561
/1-/D-UU4
ENVIRONMENTAL ASPECTS
OF CHEMICAL USE IN
WELL-DRILLING OPERATIONS
(MAY 1975, HOUSTON, TEXAS)
tf-D
\
iEN
IE PROCEEDINGS
OF TOXIC SUBSTANCES
NMENTAL PROTECTION AGENCY
4GTON, D.C. 20460
JER 1975
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Conference Proceedings
ENVIRONMENTAL ASPECTS OF CHEMICAL USE
IN
WELL-DRILLING OPERATIONS
(May 1975, Houston, Texas)
CONTRACT NO. 68-01-2928
Project Officer: Farley Fisher, Ph.D.
OFFICE OF TOXIC SUBSTANCES
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
Prepared for
OFFICE OF TOXIC SUBSTANCES
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
July 1975
CWl'.w
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Table of Contents
(* indicates speaker)
Page
21 May 1975
Opening Session 1
Welcome and Introductory Remarks 3
Farley Fisher, Ph.D., General Chairman
Session I: TECHNIQUES AND CHEMICALS USED IN WELL DRILLING 7
James L. Lummus, Session Chairman
Introductory Remarks 9
James L. Lummus
Techniques of Deep Well Drilling 11
Sam E. Loy, III
Techniques of Shallow Well Drilling 27
Robert R. Peters
Solutions for Some Problems Resulting from Refreezing of Permafrost Around a Wellbore 39
C. R. Knowles
Drilling-Fluid Principles and Operations 61
Jay P. Simpson
Well Completion-Techniques and Methods 73
Frank H. Braunlich
Panel: TOXICITY OF CHEMICAL ADDITIVES IN DRILLING MUDS
Density-Building Chemicals 103
Kenneth Grantham
Acidic Materials for Viscosity Control of Water-Base Drilling Fluids 113
John W. Hollingsworth
Panel: POTENTIAL TOXIC EFFECTS OF CHEMICAL ADDITIVES ON THE ENVIRONMENT
Effect of Drilling-Mud Additives on Plant Life 125
Raymond W. Miller, Ph.D.
in
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Table of Contents (con.) Page
Use of a Bioassay Test in Evaluating the Toxicity of Drilling-Fluid Additives On Galveston Bay Shrimp. 153
Billy G. Chesser
Acute Toxicity of Well-Drilling Muds to Rainbow Trout 169
R. H. Weir
Bactericides Used in Drilling and Completion Operations 183
T. J. Robichaux
22 May 1975
Session II: ENVIRONMENTAL IMPACT OF CHEMICALS USED IN WELL DRILLING 199
C. S. Giam, Ph.D., Session Chairman
Introductory Remarks 201
C. S. Giam, Ph.D.
Thermal Degradation of Drilling Mud Additives 203
Leroy L. Carney
Panel: CONTAMINATION AND TRANSPORT OF ADDITIVES IN GROUND WATER
Ground Water Problems Associated with Well-Drilling Additives 223
D. Craig Shew, Ph.D
Possible Contamination of Ground Waters 231
A. Gene Collins
Mobility of Well-Drilling Additives in the Ground Water System 261
Michael D. Campbell
Movement of Chemical Contaminants in Ground Water 289
Dean 0. Gregg
Toxicity and Environmental Properties of Chemicals Used in Well-Drilling Operations 311
Vladimir Zitko, Ph.D.
Potential Effects of Drilling Additives on Marine Biota 333
R. Y. George, Ph.D.
Environmental Implications of Sediment Bulk Analysis Techniques for Heavy Metals in Offshore
Well-Drilling Operations 357
Joseph G. Montalvo
Offshore Ecology Investigation 387
Joe W. Tyson
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Table of Contents (con.) Page
Effects of Drilling Operations on the Marine Environment 433
R. P. Zingula, Ph.D.
Treatment and Disposal of Waste Fluids from Onshore Drilling Sites 451
Gerald A. Specken
Toxicity of Drilling Fluids, Their Testing and Disposal 463
D. R.Shaw
Biological Effects of Geothermal Development 473
Max Katz, Ph.D.
23 May 1975
Session III: ENVIRONMENTAL IMPACT OF THE BYPRODUCTS IN WELL DRILLING 487
Pat M. Wennekens, Ph.D., Session Chairman
Introductory Remarks 489
Pat M. Wennekens, Ph.D.
The Handling and Treatment of Water-Base Drilling Muds 491
Robert B. Allred
Handling and Treatment of Oil-Base Drilling Muds 505
Warren C. McMordie, Jr., Ph.D.
Onshore Disposal of Drilling Muds 515
L. R. Louden, Ph.D.
Offshore Disposal of Drilling Fluids and Drilled Up Solids 523
William J. McGuire, Ph.D.
Environmental Effects of Drilling Muds and Cuttings 533
James P. Ray, Ph.D.
Session IV: RESPONSIBILITIES OF WELL DRILLERS 551
Albert J. Fritsch, Ph.D., Session Chairman
Introductory Remarks 553
Albert J. Fritsch, Ph.D.
Objectives of Well-Drilling Regulations 555
Jay H. Lehr, Ph.D.
Responsibilities of Offshore Drilling Regulations 571
Donald W. Solanas
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Table of Contents (con.) Page
Regulations of Offshore and Onshore Disposal 579
James E. Smith
CONFERENCE SUMMATION
Farley Fisher, Ph.D 593
COMMENTS SUBMITTED AFTER THE CONFERENCE 599
Observations and Reflections on the Conference: Environmental Aspects
of Chemical Use in Well-Drilling Operations 601
Dennis G.Wright
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21 May 1975
Opening Session
Farley Fisher, Ph.D.*
General Chairman
"Chief, Early Warning Branch, Office of Toxic Substances, Environmental Protection Agency,
Washington, D.C.
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OPENING COMMENTS
Farley Fisher
Good morning to you all. I would like to welcome you to the conference
on the Environmental Aspects of Chemical Use in Well-Drilling Operations
sponsored by the Office of Toxic Substances of the Environmental Protection
Agency, and arranged by the Research Triangle Institute for us.
I am Farley Fisher; I am chief of the Early Warning Branch of the Office
of Toxic Substances of the EPA. I would also like to introduce Mr. Frank
Ayer from RTI, the conference coordinator; he is largely responsible for the
arrangements we have here today. Mr. Ayer and Mrs. McGuffey, his assistant,
are available to assist you with any problems you may have.
In addition, before we start, I would like to introduce at least three
of your session chairmen so that you will know them. James L. Lummus, Amoco
Production Company, is going to be our session chairman today. Dr. C. S. Giam
of Texas A & M University will serve as chairman Thursday. And Dr. Albert J.
Fritsch, Center for Science in the Public Interest, will be our session chair-
man on Friday.
The purpose of this conference is to explore what is known about the
environmental effects of the techniques and chemicals used in various types
of well-drilling operations. I think that as the program develops it will
be clear that the heaviest emphasis is on drilling of oil wells, but it is not
our intention to neglect other types of wells; we will have some presenta-
tions on water wells and geothermal wells. And it certainly is not inappro-
priate for persons to raise points dealing with wells other than those—brine
wells or sulfur wells, for example.
We do want to talk somewhat about the commonality of technology, and also
about the distinctions in technology between various types of well-drilling
operations.
I hope that we have a diversity of viewpoints represented, and I hope
that everybody will feel by the time we are through that they have had an
opportunity to air their views.
It is not our intention at a meeting of this type to try to resolve any
of the issues which may come up, but rather merely to get them out in the
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open, so that they can be discussed further in private or in other fora,
with the hope that within a relatively short period of time we may decide
which are real issues and which are not, and for those that are real issues,
decide exactly what can be done to help alleviate the problem.
The topics to be covered in the conference cover a very wide range.
We are going to talk about well-drilling techniques that are used, and in
some cases techniques which are proposed for use. We are going to talk
about disposal problems with spent muds. We are going to talk about ground
water contamination, which is a real bugaboo. And we are going to talk about
regulatory attitudes, what kind of regulations exist now, and exactly what
effect they are having, good or bad, and several other items as well.
Now, one can say, "Why in the world are you looking at this problem?"
or "Why are you looking at this area? We do not think it is a problem, and,
after all, the environment is in pretty good shape. The States of Texas and
Oklahoma have not fallen into the sea yet, despite the fact that people said
they would."
The answer to that is that we are not sure things are quite as good as
we would like. You do hear stories, from time to time, about aquifers being
contaminated, about vegetation being destroyed, and various other things
which could or could not be a result of well-drilling practices.
There are some very serious problems of which we are only starting to be-
come aware in a national sense, although they have been the focus of
individuals' concerns for many years.
There is the question of ground water contamination, which is a very
serious thing, especially from the point of view that once it has occurred
there is really very little we can do to reverse it, and that there is fre-
quently a very long lag time between the event causing the contamination and
the actual appearance of the contamination.
There is the question of the disruption of marine ecosystems, which
has received up to now considerably more attention than the ground water,
and which is, once again, something we do not really understand very much
about.
So we feel that there are very real questions. We do not know what the
answers to those are and we are not pretending we know what the answers are.
We hope that what transpires here in the next 3 days will bring us a little
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closer to those answers.
People will also say, "We are in an energy crunch. The government
is supposed to be encouraging people to drill more oil wells, drill geothermal
wells, and so on. You people want a brake on this whole operation." And the
response to that, which I really consider to be a rather childish objection,
is that we are not trying to put a brake on anything. Our concern is to see
that what is done is done in as environmentally sound a manner as possible.
No matter how serious we think our current needs for oil are, they pale
when compared with our ultimate need for water. And we would be making a
very drastic mistake if we decided to trade off oil in the short term for
water in the long term. This is the kind of mistake we simply cannot afford
to make.
It might be appropriate for me to spend just a few words on what we are
not intending to -discuss here. We have designed this conference around the
operation of drilling and installing a well. It is not our intention here
to get into problems associated with accidents or improper operation of a
well. In other words, we are not going to get into the subject of oil spills
or gas ruptures, subjects which have been treated in considerable depth at
other meetings, and of which many people are well aware. In order to con-
centrate on what we came here for, I would ask that we try to avoid getting
sidetracked on matters of this type.
I am very happy to see you all here. I am looking forward to a very
profitable and educational 3 days, and I hope you are doing the same. Success
of that will depend very much on all of you feeling free to contribute what
you have to contribute to the discussion as it progresses.
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21 May 1975
Session I:
TECHNIQUES AND CHEMICALS
USED IN WELL DRILLING
James L. Lummus*
Chairman
'Special Research Group Supervisor of Drilling Fluids and Optimization, AMOCO Production
Research, Tulsa, Oklahoma.
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SESSION INTRODUCTION
James L. Lummus,
Session Chairman
I would like to welcome you to Session I, which, as Dr. Fisher
pointed out, is going to be devoted to the subject of Techniques and
Chemicals Used in Well-Drilling.
Basically Session I this morning will be a discussion on the tech-
niques of drilling, some of the various aspects of the planning and
drilling and completing of wells and of some of the chemicals that are
used in drilling fluids for this purpose.
This afternoon we will get into the toxicity of chemical additives
in drilling muds. And I think we have a very interesting program with
interesting papers.
We hope to acquaint you, the audience, and those who review the
proceedings later, with some of the aspects of drilling. We hope to
give you an insight into some of the problems encountered and some of
the techniques and methods that are used.
I would like to make a remark basically about drilling, something
that has impressed me over the years—that the drilling of a well re-
quires the expertise of a large number of people, probably a larger
number of people than most of you sitting here in the audience realize.
Today you will be hearing from people who have been involved in
drilling most of their lives and who I consider competent experts in this
field.
It takes both staff and operating type people to plan and drill a
well. The drilling methods, new equipment, and the chemicals used in
well drilling have to start with an idea, which may come from various
sources. These ideas are researched by engineers and chemists in various
company laboratories associated with the oil industry. Sometimes these
people are unsung, but the technology to go ahead and improve drilling
efficiency depends on them.
These ideas may include a new bit, or a new mud additive; they may
include a new directional tool. If they are promising, they are licensed
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to service companies which, in cooperation with oil company people and
drilling contractors, apply them in improving the efficiency of a well-
drilling operation.
At the present time in the oil industry we have drilling costs
skyrocketing. Projected costs that were made last year no longer apply.
The cost to drill a wildcat well is up anywhere from 15 to 25 to even as
high as 30 percent more than was projected. So it is becoming increasing-
ly important to do a better job of planning and drilling. And it is
becoming increasingly important to implement new ideas as quickly as
possible. We can no longer afford the luxury of biding time with the
status that we are in today.
Now, as in the case of any industry—the rubber industry, the food
industry, so forth—the communication of technology, so that it can be
used on a real-time basis, is one of our most difficult problems, and
a problem to which we, the industry, devote a considerable amount of
attention. This is evidenced by the number of technical meetings,
special training courses presented at universities, seminars, and in-
house training sessions by different companies that our industry supports.
One of the areas in which more dialogue is needed is the subject
of this conference, Environmental Aspects of Well-Drilling Operations.
Hopefully, we will be able to communicate better after today's session,
which we think will be devoted to real-life situations as far as drill-
ing wells and the possible effects on the environment are concerned.
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TECHNIQUES OF DEEP WELL DRILLING
S. E. Loy, III*
Abstract
The pressing need for new petroleum reserves makes it neces-
sary to drill to deeper and deeper horizons. The challenge of this
drilling is being met by enlarged technology, improved metallurgy,
and a growing skill in our crews. The capabilities and materials
developed involve every aspect of the drilling process. This pres-
entation will outline the planning and engineering that accompany
the drilling of a deep well, the materials used in the operation,
and the costs associated with the endeavor. Also emphasized will
be the problems of temperature and pressures which place an added
requirement on our metallurgy, drilling fluids, the well equipment
used, and tke technology of the drilling engineer.
INTRODUCTION
The drilling of deep wells is occupying a position of increased
importance with present efforts to maintain an adequate energy sup-
ply. As it becomes more and more difficult to find reserves onshore
at shallow depth, the deeper wells assume an increased significance.
The techniques used to drill the deep well are important at this con-
ference, though, not because most wells are deep, but because the
deep well represents all aspects of the drilling procedure. This
discussion will emphasize the factors that are significant in drill-
ing the deep well; in addition, others common to all wells will be
covered. The deep well, except possibly for the factor of high tem-
perature and frequently the presence of abnormal pressure, is not
basically different from the shallow well; it experiences problems
and costs which are of the same kind, but on a much more severe level.
*Drilling Operations Manager, Exxon Company, Houston, Texas.
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10,000
I
20,000
,| 30,000
40,000
Record Well Depth
USA
„,
**
1940 1950 1960 1970 1980
Source: Petroleum Engineer Intl. March 1374
Figure 1. Record well depth
in the United States.
100°
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Table 1. Examples of rig equipment
Mast: ft
Drawworks: hp
Engines: hp
Mud pumps : hp
Substructure: ft
"Small"
126
(.4 mil-
lion Ib)
600
2—325 ea.
2—375 ea.
9
"Medium"
142
(1 mil-
lion Ib)
1,400
3-700 ea.
2—1,000 ea.
20
"Largest"*
147
(2 mil-
lion Ib)
4,000
3—1,400 ea.
2—1,300 ea.
32
*0i1 and Gas Journal, Vol. 71, No. 19 (May 7, 1973), pp. 53-55.
by diesel engines. Total horsepower on the largest land rig is near
4,000 horsepower with the average rig being near 1,000 horsepower.
Examples of the basic essentials of some rigs are listed in table 1.
The variation of size and type of equipment is over a wide range as
can be seen from the table. The examples given indicate an approxi-
mate range. No two rigs are alike, most having been modified since
construction to take advantage of new equipment or to provide capa-
bility for a specific area of operations. A large rig on location
is shown in figure 3.
A drilling string used to drill at the shallower depths is shown
on figure 4. Illustrated is the conductor casing (the first string
of pipe set), the drill pipe, drill collars, and bit. The drill pipe
is used to carry the drill collars and b!. and to conduct the drill-
ing fluid to the bit. The drill collars provide rigidity and a source
of weight to the bit. The bit, of course, cuts or crushes the forma-
tion. The bit shown here is a tri-cone bit. Bit design is an impor-
tant science within itself. Designs include the drag or fishtail
bit, mill tooth bits, tungsten carbide insert bits, diamond bits, and
many variations within these designs. Each has its own special appli-
cation depending principally on the type of formation being drilled,
the cost of the drilling operation, and the depth of the well.
The casing string for a deep well is illustrated on figure 5.
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Figure 3. A large rig
on location.
DRILL COLLARS
/.V.jF^< .
^/iblh
ORilL W*flj£fa$'
Figure 4. A drilling string
used at shallower depths.
This pipe presents special problems in metallurgy. It must be strong
enough in tension to hold its own weight when lengths as long as 4 to
5 miles are hung in the well. It must be strong enough in burst
strength to stand the 10,000 to 15,000 psi which may be at the top
of a deep gas well, and it must be strong enough in collapse to
avoid crushing when formation pressures exceed internal pressures
sometimes by as much as 15,000 psi. Of course, only the very deep
wells experience these extreme conditions and then only a part of
the string on a deep well is exposed to maximum conditions. These
requirements are met by using thick well pipe and making the pipe
from very strong steel. Ordinary steel used for most construction
work and on shallow casing strings has a yield strength of about
40,000 psi. It is common for casing strings to use steels with
80,000 psi strengths, and some are made from steel having 110,000
psi yield strength. The highest strength steel used in casing to
date is V-150 steel having a minimum yield of 150,000 psi. Steels
having yield strengths as high as 135,000 psi are commonly used for
drill pipe strings for deep wells. The cost of these materials re-
quires that a high level of engineering expertise be used in the de-
sign of the string. This design is specific for the conditions of
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Figure 5. A casing string
used for a deep well.
Figure 6. A blowout preventer
stack for a deep well.
each deep well, ^n many companies, the detailed engineering calcu-
lations required are assisted by computer. The conditions to which
the string is exposed and the safety factors appropriate for the
particular type of use are programmed and the output specifies the
most economic combinations of pipe grade, wall thickness, and con-
nection type meeting the requirements.
The casing on a well is run for a number of purposes, among
them are to protect and stabilize weak formations, to avoid loss
of mud into the formation, and to protect the upper fresh water
sands from possible contamination from salt water or hydrocarbons.
On a deep well, a most important feature is the control of the forma-
tion pressures which may be encountered. The casing isolates the
pressure and serves as the connection at the surface upon which blow-
out preventers can be placed for the control of accidental flow. An
example of a blowout preventer stack for a deep well is shown on
figure 6.
Blowout preventers are designed to be set on top of a casing
string and shut off unwanted flow from the well. Two main types
of preventers, the annular and the ram type, are used on a deep
well. The number and arrangement of blowout preventers in the
stack depends on the type and location of the well to be drilled.
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Most deep wells will have one annular and two or more ram type pre-
venters. The annular is designed to be closed pressure tight around
pipe, irregular objects such as a kelly, wireline, or on an open
void. The closing element is a thick annular spool of special rub-
ber. The ram preventers are sized to close piston driven seals
(rams) around the drill pipe being used. There is also a blind
ram to close on an open void. One separate ram preventer must be
used for each size pipe.
It is not sufficient just to close-in the well on preventers,
the influx of fluid must be circulated out, the well placed under
control--probably by using heavier mud--and drilling resumed. To
do this requires special connections on the preventer stack, remote
or manually operated chokes to hold back pressure while circulating
a heavier mud to control the well, and a separator and flare system
to handle any gas or oil circulated from the well. The engineering
fundamentals of the well control operation are given careful atten-
tion by each drilling contractor and operating company. It is es-
sentia that their personnel be ready to take prompt and correct
action so unexpected well pressure can be handled safely and without
excessive expenditure.
There is always the possibility of the unexpected in any human
operation, whether it is flying a jet airliner or drilling a well.
In the event of a blowout, there is risk of contamination to the im-
mediate environment. Industry continues to train its personnel and
to develop its equipment to reduce this risk to a minimum. This will
always be the case, for in addition to our public responsibility,
the safety of our personnel and the cost of the drilling operation
causes the elimination of blowouts to be a continuing prime objective
in drilling technology.
The primary components of a drilling rig have been mentioned
above. There is a large amount of additional equipment without which
wells could not be drilled. Among these are the other components of
the rig such as electric generators, shale shakers, mud tanks, degas-
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sers, desanders, desilters, auxiliary pumps, and sometimes centri-
fuges, power swivels, wireline units, and automatic control equip-
ment. The equipment is selected according to the type of drilling
problems expected.
DRILLING FLUIDS
The drilling fluid performs a number of essential functions on
a well. Among the most important are the cooling of the bit, lifting
drill cuttings to surface, maintaining sufficient pressure to hold
back flow from the formations penetrated, and sealing the hole so mud
or mud filtrate will not flow in significant amounts into the forma-
tion. To satisfy all these requirements, the mud must be compounded
so as to have chemical and physical properties which can be carefully
controlled to meet the varied and changing subsurface conditions.
The science of drilling fluid control has developed to a high degree,
and its application on-site is essential to the success of a well.
This is particularly true of the deep well. There the high tempera-
tures of the deep formations cause the chemicals from which the mud
is compounded to react with one another or degrade at such a rate
that many of the more common materials cannot be used in the deep
well.
The temperature found at depth by a drilling well varies depend-
ing upon locality. The deepest well drilled to date had an estimated
formation temperature of 475°F at the total depth of 31,441 feet.
The highest temperature recorded in a well to date is 555°F. This
well, in Southwest Texas, would have a calculated formation tempera-
ture of 590°F at 23,837 feet. Most wells have downhole temperatures
much lower than these record values. The usual temperatures experi-
enced are illustrated on figure 7. The gradient of 1.3°F per 100
feet is in the low range, whereas 2.2°F is near the upper limit under
ordinary conditions. It will be noticed the temperature range for
wells at average drilling depths is around 150°F.
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700
600
JL.
-500
1 300
-200
100
Formation Temperatures
10,000 20,000
Depth: Feet
30,000
Figure 7. Formation
temperatures.
Basically there are two differing types of drilling fluids:
water base and oil base. Each is composed of a liquid carrying a
suspending agent and a weighting agent. To these are added materi-
als to control the flow properties of the mud and to reduce filtra-
tion into the formation. In most instances, a number of other prop-
erties such as electrolytic composition, pH, reserve alkalinity,
emulsion stability, and tolerance to contamination are important.
Each of these properties is important in the shallow well but a
great deal more important in the deep well.
The most commonly used drilling fluids are water-base fluids.
Early drilling muds were simply native clays dispersed into water.
As wells got deeper and the importance of pressure control and hole
cleaning became better understood, special clays such as bentonite
were used, and chemicals were added to control the viscosity, or
filtration rate. Also weighting agents were developed. The early
viscosity control agents included tannins from quebracho and sodium
phosphates. Filtration was controlled by the bentonitic clays and
by starch. Weight was controlled by natural solids build-up and by
the addition of inert materials, primarily barite--a natural mineral
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grade barium sulfate. With the exception of the barite, all these
materials are susceptible to reaction and chemical change at the
higher temperatures in a deep well. Though these materials are
still satisfactory in shallow wells when wells are drilled deeper
and temperatures approach 150°-250°F, new materials are needed.
The next generation of materials was designed for roughly 200° to
300°F. Here, organic polymers such as carboxy methyl cellulose or
polyacrylates are used for filter loss, and modified lignosulfonates
for viscosity control. These materials are economic and perform
satisfactorily to somewhere near 300°F. Past 300°F, few materials
are satisfactory. Lignites are used in combination with lignosul-
fonates for want of the ideal material. Oil muds, discussed below,
also find extensive use at the high temperatures.
Drilling fluids compounded from oil have been used successfully
by the industry for many years. Besides the application in the deep
wells at high temperature mentioned above, their use is important in
some areas to reduce the adverse affects of water upon those produc-
tive formations which can be damaged by contact with a water-base
filtrate. This was probably their first use. This application is
still important, but added to it is its present application in main-
taining a stable hole through formations likely to cave or slough
when contacted by water and the one mentioned above—that of maintain-
ing a mud system satisfactorily tolerant to very high temperatures.
Also the oil phase mud has found wide use in avoiding stuck pipe in
difficult holes or as spotting fluid for freeing pipe once it has
become stuck. These uses make oil muds important to everyday drill-
ing, and extremely important to deep drilling.
The composition of oil muds vary over almost as wide a range as
do water base muds. Generally they have a composition whose compo-
nents perform in the oil carrier the same functions that are performed
by their counterparts in a water base composition. Oil muds are to
be reviewed in detail in a discussion to follow. A very brief list
of their components would include bentone clays, asphalts, electro-
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lytes, water (in emulsion), and organic agents designed to thin the
composition or stabilize the emulsion.
ABNORMAL PRESSURE
The technology of drilling the deep well has been covered to a
degree during mention of metallurgy, equipment, and drilling fluids.
However, there is one special subject which bears discussion. This
is the detection and control of abnormal pressure.
Normal pressure is defined as the subsurface pressure resulting
from the column of water naturally present in the formations from the
surface to a specific depth. This water is usually salt water, but
it can be fresh. Abnormal pressure then would be pressure in excess
of this value.
Abnormal pressure does not occur at all in some areas. In areas
where it does occur, it is erratic so one can speak only in trends.
The following examples are given as illustrations. In Central Missis-
sippi, abnormal pressure occasionally is found somewhere below 20,000
feet. Inshore along the Texas and Louisiana Gulf Coast, it often
occurs at between 9,000 and 11,000 feet. Offshore in the Gulf of
Mexico, the point of abnormal pressure occurrence becomes shallower
as one goes away from the coast with abnormal pressure occurring as
shallow as 4,000 or 5,000 feet in the deep water some distance off-
shore. In other areas of the country, its occurrence is likewise
spotty.
The detection and proper handling of abnormal pressure is essen-
tial for the successful drilling of any deep well. First, the mud
weight and casing program for the well is planned to provide mud
weight and/or casing at the proper depth to control the formation
pressures. The casing cannot be set arbitrarily early because the
formations higher up the hole will break down and cause loss of drill-
ing mud as higher mud weights are required to control higher formation
pressures. On the other hand, if an attempt is made to set casing too
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Table 2. Abnormal pressure indicators
A. Increased: Drilling rate
Mud gas
Mud chlorides
Mud temperatures
B. Decreased: Sonic velocity
Shale resistivity
Shale density
C. Appearance of shale
D. Micro fauna in shale
deep, then the well may "kick" because the mud weight is too light
to hold back the formation pressure. The well will still be con-
trolled by blowout preventers, but their use should be reserved
only for emergencies. The proper placing of each string of casing
in an abnormal pressure well then is critical and must be tailored
to the actual downhole conditions.
Abnormal pressure can be predicted before a well is drilled
through use of seismic data and by knowledge from previous wells.
As the well is being drilled, there are a number of important in-
dicators which are used to detect imminent abnormal pressure occur-
rence. Table 2 illustrates these indicators. Among the more common
ones are sudden increase in drilling rate, increased gas in mud, in-
creased chlorides in mud, increased mud temperatures, decreased den-
sity of shale cuttings, reduced electrical resistivity of shales, re-
duced sonic velocity of shale intervals, and the physical appearance
of the cuttings. Also the micro fauna contained in the shale cuttings
is used as an indicator. These techniques are under continued research
and development. An important part of the job of drilling personnel is
to work with their improvement and application. An example mud
weight and casing program for an abnormal pressure well is shown on
figure 8. These casing and liner strings are costly and cannot be
21
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Iran ttion
Abnormal
Abnormal Pressure Well
Pressure Casing Mud Wt.
Normal
7"
TD
9.0
10.0
11.6
12.8
15.5
16.8
18.0
Figure 8. Abnormal
pressure well.
run arbitrarily; but often, even more critical, there is a limit on
how many can be run because each must have a smaller diameter than
the previous one used. A well can simply run out of room to set
another string of casing if the planning and execution is in error.
The deep, abnormal pressure well can be drilled successfully.
The plans that go into such a well are much more detailed than those
for the average well, and the application of proper technology assumes
critical importance; but the job can be done. The industry will con-
tinue to improve its techniques and meet this challenge.
CONCLUSIONS
1. Our search for new energy will require the industry to continue
the trend toward drilling deeper wells.
2. The drilling equipment increases in size and technological com-
plexity as wells are drilled deeper.
3. The challenge of drilling the deep well is being met by industry
technology.
DISCUSSION
MR. RICHARD S. SCALAN (University of Texas, Port Aransas, Texas):
You mentioned use of cement casings, and so on. Is there
22
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something in drilling wells, in general—in deep wells in partic-
ular—perhaps additives, that might be in the cement, that might
be of concern in the protection of the environment?
MR. LOY: Cement is, of course, used in a manner such that the formation
is subjected primarily to filtrate, which is basically just water.
And certainly there are some retarding agents that might go with
the water to penetrate the formation to a very limited extent.
But the penetration of this water filtrate into the formation is
just a matter of a few inches, since not very much of it is placed
around the casing. So its impact within the boreholes would be
very minor if significant at all.
As far as the additives that go into the cement possibly
being of concern, I really cannot answer. Maybe somebody here
can. I do not think there is anything basically harmful.
Now, certainly, cement has been used in the construction
industry for many years. The type of cement that we are using
to cement the conductor and surface casing strings is not basic-
ally different from that which has been used in the industry.
Any excess cement that is circulated out is generally dis-
posed of such that it is not a deterrent to life.
DR. PAT M. WENNEKENS (Alaska Department of Fish and Game, Anchorage,
Alaska): There seems to be a trend in your graph showing so-
called abnormal pressure as you go further offshore. As you
go more toward the continental slope, do you expect these
trends to proceed the same way? Also, do you have any comments
on what was observed during some of the deep drilling done by
the Glomar Challenger in the Gulf of Mexico, in terms of unusual
pressures when they went to the deeper water depths?
MR. LOY: I can answer the second question first. I am not really ac-
quainted with what the Challenger encountered, but I am acquainted
with the limited information we have of deep water in the Gulf of
Mexico as well as of the shallow water. I can say that it would
appear that maybe there could be some trend to having abnormal
23
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pressure occurrence at a shallower depth as you get into deeper
water in the Gulf of Mexico. The occurrence of abnormal pressure
is spotty and erratic, as I mentioned in my talk here, you can
only speak in trends. You would have to know a particular area
to isolate where abnormal pressure might be encountered in that
area.
CHAIRMAN LUMMUS: You might add, the more shallow it is, the more
dangerous it is for well drilling.
MR. LOY: That is true. Of course, the shallower this abnormal pres-
sure occurs, the more you are limited on the hydrostatic head of
the drilling mud that can be placed.
DR. WENNEKENS: Some hydrocarbons were shown Sigsbee deep in the Gulf,
and I was wondering if there was any evidence of a pressure prob-
lem in those readings. Can anybody in the audience comment on
that?
MR. WILLIAM DOLLINGER (Sherwin-Wi11 Jams Company, Houston, Texas):
We are concerned with chemical use in well-drilling operations.
In your slides you showed emulsifiers, and you showed surfactants.
You did not mention corrosion inhibitors. I wonder if that was
intentional or otherwise?
MR. LOY: No, it was not intentional. I could have mentioned a lot of
control inhibitors, and they certainly can be a vital part of the
drilling fluid, depending on the conditions which you encounter.
CHAIRMAN LUMMUS: I think Sam was tripping around a little bit because
he did not want to say everything that Jay Simpson is going to
say later about drilling fluids and what Mr. Braunlich is going
to say about completion and other techniques later on. It was
just kind of an outline of the drilling operations. We are going
to discuss some of the more specific chemicals a little later on.
MR. JAMES W. WINFREY (Petroleum Consultant, Houston, Texas): Sam,
I think it would be worthwhile for you to say a little bit about
the problem of lost returns. You did not say why you set this
intermediate string of casing. Some of these people may not
24
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understand it. That is a part of the drilling technology.
MR. LOY: I did mention it, but I did go rather rapidly.
The intermediate casing string is used to protect the weaker
formations. As you go deeper, you need to carry heavier mud
weights. Of course, the shallower formations tend to break down
and you tend to lose circulation, as we term it, or lose the
drilling fluid into the formation. That is the reason for the
intermediate casing string.
The big problem in drilling deep wells is that you tend
to run out of casing strings. If you are drilling rather deep,
you will have to start with a large size of casing in order to
have enough string to reach your objective, because you have
weaker' zones that you have got to protect—first of all, shallow
water, fresh water. You need to protect the weaker zones from
breaking down. And then, of course, you want to keep abnormal
pressure fluid from coming into the well. Then you may even
have a reversion back to normal pressure below that and have
to set another string to get to the objective. This is one
of the tremendous costs that go into deep well drilling.
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TECHNIQUES OF SHALLOW WELL DRILLING
Robert R. Peters, P.E.*
Abstract
The various methods of drilling for the construction of water wells
began with the cable tool machine and since have advanced up to rotary,
reverse circulation, and air drilling. The very beginning of water well
drilling by the utilization of cable tool machines dates back to approxi-
mately 600 B.C. Since then many innovations have been incorporated. The
orderly development of ground water is a major responsibility of water
supply contractors. It is necessary that construction be such that this
vast resource not be destroyed. In recent years, we have found that
increased sophistication and methods of construction present problems to
the environment. The disposal of construction clays and/or chemicals
utilized in the development of water supplies is presenting increased
problems. The methods and/or disposal sites will require careful
investigation.
The various major methods of drilling are the cable tool, standard
mud rotary, reverse circulation, and air drilling.
The cable tool, or percussion method, is the oldest system in
history and dates back to the first recorded wells drilled by this
method in China, about 600 B.C. These early wells were drilled a few
hundred feet deep. By A.D. 1500, holes were being drilled to depths
of 2,000 feet. After the completion of the Drake oil well in 1859, many
advances were made in this method of drilling. It today is used in many
instances of hard rock, or cavernous drilling, but it is a rather slow
*
Robert R. Peters is with the Layne Atlantic Company, Singer-
Water Resources Division; President, National Water Well Association,
P.O. Box 7095, Norfolk, Virginia 23509.
27
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method whereby a string of tools are lifted and dropped to break up
the formation. The tools then are removed and a bailer installed
to bring the cuttings out of the well. In unconsolidated formations,
it is necessary to drive pipe as the drilling progresses. In some
instances, water and muds have to be added in order to get the cut-
tings out of the hole.
The early history of rotary drilling indicates that it was used
by the early Egyptians quarrying stone for the pyramids. The earliest
use of the method of rotary drilling as practiced today, using hollow
drill rods and circulating fluids to remove the cuttings, was by an
English patent issued to Robert Beart in 1844. Since that time many
additional patents have been issued for various methods of rotary
drilling. However, the rotary method became commonplace after 1901
when Captain Lucas drilled the spindle-top discovery well near
Beaumont, Texas, using rotary tools. Today, approximately 90 percent
of the wells are drilled using this method or some combination there-
of, depending upon the formations encountered.
As to the use of drilling fluids to increase viscosity, the
first step, especially in the water well business, was to locate the
local clay banks whereby native clays were used to prevent circulation
loss, keep the bit cool, and remove the cuttings from the hole. Today
our methods and fluids used are much more sophisticated, and we have
the ability not only to control the weight of the fluid, but its
viscosity and sand content. Today a mud engineer is available on
large wells to be certain that the fluid is kept in proper condition
at all times. In the water well business this service is limited and
is normally performed by the driller on site, using tools or apparatus
such as marsh funnel, sand content indicators, and pH paper together
with mud-weighing equipment.
We, in some circumstances, utilize various clays such as bentonites,
native clays, starches, and gum products. The greatest number of our
wells drilled in alluvial materials are done by the utilization of ben-
tonite fluids. We do, however, in conditions of drilling into salt
28
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water formations, use starch products. Gum products, which are bio-
degradeable, are also used for formation drillings. In other words, the
well is made down to the top of the formations, and a changeover to gum
products for the purpose of cutting the formation is used. This material
has a time life and, unless expelled, degrades itself biologically. It
has, upon occasion, generated some problems with bacteria being produced
from the well after development. This normally is controlled by chlorina-
tion to eliminate this problem.
We are required, under some circumstances, to use various weighting
agents due to higher formation pressures. However, it is our normal
procedure to maintain as low a mud-weight-to-water ratio as possible.
In the development of formations with low static water levels, the
higher mud weights create considerable pressure on the face of the for-
mation and cause deeper mud penetration, which is a problem in the
development of the well itself. The method of reverse circulation
drilling is the opposite of straight rotary whereby the cuttings are
brought back up the drill pipe rather than floating up the bore hole.
This allows much reduced mud use due to a constant velocity maintained
inside the drill pipe. It is employed at times with combination machines
that are capable of both straight mud rotary and/or reverse circulation
drilling. It is limited in depth capabilities due to friction loss in
pipe. This capability bas been increased in recent years due to the
addition of air lift principles to bring out the fluids.
The air rotary method using a hammer is very effective in the
drilling of hard rock formations. It is practically replacing the cable
tool machine due to its very rapid rate of penetration. Air is pumped
through the drill pipe down to the bottom where a percussion hammer is
operated, breaking up the formation by the rapid reciprocating movement
of the bit. Foam is sometimes used with this method to increase this
capability.
Let us look first at a deep water system design and see what has
to be done to build an economical and practical well water supply. Many
areas of our country are blessed with excellent quality subsurface water
29
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at relatively shallow depths. This makes it easy to build a system if
a good water supply contractor is available in the area. He would
normally be contacted by an engineering firm or municipality and asked
to assist in the writing of specifications, or to negotiate directly.
Here is where the major responsibility begins and must be assumed. We
can and must accept this responsibility if our industry is to survive
and prosper. This most probably will be challenged, as our industry
has survived many centuries; however, we must continue to improve and
move enthusiastically into the 21st century. Self-policing and proper
direction will enable our industry to gain the respect and confidence
it so rightly deserves. If we do not police ourselves, someone else
will do it for us. An example of this is the recent water laws being
enacted in many States, together with sometimes stringent requirements
for well permits. More and more regulations will be enacted, and
therefore we must play an important part in seeing that these rules
and regulations are properly drafted.
In order to properly put into perspective the advantages and
economics of a ground water system, it is important to know something
about surface water supplies and their respective advantages and dis-
advantages. We should be in a position to point these out in our dis-
cussions with our customers. It also is imperative that we carefully
explain how and where ground water occurs, remembering that it being
out of sight automatically causes it to be shrouded in mystery. How-
ever, there is no great mystery about ground water, only superstition
caused by lack of knowledge of the unknown. We in this field are
blessed with the ability to understand its occurrence. Our role then
is to convey this understanding to our customers and not allow unquali-
fied people to continue in the furtherance of superstition and false
information.
Whether called in by the municipality either through their engineers
or by our own investigation, the responsibility of developing the very
best system that is practical is our goal and duty. Here is where we
must display our best professionalism. If we are working with systems
30
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which have been in existence for considerable time and this is only
an extension, then our role is to see that the original design, if
proper, is continued and nothing is done to alter or reduce the depend-
ability of such a system. This is where careful investigation of the
original system is important. We would locate on a map the site of
each well, check the distance that wells are apart, and check whether
we are beginning to box in the wells that are causing excessive draw-
down. This, as you know, costs the customer many extra dollars due to
pumping costs.
Be informed on new developments in the area. Check with the U.S.
Geological Survey and State Water Agencies as to investigations and
recent reports. Water levels from past records should be compared
with records of recent investigations. If during these preliminary
investigations you find data which indicate potential problems, this
is where you should recommend that a professional ground water consul-
tant be called to evaluate and confirm your data. Many ground water
systems have just grown and lacked proper planning for the future.
This, when very little water was being taken from an area, caused no
apparent problems. However, if our resource is to be developed to its
potential, we must use all the tools available in order that we do not
destroy an aquifer for future use.
Are we developing the best quality water that a given area has
available? Here is where preliminary research should be conducted, and
if it is not available, a testing program should be initiated to secure
this information. The best quality water available should be developed
for the customer. Only when these things are done on each and every
job are we ground water developers. This is the way to prevent the loss
of a ground water customer to a surface supply.
Old systems for many reasons have been improperly designed and
developed. There is no excuse in today's modern technological world,
with the knowledge and equipment that we possess, for improper design
and development. Let us carefully evaluate our position and begin the
development of a complete new water system. In the beginning, all of
our preliminary work is the guiding of design criteria in the advantages
of using a ground water system. This sounds relatively simple, however,
31
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being able to look out on a vast reservoir or lake with its esthetic
values has considerable appeal to many water users. The vast water
treatment plant required for these systems is quite a monument to the
engineers or city fathers for many years to come. The potential
recreational opportunities sometimes afforded are also a selling point.
The well with its accompanying pump head and electric motor sitting
on top is a small item and yet is the only visible sign of considerable
money that has been spent.
Now what do we have for our ground water system? This really is
rather basic, but has quite an appeal, and that is economics. The cost
of surface versus ground water is on the order of 15 cents versus 5
cents to produce. The original capital investment of a surface versus
a ground water system can be on the order of ten to one. Step number
one will cause most to listen. Next is dependability, and here is where
we meet the test. This is where we must be able to sell the unseen.
This also is where we fight such quotes as "The well has gone dry,"
"vein of water," and "water witching."
Many major industries and cities such as Berlin, Paris, Memphis,
and Houston depend upon or are largely supplemented by ground water
supplies. Understanding the basic hydrological cycle tells us that
ground water has been and will continue to be a vast resource of fresh
water for our future needs. Our problem then is to unveil its secrecy
and to convince the customer that the dependability of deep water is as
good as or better than a surface supply. We have practically eliminated
the evapotranspiration problems and have a source protected from contami-
nation, this only being as long as we use proper techniques and design.
In many instances the quality is such that we can pump directly from the
well into the mains. A well equipped with vertical turbine pump and
electric motor producing one million gallons per day is a far cry from
a pumping station and treatment plant of the same capacity.
If we are requested to assist in the development of a ground water
supply, what now is our responsibility and role? Our first job would
be to present the customer with all of the available information that we
have on the area. This could very well be a supplement to a surface
32
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water supply, due to limited production from a surface area. Existing
records of nearby wells which would give information to effectively
produce a dependable water supply would be analyzed. State agencies
and the Geological Survey would be contacted for data on wells in the
area. Sometimes it may be necessary to extend and cross-section this
data with information from areas on either side. It is very probable
that some wells have been developed and information is available as to
the quality of ground water in the area. This would certainly be the
type of information that we would want to present to the engineer or
customer. From these records, we would also be able to partially deter-
mine the availability of the ground water supply and whether or not it
could be pumped to the capacity requested. If treatment was necessary
in outlying areas, it very possibly would be necesary in the area of
investigation. Some assumption would have to be made as to the produc-
tion of a particular unit and also a general idea of spacing, depending
upon information from other nearby sources. Once this basic information
was available, a potential well design could be drafted. This would
allow for certain sizes of casing due to the pumping capabilities of the
aquifer and also water levels and thickness of formations. It would be
at this point that a recommended test program should be employed to
actually determine the productive capabilities of the aquifers, also the
aquifers that would be eliminated due to the quality of the water and
the formation productivity. We certainly would want to produce for the
customer the best quality of water available in the area. This would
reduce his cost and also eliminate maintenance for the future.
Assumptions would have to be made as to potential yields; however,
upon drilling the test hole and securing this data, a test well would
be installed to collect hydraulic information on the aquifer. It may
be necessary to put in several observation holes and conduct pumping
tests to ascertain this information. Once this data was secured, it
would then be a matter of designing a system to give the customer a
safe and dependable water supply for the future. It should be pointed
out very carefully that the well design and construction must be such
to give a safe and dependable supply for the future, to protect for
33
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the future, to protect for the lowering of water levels, and to posi-
tively prevent the contamination of the aquifer that we are developing.
All systems should have surface casing sealed and cemented to the top
of the water-bearing aquifer. This would be done by pressure cementing
and is the finest insurance that the customer could have. The drilling
contractor that fails in this endeavor is not only destroying the aqui-
fer as a productive source, but when this is done, has destroyed him-
self by having no resource to develop. It is the duty and responsi-
bility of the well-drilling contractor to design a well to be the most
economical and not necessarily the cheapest.
Many ground water customers have been lost to surface water sup-
plies due to poorly designed and improperly constructed wells. This
also is where engineers have been put in a position of embarrassment
because of water supply contractors using improper methods and materials
Their failures in this endeavor have caused engineers to be very skepti-
cal about recommending ground water supplies in the future,, We should
never allow ourselves to be talked into any design that we feel is not
safe and adequate. It is quite possible at this point that we would
acquire a customer, but this would be a short-term loan, and the penal-
ties would be great indeed. Casing size and thickness should always be
ample to allow easy installation of pumping equipment and not having
casing failures because of improper wall thickness. Screens, if used,
should be of corrosion-resistant material that will enable long and
dependable service. Means of access into the wells should be provided
that will allow water level measurements and other investigations
which would be conducted in the future. It must be emphasized that
all well designs should be to safe yields and not beyond. We should
not cause excessively low water levels because of overpumping a parti-
cular well. Well experience and hydraulics should be given careful
consideration at this point. Excessively low water levels generate
many rumors; if these can be averted, they should be. However, impro-
per design of many small systems will trigger problems, because of
large municipal and/or industrial developments in an area. Wells that
have this problem are usually designed prior to any large ground water
34
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withdrawals in an area. Here again is where the water supply contrac-
tor has to explain what is happening in an area. This sometimes is
very hard to do when an individual has lost a sizable investment be-
cause of improper design. In the future, we must prevent this from
happening.
We should offer to the customer all the advantages of our tech-
nological research and skill. This means that all new techniques
should be applied to each and every job. There are many instances
when specialized problems are involved, and this is where they should
receive specialized treatment. A few of these to receive consideration
and mention would be programs such as electric analog and digital com-
puters; these techniques are extremely valuable in analyzing such
problems as excessive low water levels, possible salt water encroach-
ment, and such things as water quality change. Pumping water from any
area causes flow net changes, and if an area should have undesirable
waters that are affected by a particular flow net, this water could be
moved into our area of pumpage. This type of investigation is also
extremely valuable when the area of pumping would be subjected to pos-
sible salt water intrusion or encroachment. These are the things that
can be forecast ahead of time by the use of electric analogs and other
tools of this nature.
Development of large capacity wells begins with the drilling of a
pilot hole to the full expected depth of the well. Previous data in
the area would give us information as to what this depth would be. Sam-
ples are taken at approximately every 10 feet and at each change in for-
mation. These samples are analyzed and sieve analysis run to determine
screen size and/or gravel size, if same is to be utilized. We then
would proceed with conducting geophysical logs, obtaining resistivity
self-potential, gamma, etc., to ascertain exact locations of screens
to be set opposite water-bearing formations. These data, together with
information on other wells in the area, would enable us to design the
permanent construction of the well. If, however, water quality is a
factor, it may be necessary to build miniature wells and actually pump
formation samples for analysis. The final design of the well having
35
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been ascertained, we then would proceed to cut a large diameter hole
to receive the surface casing. This casing would normally be set to
the top of the water-bearing formation or formations to be developed.
A cememting procedure would then be conducted to fill the annular
space between the casing and the bore hole completely back to the
surface. After the cement has set, a hole of approximately the in-
side diameter of the surface casing would be drilled to the bottom
of the water-bearing formation. It may be necessary now to enlarge
this hole by the use of underreaming tools to a much larger diameter.
Careful mud control at this point is very important. The screen line
itself is then installed, together with connecting lengths of pipe to
either extend up inside the surface casing a depth of approximately
50 feet or return completely to the surface. If a lap joint is made
up into the surface casing, a method of backing off by the use of
right/left couplings would be employed and screen line normally would
be hung with the use of the drill pipe.
If the large diameter well method is employed, a conductor pipe
for the purpose of pumping gravel would be used to fill the annulars
between the screen line and the formation's face. This area is com-
pletely filled and the gravel is extended up inside the surface casing
a previously determined amount or brought completely to the surface.
When this gravelling operation is completed, the well would normally
be flushed with clear water and developed (see figure 1).
The development method would vary, depending upon several circum-
stances. There are times when air pumping and swabbing would be em-
ployed as in the construction of multiple screen wells. The develop-
ment at times presents problems due to formations of higher perme-
ability developing faster with the lower permeability formations
pumping little or no water. Once the development of the well is com-
plete, a test pump is installed to ascertain the production capacity
of the aquifer. Once basic preliminary water levels are established,
a pumping test would be conducted to ascertain the production capability,
transmissivity, and area of influence of this particular well, or, in
the case of several, the well field itself.
36
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Figure 1. Cross section showing superiority of a Layne under-
reamed gravel-wall well with casing cemented, over an ordinary
gravelled or ungravelled well with casing uncetnented.
37
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We have found in recent years a considerable increase in the
sophistication and techniques of developing large production water
supplies that are dependable over many years. We have encountered
considerable difficulty at times due to a lack of knowledge of our
business in the normal engineering profession. It is a lot easier
for an engineer to look at a lake and see a water supply than it is
for him to ingest in his mind the potential of underground aquifers.
We are also having problems at the present time with the possi-
ble contamination of some very prolific aquifers due to poor construc-
tion methods which cause leakage, and/or to improperly constructed
injection wells. From an environmental standpoint, one recent example
is a situation that occurred on one of our jobs presently under con-
struction whereby we were told and on the plans were shown the area
for the disposal of the water from the well. Our normal assumption
would be that this included dirty water, being mud, and clean water
from the final test pumping. We would expect drill cuttings as such
collected in the pit would have to be removed and disposed of elsewhere.
We found, however, that we were not going to be allowed to put the
water in a small drainage stream on one site and a storm sewer on
another due to the fact that the water contained considerable turbid-
ity. This problem has been resolved at the present time by pumping
this fluid to a sanitary sewer approximately 1,200 feet from the dril-
ling site. It was pointed out to us that it was our responsibility
to dispose of this fluid. Our reply was, "Where?" No one had an
answer except that it was our responsibility. Fortunately we were
working for a governmental agency which in turn was dealing with a
governmental agency. Had this been private enterprise, we probably
would still be trying to resolve the problem. We must immediately
take the necessary steps that allow us to face this problem before a
contract is signed, not after.
38
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SOLUTIONS FOR SOME PROBLEMS RESULTING FROM
REFREEZING OF PERMAFROST AROUND A WELLBORE*
T. K. Perkins, G. R. Wooley,
and F. W. Ng
Presented by C. R. Knowlest
Abstract
New well completion technology has been developed to deal with
problems unique to Arctic permafrost areas. During drilling, com-
pletion, and production, some thawing of permafrost around the well-
bore occurs. If wells are not produced immediately after completiont
or if production is interrupted at a later time, the thawed region
around the wellbore will begin to re freeze.
Re freezing of the permafrost can lead to two types of problems.
First, as water in the thawed region is converted to ice, its volume
increases. This results in high fluid pressures which are imposed
on the outer casing. Full-scale field tests, extensive laboratory
measurements of the mechanical and thermal behavior of permafrost,
and theoretical and computer studies have led to an understanding
of these pressures. External refreezing pressures calculated for
normal operating conditions are in a range that can be tolerated if
the proper casing is selected.
A second potential problem is the refreezing of fluid within
the Wellbore system itself. If freezable fluids are left in annuli
during the completion process, the possibility of high internal pres-
sure exists. Because of the low pipe expansibility, pressures can
rise to values which will cause collapse of inner strings or burst
of outer strings. There are several practical approaches to avoid-
ing this potential problem. This paper describes a unique displace-
ment process which has been used to replace freezable fluids with
nonfreezable, thermally insulating casing fluid.
*This paper was presented as API Paper No. 364-A, at the 1975
Annual Meeting, Division of Production, American Petroleum Institute,
Fairmont Hotel, Dallas, Texas, April 7-9, 1975.
•(-District Drilling Engineer, Atlantic Richfield Company, Pro-
duction Research Center, Piano, Texas.
39
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INTRODUCTION
The discovery of oil in arctic areas has led to significant
changes in drilling and we11-completion practices. The harsh winter
environment has necessitated substantial changes in surface opera-
tions. In a less obvious way, subfreezing temperatures have also
created subsurface problems of considerable significance. The sub-
surface problems considered in this paper result from the interaction
of permafrost with the well bore.
Permafrost of various thicknesses occurs in Arctic regions where
commercially significant hydrocarbon reserves may be found. Many
wells have now been drilled and completed on the Alaskan North Slope
where approximately 2,000 feet of permafrost are encountered. Even
thicker permafrost has been reported in Russian technical literature.
During the drilling and well-completion operation, some thawing of the
permafrost is caused by the drilling mud which brings heat up from the
earth below the permafrost horizon. Drilling can typically result in
a thawed region of a few feet in radius. Production of hot oil for a
long period of time can lead to thaw radii of several tens of feet
(refs. 1,2,3), the exact value depending on the operating conditions
and the degree of well bore insulation provided in the permafrost re-
gion. If the wells are not produced immediately after completion, or
if production is interrupted at a later time, the thawed region around
the well bore will begin to refreeze.
Refreezing of the permafrost can lead to two types of problems.
First, as water in the thawed region is converted to ice, its volume
increases. The increasing volume leads to an increase in fluid pres-
sure which is imposed on the outer casing. The wellbore must be designed
to withstand these "freezeback" pressures.
A second potential problem is the refreezing of fluid within the
well bore system itself. If freezable fluids are left in the annuli
during the completion process, the possibility of high internal pres-
sures exists due to the volume increase accompanying freezing. Be-
40
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cause of low pipe expansibility, pressures can rise to values which
will cause collapse of inner strings.
This paper describes some practical solutions to these two poten-
tial problems.
EXTERNAL FREEZEBACK
Consider first the external freezeback pressures. As the perma-
frost region around a wellbore is heated, ice in the soil pore space
thaws and its volume is thereby reduced approximately 9 percent. A
pressure decline resulting from the volume decrease tends to be limited
by gas expansion or influx of fluid such as drilling fluid filtrate,
water from a thawed region near the surface or below the permafrost,
laterally flowing brine, and gravity flow from thawed sections above.
Permafrost refreezes most rapidly near the surface; hence, excess
water may be trapped when deeper thawed regions refreeze. Upon re-
freezing, the water in the pore space expands, thus tending to increase
the pore pressure. The increased pressure may simply force fluid to
flow to another region. However, if this is not possible, the pressure
continues to rise until the soil or well casing deflects or yields suf-
ficiently to accommodate the excess volume.
Freezeback pressures have been studied in full-scale field tests
at Prudhoe Bay (ref. 4). Two wells were drilled and completed through
permafrost to investigate thawing and refreezing phenomena. Thermistors
and pressure transducers were attached to cables which were external to
the casing. Thawing was accomplished by circulating hot fluid in the
wellbore. During the thawing and subsequent refreezing cycles, temper-
atures and pressures were recorded at the surface.
The Drill Site 4-6 was spudded February 14, 1972. A 20-inch con-
ductor pipe was set at 109 feet RKB, and a 17-1/2-inch hole was drilled
to 2,700 feet with fresh water mud. A 13-3/8-inch, 72 Ib, N-80 modified
buttress casing, with external instrument cables was run to a depth of
2,191 feet. The first stage of cement was 700 sacks of Permafrost II
41
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with the top identified at 1,580 feet with a cement bond log. The
second stage was cemented with 400 sacks through a DV tool at 486
feet. The 20-inch by 13-3/8-inch annulus was displaced with an oil-
base casing pack, and the well was completed with open-ended 3-1/2-
inch 9.2 Ib, N-80 buttress threaded tubing hung at 2,044 feet.
The second well, Drill Site 1-6, was spudded May 27, 1972. An
18-1/2-inch hole was drilled with oil-base mud to 2,750 feet. The
well was completed with 20-inch conductor set at 107 feet, 13-3/8-inch
landed at 2,698 feet, and 3-1/2-inch tubing perforated at the bottom
and hung at 2,544 feet. The bottom of the 13-3/8-inch casing was
cemented with 1,350 sacks of Permafrost II cement in one stage.
The fluid circulation system for the two wells consisted of
direct-fired oil heaters, circulation pumps, temperature controls,
flow meters, and temperature and pressure recorders. The circulating
fluid was a 50-percent mixture of ethylene glycol and water. The
heat flux of 1 to 1-1/2 MM Btu/hour for thawing was produced by fluid
flow rates of 2 to 3 BPM.
Several thaw-and-freezeback cycles have been completed in each
well. A summary of thaw cycle data is presented in table 1. The
first cycles in both wells were designed to simulate heat transfer
to the permafrost during the drilling and completion of a development
well in the Prudhoe Bay Field. The second cycles represent heat trans-
fer to the permafrost during short production periods for a normal
producing well. Circulation in one of these wells for one month
would transfer heat to the permafrost equivalent to many months of
production since the production wells will be completed with materials
in the wellbore that provide greater insulation. Later cycles were
made in the wells to investigate the effects of multiple thaw-and-
refreezing and of changing the thaw radius.
Temperatures external to the casing were recorded each 6 hours
during both the thaw and refreezing parts of each cycle. Several
additional temperature surveys were run in each well using a preci-
sion wireline instrument. Within a few days after circulation was
42
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Table 1. A summary of thaw cycles
Well &
cycle
no.
Date at
beginning
of thaw
cycle
Time at begin-
ning of thaw
cycle measured
from beginning
of first thaw
cycle, days
Average
input
fluid
temp. °F
Circulation
rate, BPM
Circulation
time, days
D.S. 4-6
1 2/22/72
2
3
4
5
6/28/72
3/17/73
6/4/73
7/27/73
0
126
389
468
521
113
160
140
130
135
12.4
(Rig pumps)
2
2
2
2
32
7
3
8
D.S. 1-6
1 6/9/72
2
3
9/17/72
3/7/73
0
201
373
138
150
125
(Reverse)
3
3
10.5
90
stopped, the temperatures throughout the monitored sections of the
wells dropped to the freezing point. The depth at which total freeze-
back had occurred was indicated when the temperature would start drop-
ping below the freezing point, which depends on water salinity, pressure,
lithology, and mineralogy. This freezeback depth progressed down the
hole as water in the formation and, in Drill Site 4-6, the mud ouside
the casing became completely frozen. Experimentally measured freeze-
back times agreed well with calculated (ref. 3) values.
Pressures external to the 13-3/8-inch casing were recorded each
6 hours during both the thaw and refreezing parts of each cycle. The
43
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pressure history for the two wells is shown in figure 1. Initially, the
transducers indicated a pressure gradient equal to the hydrostatic
gradient of the fluid outside the 13-3/8-inch casing. However, during
the heating cycles the pressure measurements indicated a drop in the
fluid level in the casing-borehole annulus. The drop in fluid level
was confirmed by refilling the annulus. The nonlinear behavior of the
pressures with depth later during the heating cycles indicated barriers
to vertical communication outside the casing of both wells. This is
more pronounced during the second heating cycle due to additional
sloughing that took place during the first cycle. The nonlinear pres-
sure variation with depth is illustrated on figure 1 where during the
second heat cycle on Drill Site 4-6, all of the deeper transducers
indicated pressures of less than 200 psi with the exception of the
transducer at 571 feet. Similar conditions are shown during the
second heat cycle on Drill Site 1-6 where the deeper transducer pres-
sures dropped below 200 psi. The shallower transducer pressures in
both wells remained at or near a fluid gradient due to the annulus
being filled periodically with water at the surface during the heating
cycles.
Immediately following the discontinuation of each heat cycle,
pressures began to increase. The pressures in well Drill Site 4-6
increased at each transducer level as the temperature dropped to the
freezing level and continued to increase until the temperature fell
below the freezing point at that particular transducer level. The
independence of each transducer in well Drill Site 4-6 is illustrated
on figure 1 where the maximum pressure at each transducer depth oc-
curred as the temperature dropped below freezing regardless of the
pressure level of the adjacent transducers. The water-base mud left
in the annulus froze across each of the transducers, preventing a
vertical transfer of the pressure in the annulus.
The pressure behavior differed in well Drill Site 1-6 because
of the presence of the oil-base mud left in the annulus during the
completion of this well. The oil-base mud, which does not freeze or
44
-------
cr
o
lU
t—
S
\n
in
UJ
cc
c_
CC
UJ
UScJ)
en
>-
CX
Ul
UJ
cc
Q_
-o
c
-------
solidify, allows the vertical transfer of pressure in the annul us.
This explains groups of transducers reaching a maximum pressure at the
same time, independent of the temperature level at each of the trans-
ducers. This is illustrated on figure 1 in cycle No. 1 where maximum
pressures were reached at transducer depths of 30, 129, and 337 feet,
simultaneously. Also, a group of transducers at 547, 652, and 968
feet reached maximum pressures simultaneously. This would indicate
vertical barriers in the annulus at 450 feet ± and 1,000 feet t The
same grouping of transducers is also apparent during the second cycle.
The location of these two barriers, plus additional minor barriers,
was indicated by bonding on a Cement Bond Log run prior to and follow-
ing the second heating cycle.
In addition to the large-scale field experiments, extensive the-
oretical (refs. 5,6) and computer studies, and laboratory investigations
of permafrost properties have been undertaken to more completely under-
stand the freezeback phenomena. The theoretical understanding begins
with a computer simulation of thermal behavior since it is the thawing
or refreezing of permafrost that leads to its influence on the well.
The mechanical behavior of thawed and frozen soils has been determined
experimentally (refs. 7,8). Using the results of the experimental
studies and the theoretical equation relating stress and strain, a com-
puter program has been developed (ref. 4) that calculates refreezing
pressures. Pressures calculated with the computer program agrees with
the field data which are shown on figure 1. Figure 2 shows, for ex-
ample, the maximum freezeback pressures as a function of depth for
the various thaw cycles of the Drill Site 4-6 well. These data indi-
cate that multiple cycles do not strengthen permafrost. Figure 3
shows similar behavior for the Drill Site 1-6 well. Heat loss from
this well was lower than for the Drill Site 4-6 well because of the
low thermal conductivity of the oil-base fluid outside the 13-3/8-
inch casing. Maximum pressures observed for this well were generally
lower than for the Drill Site 4-6 well because the thaw radius was
smaller and because the oil base fluid outside the casing could not
46
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200 -
400 —
LINES SHOW CALCULATED BEHAVIOR
MEASURED CALCULATED
O CYCLE 1
0 CYCLE 2 — — — —
600 -
800 -
1000 -
1200 i—
200 400 600 800 1000
PRESSURE, psi
1200 1100
1600
Figure 2. Maximum freezeback pressure Drill Site 4-6.
o
X
200
400
600
800
1000
1200
1400
MEASUREMENTS \
o
O CYCLE 1 N
0 CYCLE 2
A CYCLE 3 0
CALCULATION INCLUDING EFFECT OF
NON FREEZING FLUID AT THE WELLBORE
200 400 600 800
PRESSURE, psi
1000 1200
i i\i_oour\L, jjsi
Figure 3. Maximum freezeback pressure Drill Site 1-6.
47
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freeze and create excess volume. The refreezing pressure gradient
appeared to be lower in the region above 400 feet where large wash-
outs were logged. Pressure transducers in the interval from 547 to
968 feet reached maximum pressure simultaneously and were related by
the hydrostatic gradient of the oil-base fluid surrounding the pressure
transducers. Figure 3 also shows calculated behavior including the
effect of nonfreezing fluid at the well bore. This analysis indicates
that fluid communication through the annulus of unfrozen oil-base mud
causes shallow freezeback pressures to be larger than they otherwise
would be, and deeper freezeback pressures are less than they would be
if the outer casing annulus were cemented or filled with a freezable
liquid.
The previously described computer program has been used to calcu-
late freezeback pressures for field operating conditions. In a typical
field case, the degree to which water can flow into the thawed region
to maintain saturation, or the degree to which liquid can flow out of
the thawad region to relieve pressure, is not known with certainty.
In order to calculate a maximum likely pressure, we have assumed that
the thawed region will remain saturated during heating and that no
fluid can escape from the thawed region during refreezing. The thaw
radius depends on the exact well completion and on operating conditions
To illustrate behavior that is expected, we have modeled a well which
is completely cemented to the surface and which is insulated with a
gelled oil fluid in the 13-3/8-inch by 9-5/8-inch annulus as well as
in the 9-5/8-inch by 5-1/2-inch annulus. The well is assumed to be
produced at moderately high flow rates for various lengths of time
and then shut in to allow complete freezeback to the wellbore. Cal-
culated freezeback pressures versus depth for refreezing after one
year of production and for refreezing after 20 years of production
are shown on figure 4. Estimated times to refreeze at various depths
are also shown. These calculations indicate that somewhat greater
pressures are expected for large thaw radii, provided a mechanism is
available to resaturate the thawed zone. On the other hand, extremely
48
-------
400
800
1200
CL
LU
Q
1600
2000
2400
• YEARS TO FREE2EBACK
TO THE DEPTH SHOWN
YEARS OF PRODUCTION
BEFORE REFREEZING COMMENCES
800
1600 2400
EXTERNAL PRESSURE, psi
3200
4000
Figure 4. Casing strength (casing full of 9.6 PPG fluid)
and estimated maximum freezeback pressures
long periods of time would be required to refreeze and thus generate
the pressures. Figure 4 also shows the collapse pressure of two
weights of casing when filled with 9.6 ppg fluid and assuming no
additional strength resulting from the surrounding cement.
A parameter study has helped to identify important variables.
In the course of this study, freezeback pressures were compared with
that calculated for the following case:
(Porosity) (Ice Saturation) = 35%
Initial thaw radius =5.3 feet
Depth = 1,000 feet
Earth stress = 645 psi
Permafrost equilibrium temperature = 22.3°F
Freezing temperature = 31.0°F
49
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Final freezeback radius = 0.557 feet (13-3/8-inch casing)
Freezeback time = 200 days
The effect of parameter variation is shown on table 2. The great-
est changes in pressure occur when changing the maximum thaw radius and
the final freezeback radius. Of course, it is also clear that depth is
a significant variable.
INTERNAL FREEZING
Consider now the possibility of having water-base fluids in por-
tions of the cased well bore within the permafrost region. As perma-
frost refreezes, the water-base fluid also refreezes and expands in
volume. Pressure will rise until the excess volume can be accommo-
dated by fluid compressibility or expansion of the pipe. If large
volumes of fluid are frozen, the pressure may increase to a value
which will cause casing damage. Many solutions to this potential
problem have been proposed such as (refs. 9-13) displacing the freez-
able liquid with nonfreezeable fluids or cement, removing undesirable
fluids by swabbing and gravity drainage of the annul us, or by drilling
the well with an oil-base drilling mud. One of the most attractive
solutions is to displace the freezable liquid with an oil-base fluid
which gels when it is heated by produced fluids in the wellbore. Such
gelled oils can be formulated to have low thermal conductivities and
also retard radiant heat transfer. Since gelling suppresses convec-
tive heat transfer, the gelled fluid serves as a thermal insulator.
Displacement of water-base mud with large excess volumes of
gelled oil has been described previously (ref. 9). More recently, a
modified displacement process has been used which improves the effi-
ciency of the displacement operation and reduces cost.
Figure 5 shows a typical well completion. As explained in the
previous section of the paper, when casing of adequate strength is
employed, it will be satisfactory from a freezeback point of view to
cement annuli external to the 20-inch and 13-3/8-inch casings. The
50
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Table 2. Parameter variation results
Initial thaw radius, ft Pressure, psi
1
2
5
5.3
10
20
1218
1388
1567
1582
1672
1678
Final freeze radius, ft Pressure, psi
0.557
0.75
1.0
1.5
2.0
(Porosity) (Ice
Saturation), %
1.10
0.20
0.30
0.35
0.40
1582
1517
1467
1378
1312
Pressure, psi
1418
1508
1562
1582
1602
Freezeback time, days Pressure, psi
50
100
200
300
500
1587
1584
1582
1581
1580
Computed freezeback pressure
Computed freezeback pressure
for base case
0.77
0.88
0.99
1.00
1.05
1.06
Computed freezeback pressure
Computed freezeback pressure
for base case
1.00
0.96
0.93
0.87
0.83
Computed freezeback pressure
Computed freezeback pressure
for base case
0.90
0.95
0.99
1.00
1.01
Computed freezeback pressure
Computed freezeback pressure
for base case
1.00
1.00
1.00
1.00
1.00
51
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PERMAFROST BOTTOM
@ 2000 FT
LEGEND :
CEMENT
GELLED OIL
WATER-BASE
DRILLING MUD
20" 94# H 40
@ 100 FT.
' FO CEMENTER @ 2400 FT
r
P'
i \
V' FO CEMENTER @ 2650 FT.
-i 13 3/8" 72# MN80 @ 2700 FT
5Vi" 17# N 80 TUBING SET
AT PAY ZONE
9 5/8" 47# S0095 @ 10,000 FT
Figure 5. Typical arctic completion.
annulus between 9-5/8-inch casing and 13-3/8-inch casing can be dis-
placed through a stage cementing tool located well below the bottom
of the permafrost. The water-base drilling mud which is being displaced
will generally have a modest plastic viscosity and gel strength. Oil-
base displacing fluids have been formulated which will irreversibly
develop gel strengths sufficiently high to prevent convection as they
are heated by produced fluids in the wellbore. During initial place-
52
-------
merit, the fluid is quite pumpable, yet it exhibits a relatively high
plastic viscosity and gel strength even when injected at a low temper-
ature. Because of the high viscosities and gel strengths of these two
fluids, a direct displacement is usually in laminar flow. High displace-
ment efficiency of the drilling mud requires that a considerable ex-
cess volume of gelled oil be injected.
The more recently developed process includes an intermediate
wash step using fresh water. Because of the lower viscosity, high
pump rates will produce turbulent flow in the displacing water. If
water is pumped down the drill pipe so as to enter the casing annul us
and displace mud upwards, the viscosity ratio and gravity ratio in the
annulus are unfavorable. Nevertheless, displacements can be relatively
efficient. Turbulent eddies erode bypassed mud, transfer it laterally
into the moving fluid stream, and thus lead to good displacement effi-
ciencies which are characteristics of turbulent conditions. Displace-
ment behavior during this step has been studied in small laboratory
models (approximately 5 and 10 feet long) in an intermediate depth
well (900 feet) and in full-scale displacements at Prudhoe Bay. Figure
6 illustrates, for example, the types of displacement behavior observed.
The data indicate that no more than two system (drill pipe plus annu-
lus) volumes should be required to achieve good displacement of the
water-base drilling mud.
Following the water wash step, gelled oil is injected down the
drill pipe to displace the water. If desired, a wiper plug between
oil and water can be used. As the weighted gel enters the annulus,
both gravity and viscous forces will be favorable. Further, the
displaced fluid will have a low viscosity and no gel strength. Studies
in laboratory models and in actual field displacements indicate highly
efficient displacements. Figure 7 shows a comparison of typical re-
sults. Again, less than two system volumes appears to be adequate to
achieve a near perfect displacement.
Use of a device to directly indicate water contamination of the
gel in the effluent stream has proven to be very helpful. A commer-
53
-------
100
O
eo
UJ (/)
X - S
O X
Z I-
£2
_1 >
< o
? t
u, CO
UJ X
X
cc o
UJ —
0. X
- LEGEND:
H-
- 40 g A LABORATORY MODEL
£ o 900 FT DEEP WELL
* Di
FULL SCALE WELL
AT PRUDHOE BAY
[VOLUME OF GELLED OIL PUMPED IN 1
VOLUME Or DRILL PIPE AND ANNULUS
Figure 7. Displacement efficiency for water being
displaced by gelled oil.
REYNOLDS
NUMBER
or WATIR
3,120
16,600
23,000
54
-------
dally available "Net Oil Analyzer" has been successfully used at
Prudhoe Bay. It consists of a Teflon-coated metal probe located cen-
trally in a length of Teflon-coated pipe, both of which are wired to
an electronic oscillator circuit mounted integrally with the unit.
The electrical capacitance of the device depends on the composition
of the fluid in the pipe. This causes the oscillator to generate
outputs of various frequencies. By calibrating output frequency
against samples of gelled oil containing known water contamination,
the probe can be used to monitor the effluent during gel placement.
The reading is instantaneous and can be taken as often as desired.
For field displacements, a comparison of probe readings with retort
analysis of effluent samples has shown excellent agreement.
CONCLUSIONS
1. Field experiments have shown that within the earth, there
are mechanisms available to maintain positive pore pressures in thaw-
ing regions around a we 11 bore.
2. Upon freezing, pressures will rise until excess fluid can be
dissipated, or until the frozen soil can be pushed back at a rate nearly
equal to the rate at which excess volume is being created by the re-
freezing process.
3. Pressures calculated with a mathematical model which is based
on thermal and mechanical behavior of Prudhoe Bay permafrost are in
good agreement with values measured in a large-scale field test.
4. Pressures estimated for normal operating conditions are in
a range that can be tolerated if the proper casing is selected.
5. In the completion of a typical Arctic oil or gas well, water-
base fluids which are inside casing opposite the permafrost section
must be removed in order to prevent casing damage resulting from freez-
ing of the fluid.
6. If freezable fluids are displaced by gelled oil, freezing
problems will be eliminated while at the same time the gelled oil
serves as a thermal insulator.
55
-------
7. An improved displacement process consists of an intermediate
water wash step to displace drilling mud before injection of gelled oil.
8. Two system volumes of water are sufficient to remove virtually
all the water-base drilling mud from the system.
9. Displacement of water with weighted gelled oil is highly
efficient, and less than two system volumes has given near perfect
displacements.
10. Use of readily available electronic instruments permits
continuous monitoring of the gelled oil effluent stream.
REFERENCES
1. E. J. Couch and H. H. Keller, "Permafrost Thawing Around Pro-
ducing Oil Wells," Journal of Canadian Petroleum Technology,
1970, volume 9, p. 107.
2. J. R. Eickmeir, D. Ersoy, and H. J. Ramey, Jr., "Wellbore Tem-
perature and Heat Losses During Production or Injection Opera-
tions," Journal of Canadian Petroleum Technology, 1970, volume
9, p. 115.
3. E. P. Howell, T. K. Perkins, and M. S. Seth, "Calculating Tem-
peratures for Permafrost Completions," Petroleum Engineer,
April 1973 (vol. 45), p. 69.
4. T. K. Perkins, J. A. Rochon, and C. R. Knowles, "Studies of
Pressures Generated Upon Refreezing of Thawed Permafrost Around
a Wellbore," Journal of Petroleum Technology, AIME Transactions,
October 1974 (vol. 257), p. 1159.
5. M. A. Goodman and D. B. Wood, "A Mechanical Model for Permafrost
Freezeback Pressure Behavior," SPE Paper No. 4589 presented at
48th Annual Fall Meeting, Las Vegas, Sept. 30 - Oct. 3, 1973.
6. A. M. Shalavin and G. P. Klyushin, "Method for Determining the
Pressure on the Casing Pipes with Freezing of the Flushing
Fluid in the Well," (Metodika opredeleniya velichiny davleniya
na obsadnye truby pri zamerzanii promyvovhnoi zhidkosti v skvazhine)
Burenie, No. 9 (1972), pp. 24-26.
7. T. K. Perkins and R. A. Ruedrich, "Mechanical Behavior of Syn-
thetic Permafrost," SPE Journal, AIME Transactions, August 1973
(vol. 255), p. 211.
56
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8. R. A. Ruedrich and T. K. Perkins, "A Study of Factors Influencing
the Mechanical Properties of Deep Permafrost," Journal of Petroleum
Technology, AIME Transactions, October 1974 (vol. 257), p. 1167.
9. W. B. Bleakley, "North Slope Operators Tackle Production Problems,"
Oil and Gas Journal, Oct. 25, 1971 (vol. 69), pp. 89-92.
10. R. W. Flumerfelt, "An Analytical Study of Laminar Non-Newtonian
Displacement," SPE Paper No. 4612, 48th Annual SPE Fall Meeting,
Las Vegas, Nevada, 1973.
11. H. L. Graham, "Rheology-balanced Cementing Improves Primary Suc-
cess," The Oil and Gas Journal, Dec. 18, 1972 (vol. 70), p. 53.
12. C. R. Clark and L. G; Carter, "Mud Displacement with Cement Slur-
ries," Journal of Petrgleum Techno!ogy, July 1973 (vol. 25), p. 775.
13. T. Garvin and K. A. Slagle, "Scale-Model Displacement Studies
to Predict Flow Behavior During Cementing," Journal of Petrole-
um Technology, Sept. 1971 (vol. 23), p. 1081.
DISCUSSION
MR. GENE J. MIROLLI SPE-AIME (Hercules, Inc., Beaumont, Texas):
Have you investigated the use of insulated casing? If so, does
it show any improvement in projecting permafrost?
MR. KNOWLES: Yes. This has been what we would call a contingency
study. Anytime you embark on a problem of this magnitude where
you are doing original work, you obviously do not put all of
your eggs in one basket.
And, yes, we have looked at several different types of
dual wall tubing and casing, and different insulation materials.
The need for insulation all relates to the interrelationship
of what the effect of the oil well is on the permafrost, and
what the effect of the permafrost is on the oil well. Under-
standing this, one soon determines what degree of insulation is
required. It is not the black and white problem of whether you
are going to insulate or you are not going to insulate. The
answer lies somewhere in the gray area. You only need to insulate
to a given degree.
57
-------
All our studies to date, and we are talking about the
combination of about 3 years of work, now indicate that a
limited thaw technique, using oil-base casing pack, has a
very acceptable safety margin.
MR. RICHARD S. SCALAN (University of Texas, Marine Sciences Insti-
tute, Port Aransas, Texas): I wonder if you could give the
uninitiated an idea of what permafrost is like. Is it some-
thing like jelly? Would you sink up to your knees in it?
MR. KNOWLES: That is an excellent question.
The Arctic Slope that we are working on—specifically,
the area west of the Canadian border and east of the Bering
Straits, the North Slope of the Brooks Range—has a very
interesting geologic background. I make no pretense of making
these comments as an expert, but just on what I have garnered
from my studies with geologists.
In the formations at about 1,200 to 1,000 feet, we find
evidence of ferns, fossils, and micro fauna that one would
find in a subtropic climate. The formations that are now in
the range of 900 to 600 feet—when they were at the surface
and being deposited—the climate was, in general, an Alpine
one, much as we have in Anchorage or in the high Rockies in
Idaho or Colorado.
A very lengthy study has been made to determine how much
of the formation was laid down in frozen conditions. The
results of this study indicate that the sediments above 200
feet are the only portions of the formation that have been
laid down under Arctic conditions.
Unfortunately, when you speak of permafrost, the picture
that immediately jumps to mind is the classic muskeg. One
picture is in the wintertime of a frozen swamp with a Cater-
pillar tractor walking across it, and then the next picture
is in the summertime when you could not wade across the swamp.
That is characteristic of the upper perhaps 30 to 50 feet in
the area in which we are dealing.
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Below 200 feet, certainly you are talking about forma-
tions that were laid down under thawed conditions, with normally
compacted grain-to-grain contact.
And so the answer to your question of what is the perma-
frost to a drilling engineer is: permafrost is like any other
frozen gravel bed. It is frozen; it has ice between the grains.
It has none of what we refer to as excess ice. The load carry-
ing member is the grain itself.
The classic muskeg is in the upper 50 feet, perhaps in the
upper 30 feet, where you have a lot of excess ice. You have
the polygons, obviously as the result of the ice wedges. We
have a great deal of information on that, but that gets over into
the civil engineering problem of structure support. In the oil
well problem, we are looking at the overall 2,000 feet of perma-
frost, and we are talking about grain-to-grain contact through
that section.
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DRILLING FLUID PRINCIPLES AND OPERATIONS
Jay P. Simpson*
Abstract
The purpose of this discussion is to tell what drilling fluids are and
to explain why drilling fluids must be used. Emphasis is given to the func-
tions of a drilling fluid—what the drilling fluid must do. This, in turn,
is related to the physical and chemical properties of the drilling fluids
that are tested and controlled, so that drilling operations can be conducted
safely and effectively.
Since a great diversity of drilling conditions are encountered, many
types of drilling fluids must be used. Some of the most widely used types
of drilling fluids are described, with attention to why these systems are
selected. Although a variety of materials are used to prepare and maintain
each type of drilling fluid, the additives can be considered in certain
general classes. These classes of materials are discussed in relation to
the physical or chemical properties to be controlled. Consideration is
given to the relative quantities of materials used in a typical drilling
fluid.
Some of you out there may be asking yourselves these questions: "What
is a drilling fluid? Why does anyone have to use one? Why does it need to
be so complicated? Why do we use so many different materials?"
Perhaps one of the reasons that it is difficult to talk about drilling
fluids is that we cannot really see what is going on down where the drilling
fluid is doing its work. However, I will try to describe the procedure.
The drilling fluid will start in the suction bit. A mud pump will move
the drilling fluid up into the drill string. The drilling fluid really
starts its work as it goes out of the eyes of the bit, because what it must
do is move the cuttings away from the bit and transport them on up the hole.
I think you can see that if it does not do that job, the drilling opera-
tion is not going to last very long.
*Assistant Director of Sales-Technical, Baroid Division, NL Industries,
Inc., Houston, Texas.
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Let us follow the course of the drilling fluid, as it brings the
cuttings back up the annul us between the drill string and the well bore. At
the surface, the drilling fluid flows out the flow line and usually is
passed over a shale shaker--a vibrating screen where the cuttings are sepa-
rated and dumped into a shale pit. The drilling fluid falls through the
screen into a settling pit and then moves on over into the suction pit to
start the cycle again.
The circulation system can vary a great deal. A typical arrangement on
a big rig might include three tanks for the surface system. For an air dril-
ling operation, instead of the mud pump there would be air compressors that
would pump air down the drill string and back out the flow line.
Now, let us get to the matter of why we have to use a drilling fluid.
The primary functions of a drilling fluid are listed in table 1. Serving
any one of these functions might be fairly simple; but when we put them
altogether, it does get quite complex. We have already talked about trans-
porting drill cuttings to the surface, and many different fluids will do
this. The simplest perhaps would be just circulating air.
The second function listed has to do with control of formation pore
pressures. In many ways this is perhaps the single most important function
of the drilling fluid.
Hydrostatic pressure is provided by the drilling fluid. This, coupled
with the pressure drop at the drilling fluid travelling up the annulus, con-
stitutes an equivalent circulating density that can balance a pore pressure.
Table 1
PRIMARY FUNCTIONS OF DRILLING FLUIDS
TRANSPORT DRILL CUTTINGS TO THE SURFACE
CONTROL FORMATION PRESSURES
MAINTAIN BOREHOLE STABILITY
PROTECT PRODUCTIVE FORMATIONS
PROTECT AGAINST CORROSION
COOL AND LUBRICATE THE BIT AND DRILL STRING
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But it is going to balance only one pore pressure. Down hole we will have
many pore pressures. The exposed formations will not all be at the same
pressure.
Perhaps the most common practice would be to adjust the drilling fluid
density to balance the highest pressure encountered in a permeable formation.
If you do not do that, the formation fluids will move into the wellbore,
move the drilling fluid out, and you will have an uncontrolled well on your
hands.
Selecting the density of the drilling fluid, however, may not be that
simple. The next function of a drilling fluid listed in table 1 is that of
maintaining borehole stability. If we are just balancing the pore pressure
of a permeable sand, and we have a shale that is under higher pressure—and
this is a quite common situation—we do not have sufficient pressure to
completely support the shale. Therefore, there will be a force tending to
push that shale into the wellbore, causing spelling or sloughing and
resulting in borehole enlargement.
The mud chemistry can often be modified to tolerate a degree of pres-
sure underbalance without too much hole enlargement. Many shales, however,
may be so unstable that the drilling fluid density will have to be increased
to balance the pore pressure in the shale creating a considerable overbalance
opposite the lower-pressure sand. The differential pressure will then push
the filtrate out of the drilling mud and into the formation.
The weight material and drill solids will be left on the wellbore as
wall cake, and the hole will fill up with wall cake unless we do something
about it. The filtration properties of the drilling fluid must then be
controlled. This ties in with the function of protecting productive forma-
tions.
If permeable sand is the zone from which we hope to produce oil or gas,
and if we allow a great deal of filtrate to enter that formation (or even
worse, if we allow whole mud into that formation), we can pretty effectively
block and damage the formation. In many productive zones, there will be
clay materials that are sensitive to filtrate from just an ordinary water-
base mud, so you could have some serious damage from even small volumes of
filtrate. To combat this, we do certain things to the chemistry of the
63
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drilling fluid to limit the hydration, swelling, and movement of clay parti-
cles in a dirty sand.
Another function of drilling fluid that we cannot ignore is protection
against corrosion. In our drilling operations, the drilling fluids do incor-
porate air. Oxygen then is available to cause an oxidation type of corro-
sion. We also encounter acidic gases such as carbon dioxide and hydrogen
sulfide. It is the drilling fluid that gives us the capability of creating
a situation where the tubular goods (the drill pipe and the casing), can be
protected. Or we can at least use the drilling fluid as a means of deliver-
ing corrosion inhibitors to protect the pipe and the casing.
Finally, the drilling fluid must cool and lubricate the bit and drill
string. Air might do this under certain conditions; on the other hand,
some operations may require very special attention to this matter of lubri-
cation. For example, in drilling from an offshore platform, many wells
(perhaps 20 or more) might be drilled out directionally and then turned to
the zones to be produced. These high angle holes put quite a burden on the
drilling fluid to provide sufficient lubricity. Special additives are used
to provide the lubricity needed.
Let us consider some of the types of drilling fluids that are used.
These are listed in table 2. If an operator had his choice, he would
probably pick the first type - air or gas - because the gaseous fluid would
provide the fastest drilling rate and least chance of formation damage.
Unfortunately, there are not very many situations where merely air or gas
would be sufficient. The second choice would likely be clear water or brine.
Again, there are not many cases where this could be used. This brings us
down to the water muds. These are the clay-base muds (usually dispersive
Table 2
TYPES OF DRILLING FLUIDS
AIR OR GAS (MIST, FOAM)
CLEAR WATER OR BRINE
WATER MUDS (CLAY-BASE, POLYMER)
OIL MUDS
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systems) and the polymer muds (usually nondispersive). These are the
drilling fluids that are used in most of the drilling operations today.
If none of the above systems will do the job, then the last resort will
be to go to an oil mud. This would be mud that has oil as the continuous
phase. Any water that is added or incorporated will be thoroughly emulsified
as a dispersed liquid phase.
Let us consider some of the conditions in table 3 that would permit air
or gas drilling. We said that the drilling fluid provides the hydrostatic
control for formation pore pressures that are encountered. If these are
low, then air-gas drilling might be conducted. Strong competent formations
would also be necessary, because if the formation was weak it still would
collapse into the wellbore even though you could handle the small volumes of
gas that might come in.
Table 3
CONDITIONS FOR AIR OR GAS DRILLING
LOW FORMATION PRESSURES
STRONG, COMPETENT FORMATIONS
NO HIGHLY PERMEABLE FORMATIONS
CONTAINING WATER OR OIL
For clear-water drilling (as shown in table 4) we would need normal or
subnormal formation pressure, because we would have nothing there except the
hydrostatic pressure of the water itself to control formation pore pressures.
In highly permeable formations, there would be loss of the drilling water
into the formation, and you would not be able to maintain circulation.
Table 4
CONDITIONS FOR CLEAR-WATER DRILLING
NORMAL OR SUBNORMAL FORMATION PRESSURES
NO HIGHLY PERMEABLE FORMATIONS
NO EXTREMELY WATER-SENSITIVE SHALE FORMATIONS
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Water-sensitive shale would give an unstable hole when drilled with a clear-
water system.
If any of these conditions exist, we will have the need to use a liquid
mud. For example, if we have abnormally high pore pressure, then we will
need to have a drilling fluid that can be weighted. Since this calls for
suspension of the weighting material, we then get into the area we call mud.
If we have highly permeable formations, we need filtration control. And if
we have water-sensitive shales, we use those materials that slow down the
entry of water into the shale.
Listed in table 5 are conditions that create problems when drilling
with a water mud. When any of these conditions get too bad, we go to the
oil muds. The oil muds are used often for extremely water-sensitive shale
formations and for drilling steep, bedded salt. Another use for oil muds is
in drilling abnormal pressure formations containing FLS. The reason for this
is that the abnormally pressured wells require the use of high strength pipe
for drilling, and high strength pipe is sensitive to sulfide stress cracking.
The oil mud protects the pipe from corrosion and stress cracking.
Table 5
CONDITIONS FAVORABLE FOR DRILLING WITH OIL MUDS
EXTREMELY WATER-SENSITIVE SHALE FORMATIONS
DEEP SALT FORMATIONS
ABNORMALLY PRESSURED FORMATIONS CONTAINING HgS
FORMATIONS WITH TEMPERATURES EXCEEDING 400°F
PRODUCTIVE FORMATIONS SUBJECT TO DAMAGE BY WATER
Most of the water mud additives will degrade at temperatures above
300°F and degrade quickly above 400°F. So the more temperature-stable oil
muds are likely to be used in very high temperature wells.
Table 6 relates some of the functions of the drilling fluid to the
composition or property that is controlled. For cuttings transport, mate-
rials like bentonite are used to increase the viscosity and gel strength.
Weighting materials are used to increase the density of the drilling fluid
66
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Table 6
FUNCTION COMPOSITION OR PROPERTY CONTROLLED
CUTTINGS TRANSPORT VISCOSITY - GEL STRENGTH
PRESSURE CONTROL DENSITY
HOLE STABILITY AND FILTRATION - ALKALINITY - SALINITY -
FORMATION PROTECTION WETTING CHARACTERISTICS
CORROSION PROTECTION ALKALINITY - OXYGEN - SULFIDE - WETTING
LUBRICATION LUBRICITY
to provide pressure control. The type of material needed is one that has a
high specific gravity. We also need a material that is: (1) as chemically
inert as possible; (2) as insoluble as we can get; (3) not too hard; and
(4) not too soft (because we do not want it to wear down very quickly).
Barite, naturally occurring barium sulfate, is used for this purpose.
Hole stability and formation protection can be considered together.
For controlling filtration we often use bentonite and polymers and get help
from lignite and lignosulfonate. In extreme situations we could change the
wetting characteristics by going from a water system to an oil-mud system.
For corrosion protection, we generally keep the drilling fluid on the alka-
line side. For extreme conditions, we might go all the way to an electri-
cally nonconductive oil mud environment. For lubrication, we pay attention
to such things as wear characteristics, coefficient of friction, extreme
pressure lubricity, and differential pressure sticking. We then use materials
that will help in combating these problems that are associated with drilling
deep, high-angle holes.
I think you might be interested in where some of the mud materials come
from. Most of the good bentonite comes from surface deposits in the State
of Wyoming. The crude ore is brought in, stockpiled, blended, and weathered.
It is then dried, ground, sacked, and delivered to the oil field. The
deposits of the oil-field grade lignite are located mainly in North Dakota.
Lignite is one stage in the change of humus material to coal. We might
think of it as a naturally occurring humic acid. Lignite, like bentonite,
can be mined, dried, ground, sacked, and made ready to go.
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Barite is the material that we use in such tremendous quantities and
which is found all around the world. Barite mining is a very simple opera-
tion in Missouri. Some of the deposits about a generation ago actually wer
worked by hand. The Missouri operation contrasts with the processing of th
massive barite deposits at Magnet Cove, Arkansas, where the barite is mined
and trucked to a plant. There it is upgraded by a rather sophisticated
flotation process to remove the low specific gravity material and get the
material we need for oil field operations, which is 4.2 specific gravity,
or better than four times the density of water. At various sites around th
world, the barite ore will be brought to a processing plant where it will b
crushed, dried, and ground. Some of it will be sacked, but some if it will
be kept in bulk form so that it can be handled pneumatically and delivered
to the rig to bulk tanks.
Not all of the drilling fluid materials are mined products. A lot of
them are manufactured in chemical plants and are either sacked or drummed
for delivery to the rig for use.
Let us take a look now at what are some of the quantities of materials
used in a drilling fluid.
An air or gas drilling fluid, as you might expect, is a very simple
system. Typical components are listed in table 7. In this kind of an
operation, you can imagine that we do have to pay attention to corrosion,
and so there will be some small amount of corrosion inhibitor used. Also
some fearners will ordinarily be used to cope with water encountered while
drilling. The foamer is injected into the air stream and pumped down the
Table 7
AIR OR GAS DRILLING
COMPONENT CONCENTRATION, Ib/hr
FOAMER (SOAP, DETERGENT) 1 TO 10
CORROSION INHIBITORS 1 TO 5
BENTONITE 50 TO 100
POLYMER (CMC, POLYACRYLATE) 1 TO 5
68
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hole where it encounters water that comes into the well. The water comes
out of the well in a kind of mist along with the cuttings. Not very much
material is used, maybe 1 to 10 pounds of foamer per hour of drilling opera-
tion.
In the more difficult situations, a little bit of water will cause the
wellbore to slough some. This means bigger particles to bring out, and this
can be handled better with what you might call a stiff foam. In that case
a liquid mud would be mixed on the surface—maybe bentonite and a high
molecular weight polymer—and then injected into the air stream. When that
material goes down the hole, the bigger pieces can be brought to the surface
and the air drilling can continue a little longer.
In clear water drilling, the big problem is trying to keep that water
clear. I think you can imagine that water circulated while drilling tends
to get dirty. To help prevent this, you might use a flocculant such as guar
or a polymer such as a polyacrylamide. As shown in table 8, the amount used
might be as low as 0.05 Ib/bbl.
Table 8
CLEAR WATER DRILLING
COMPONENT CONCENTRATION, Ib/bbl
FLOCCULANTS (GUAR, POLYACRYLAMIDE) 0.05 TO 0.5
FIBROUS MATERIAL (PAPER, ASBESTOS) 2 TO 5 (BATCH)
CORROSION INHIBITORS
Occasionally the practice will be to pump down a batch of water that
contains fibrous materials (perhaps shredded paper or asbestos) to sweep
larger particles out of the hole. Sometimes corrosion inhibitors are used
in this type of drilling.
For the water-base muds, we could have a hundred examples. Probably
the most widely used system is a fresh water mud treated with lignite and
lignosulfonate, such as shown in table 9. The amount of barite required
will depend upon the formation pressure encountered and would be on the
order of 500 pounds of barite for one barrel of drilling fluid having a
density of 18 pounds per gallon.
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Table 9
CLAY-BASE MUD
COMPONENT CONCENTRATION. Ib/bbl
WATER 200 TO 340
BENTONITE 15 TO 30
LIGNITE 1 TO 6
LIGNOSULFONATE 2 TO 10
SODIUM HYDROXIDE 0.5 TO 1.5
BARITE 0 TO 500
It might be worth pointing out that the density of the drilling fluid
ordinarily would not have to exceed the density of the overburden, about 19
pounds per gallon. Therefore 18-pound mud is about as high as you would
have to go.
As shown in table 10, a polymer mud would be very much like the disper-
sive type clay-base mud. The salt concentration would be about 100 Ib/bbl
when sodium chloride is used. If potassium chloride is used, you might need
only 10 to 20 Ib/bbl. The alkaline material (hydroxide) is added for pH
control, because drilling with acidic mud tends to cause corrosion problems
Table 10
POLYMER MUD
COMPONENT CONCENTRATION, Ib/bbl
WATER 300 TO 345
BENTONITE 0 TO 10
SALT (NaCl, KC1) 10 TO 100
SODIUM OR POTASSIUM HYDROXIDE 0.1 TO 0.3
POLYMER (STARCH, POLYACRYLAMIDE) 0.5 TO 5
BACTERICIDE (PARAFORMALDEHYDE) 0.1 TO 0.5
BARITE 0 TO 300
70
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As indicated in table 11, oil muds are customarily prepared from diesel
oil using some type of surfactant to emulsify water. The filtrate reducer
and gellant can be oil-dispersible versions of the lignite and clay used in
water-base muds, while the barite is the same as that used in the aqueous
systems.
Table 11
OIL MUD
COMPONENT CONCENTRATION, Ib/bbl
DIESEL OIL 150 TO 230
WATER 35 TO 50
CALCIUM CHLORIDE 15 TO 25
EMULSIFIER (SOAP, POLYAMIDE) 5 TO 20
FILTRATE REDUCER (AMINE LIGNITE) 0 TO 10
GELLANT (AMINE CLAY) 2 TO 4
BARITE 0 TO 500
The handling of oil muds often differs from that of water-base systems.
With water-base muds, the additives are usually delivered to the drill site
in bags or drums and then mixed into a mud system using the rig equipment.
In areas where a lot of oil mud is used, we quite often will handle it as a
liquid mud.
The mud would be mixed in tanks at a liquid mud plant. It would then
be delivered to a land location by truck, to inland water jobs by barge, or
taken to an offshore location by a delivery vessel. After use at the rig,
the oil mud can be brought back to the liquid mud plant, reconditioned, and
stored for future use.
DISCUSSION
MR. HARRY L. HARRISON (A.C. Drilling Specialties, Odessa, Texas): On your
polymer fluids, I did not hear you mention cellulose materials. Have
you had any experience with those, or would you care to comment?
MR. SIMPSON: Yes. Many different polymers are used. I would just select
one as an example--carboxymethylcellulose--that is used along with many
others.
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WELL COMPLETION—TECHNIQUES AND METHODS
Frank H. Braunlich*
Ladies and gentlemen, we have another broad topic to cover—a topic
that I have termed "Well Completion." (Figure 1 shown.)
Drill Pipe
Figure 1
We have heard this morning about the techniques and principles of
drilling a well. Now we must complete it and prepare it for production.
Several operations are required to do this. These well completion opera-
tions bascially involve cementing, perforating, and stimulation of the
producing formation. (Figure 2 shown.)
Circulating
Drilling Mud
Rotary Table
i
Drill Pipe
Drill Col la
- Rock Bit
Figure 2.
industrial Hygiene Specialist, Dowell Division, Dow Chemical Company,
Tulsa, Oklahoma 74102.
73
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After the hole has been drilled to the desired depth, it is neces-
sary to run some steel pipe into the hole in order to protect it from
contamination and provide communication between the surface and the for-
mation below. (Figure 3 shown.)
r ^
Wellheod JJ*
|
Annulus Filled
with Cement
^~~ Produ
4~~ ~i ^r-
^ £3 Surface Pipe
1 i ,, Cemented
V J " Cemented
3 ^
cing Formation ^
Figure 3.
Cement is used to secure this pipe in the hole. Cement: also protects
and isolates the various rock formations up and down the hole. In figure
3 we see two strings of casing. The surface string is cemented to its
total depth from the surface and a production string is cemented from its
total depth through the surface string. (Figure 4 shown.)
A^
C°^
LONG
LINE P
Figure 4.
All wells require a surface string and a production string. However,
some wells, depending on the depth and the problems encountered, will
require extra casing strings, as we have heard this morning. These have
different names, usually defining the job for which they are required.
A conductor pipe starts from the surface; we find a water string, a salt
74
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string. These are rather self-defining terms for the various casing
strings.
The surface string that we have to put into the well is used to
control caving and washing out of poorly consolidated formations near the
surface. It provides a working area and contact to the earth for the
remaining drilling operations. Another very important function of this
surface casing is to prevent the freshwater sands from being contami-
nated with drilling mud, oil, ash, or saltwater. The surface strings
vary from maybe 7 inches up to as high as 20 inches in diameter,
and they will be cemented from the surface to the bottom. (Figure 5 shown.)
SURFACE CASING
Cement To
Ground Level
Loose
*\ Surfote Sand
r-
Deepest Fresh
Water Sand
Figure 5.
Regardless of the type of casing run, the same cementing operations
are performed to tie these pipes to the formation through which they pass.
The length of the surface casing will vary considerably, from a few hun-
dred feet to over a thousand feet, depending both on conditions and on what
has been encountered while drilling the well. Some of these problems have
been mentioned this morning.
This casing is used to allow access to the producing zone, and it
will protect the formation between the producing area and up through the
various levels back to the surface. This pipe will usually extend from
the ground level through the surface casing and into the zone of expected
production. It is not always cemented all the way to the surface, although
it may be. It may be exposed to very high pressures, and in some cases
to very corrosive fluids as well as high temperature. So it is imperative
that the surface casing be extremely well designed. (Figure 6 shown.)
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PRODUCTION CASING
'H^
Vf> It-Tat C i /•
^?f Surface Casing
Cemented
Production Cosing
•f! Oil Sand
Figure 6.
STAGE TOOL @ 1,800'
STAGE TOOL @ 6,500'
7 5/8" @ 12,500'-
TIEBACK @ 17,200'
BHT 300
MUD WT. 9.5#/GAL
J
20" CASING IN 26" HOLE
800'
13 3/8" CASING IN 17 1/2" HOLE
4,600'
10 3/4" CASING IN 12 1/4" HOLE
13,000'
7 5/8" LINER IN 9 1/2" HOLE
17,600'
5" LINER IN 6 1/2" HOLE
22,000'
WEST TEXAS WELL
Figure 7.
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After it is cemented in place, the production casing separates the
producing zone from undesirable fluids such as saltwater, and acts as
a work shaft to the producing zone. (Figure 7 shown.)
Contrasting the simple well shown in figures 3,5, and 6, with only
a surface string and a production string, here is a West Texas well
drilled to 22,000 ft. It contains five strings of casing and several
special tools. The 800-ft surface string is 20-inch pipe set with ce-
ment from 800 feet to the surface. The intermediate string to 4,600 ft
was cemented around the bottom 800 ft and by use of the stage tool, from
1,800 ft to the surface.
The next intermediate string was 10-3/4 in. set at 13,000 ft. At
this time the formation would not withstand the full hydrostatic head
of cement; so cement was placed around the bottom 1,000 ft. and above
6,500 by means of the stage tool.
The next two strings of pipe are called liners. Liners extend
from the bottom of the well up into the previous string of pipe. They
do not extend all the way back to the surface. The first liner (7-5/8")
is set at 17,600 ft and cemented into the 10-3/4-in. casing. The 5-in.
liner is cemented from 22,000 ft into the 7-5/8-in. liner. The 5-in.
liner contains a tieback tool that allows pipe both to be run to this
point and the surface and to be cemented as a production string if the
well is determined to be a producer. If it is not a producer, the addi-
tional pipe has been saved. (Figure 8 shown.)
Cement Equipinen!
Figure 8.
77
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Surface equipment is rather sophisticated these days. Special
trucks and transports have been developed for this. (Figure 9 shown.)
We see in figure 9 a transport to haul bulk cement to the well. Most
cement is handled in bulk, although it has been and can be handled
by sacks. It is taken out in air bottles and transported by com-
pressed air from the air bottles to the cementer.
Figure 9.
78
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* I
Figure 10.
At the cementer the cement is injected into a mixing device where the
water and the dry cement solids are blended together, (Figure 10 shown.)
The cementer (fig. 10) consists usually of two pumps and two displace-
ment tanks so that all the pumping operations can be conducted, and so
that the amount of cement and following flush fluid that has been pumped
can be measured. After coming through this mixing device at the back
of the truck, the cement slurry is picked up by a high-pressure pump and
pumped into the pipe, thus displacing the drilling rnud in the hole.
Figure 11 shown.)
79
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Figure 11
In figure 11 we see a well site with a cementing operation underway.
The dry ingredients, including all of the additives that are needed for
cementing, are blended and mixed at a station where everything is
stored. They are then brought out in the transport, blown across by air
into the blender part of the cementer, and from there picked up and with a
80
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high-pressure pump put down through the pipe, much as was shown for
the drilling mud. (Figure 12 shown.)
Figure 12.
Why do we use cement? When mixed with water the dry product known
as Portland Cement will set into a very hard mass. Before the cement
slurry has hardened, it is very easily handled, and we can provide the
necessary hydraulic system that we need to do the job. Experience in the
oil industry has proven that this readily available material best solves
the need to permanently place and seal casings in a well. The most com-
mon method of mixing cement is to add water to the dry Portland Cement.
This type of cement is called neat cement. However, the neat cement does
not answer all the questions and problems that we have, so we have to
provide other properties to this cement slurry by using additives. {Figure
13a shown.)
.'• ,
Figure 13a.
81
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We have a number of additives for different purposes. We have
additives to provide weight to the cement slurry, to extend its volume,
to accelerate the setting of the cement, to retard the setting of the
cement, to provide lost circulation control, and then there are special
additives for special problems. (Figure 13b shown.)
Figure 13b.
Of the weighting materials, perhaps the most used is barite or
barium sulfate. Hematite, an iron oxide, has been used; it is also a
very heavy compound and can provide high density for the cement slurry.
Sand too is used at times. These materials are ground to a powder form
much like the cement solids so that they can be dispersed and trans-
ported through the system, to increase the density of the slurry.
Another way of getting the increased density is to add a dispersant
to the cement slurry. A dispersant is a material that causes the cement
to require less water to be pumpable; therefore we can use the cement
solids themselves to increase the density. This this method we can
get up to around 17-1/2 pounds per gallon without any extra inert
materials. With combinations of the dispersant and these weighting
additives, densities as high as 22 pounds per barrel have been obtained.
(Figure 13c shown.)
82
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Figure 13c.
The extenders are materials that allow us to use extra water and
reduce the density of the slurry or get a greater yield from the sack
of cement. The yield from the sack of cement is what we are after in
this case. And if we can obtain this cheaply, then these extenders are
very valuable. Examples of extenders are usually the pozzalamic-type
materials, such as volcanic ash or diatomacious earth, or the materials
that we produce, such as fly ash from our plants. (Figure 13d shown.)
Figure 13d.
83
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Accelerators are used to reduce the time required for cement slurry
to set into a hard mass, or to reduce the setting time. The best ex-
ample is calcium chloride. It accelerates the setting of the cement
considerably. It is used particularly in low temperature or shallow
wells. (Figure 13e shown.)
Figure 13e.
On the other side of the scale we have retarders, in order to have enough
working time with the slurry to allow us to set it in high-temperature
wells. Retarders are lignin compounds or sugar compounds that retard the
setting of this cement. It is an extremely difficult task to inject a
cement slurry from the surface under 70° or 80° surface temperature
down to the bottom of the well bore and back up and around the pipe, when
the bottom hole temperature is 400° or 500° F, and have enough pumping
time to get everything in place before it sets up. So the design of this
cement, especially with the retarders, is extremely critical. (Figure 13f
shown.)
Figure 13f.
84
-------
'.. Ktf
o-its Figure 13g,
«K* - '
In addition to materials that actually affect the reaction of the
cement slurry, we have lost circulation materials, which are defined
by their titles. They are to prevent lost circulation in cracks or in
high permeable or vuggy formations so that the cement can be brought
up around the pipe and not lost in the undesirable zones. Examples of
this type of material are ground coal, known as kolite; gilsonite,
which is a high-carbon material; and a flake-like material made of cel-
lophane flakes. (Figure 13g shown.)
Special additives are also used for unusual problems. For example,
in high temperatures, cement strength tends to degrade with time. So in
an effort to control this cement loss, find sand is added to the cement
slurry when temperatures get above, for instance 250° F.
At times we find we have a lot of foaming problems at the surface
in trying to mix these cement slurries, so antifoam agents are added to
help in the mixing operation.
Some dispersants are used, which, as we have already mentioned,
allow us to use extra water.
Fluid loss additives are added, because as the cement slurry is
passed across the face of a formation which has permeability and poros-
ity, we tend to lose the water from the slurry. As this happens, the
mixture becomes too thick to pump, and at times it could, in a sense, set
85
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up and not be pumpable, even though chemically it has not had time to
react and form the solid mass that we usually consider cement.
There are many others too numerous to mention at this time. (Figure
14 shown.)
Figure 14.
When cementing casing in the well, there are some important pieces
of equipment that could be called auxiliary equipment. These are not
always used but they do have a definite purpose and should be used when-
ever possible. (Figure 15a shown.)
Figure 15a.
86
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A float shoe is screwed onto the first joint of casing run into the
well. This round-nosed device acts as a guide for the casing and pre-
vents it from hanging on ledges as the casing is lowered into the well.
The ball acts as a check valve and prevents the cement from coming back
into the casing after it has been displaced. The float shoes are also
made with a flapper valve in place of the ball.
Guide shoes are sometimes used instead of float shoes. Their main
purpose is to guide the casing down the hole. They do not contain a
valve mechanism.
The float collar shown has a spring-loaded flapper valve which allows
fluid to pass through it from the top and closes similar to a bathtub
stopper when fluid attempts to enter from the bottom. This allows the
casing to be floated into the hole by the buoyancy of th3 partially filled
casing. The float collar is usually placed one joint above the float
shoe. Float collars are also made with the ball check instead of the
flapper. (Figure 15b shown.)
Figure 15b.
Centralizers are simply devices with bow springs similar to leaf
springs on a car. These heavy spring steel guides fit around the outside
of the casing and help center the casing in the bore hole during the
cementing operation. Some operators prefer the spiral centralizer. It
contains spiral blades which deflect the flow of fluid and generate
turbulence to aid in displacing the drilling mud from the annulus.
(Figure 15c shown.)
87
-------
Figure 15c.
Scratchers are placed on the outside of the casing and are used to
remove the mud from the formation face so that the cement will make a
good seal against the rock. To get the proper action from the scratchers,
the casing has to be moved up and down or rotated, which depends upon the
type of scratcher used. (Figure 16 shown.)
.*»«• I
t-f,,tn,h,t<
I KM* »«»
li* !<•*«*»»
Figure 16.
Figure 16 illustrates the use of the four pieces of equipment pre-
viously discussed as they might be used in a well. The float shoe directs
the centralized casing to the bottom of the bore hole. A fluid such as
cement is free to move down the casing through the open flapper in the
float collar and on to the bottom of the casing. As the cement passes
88
-------
through the float show, the centralizer holds the casing in the center
of the bore hole, allowing the cement to completely surround the steel
casing. The scratchers remove the drilling mud cake from the formation
as the casing is rotated. (Figure 17 shown.)
Figure 17.
"UK tOP
Casing wiper plugs are designed to be run inside the casing ahead
of and behind the cement slurry on a casing cement job. These plugs help
prevent contamination between the cement and the drilling fluids as they
move down inside the pipe. The plugs also help remove drilling mud that
adheres to the inside of the casing.
In the past, wiper plugs have been constructed of materials such as
gunny sacks, cast iron, leather, and wood. The present design calls for
either cast aluminum or plastic cores with a molded rubber body.
The bottom plug, shown at the left in figure 17, has a hollow core
with a diaphragm which is ruptured by increasing the fluid pressure on
the plug after it has seated on the float collar. This plug allows more
complete removal of mud from the casing and rupturing of the rubber
diaphragm allows continued pumping after the plug seats on the float
collar.
The top plug on the right has a solid core designed to completely
close off fluid movement when seated on the float collar. (Figure 18
shown.)
89
-------
Figure 18.
Figure 18 illustrates the seating action of wiper plugs in the casing,
On the left we see the bottom plug seated with the diaphragm ruptured
and fluid being pumped through the casing. On the right the top plug has
been pumped to the bottom stopping fluid movement through the casing.
(Figure 19 shown.)
Figure 19.
This series of well sketches shows the fluid movement in the casing
during a cement job. In diagram #1, mud is being circulated out of the
pipe with the bottom wiper plug separating the drilling mud from the
cement. In diagram #2, the bottom wiper plug has seated on the float
collar and the diaphragm in the plug has ruptured, allowing the cement to
move around the shoe of the casing and into the annul us. The top wiper
plug is separating the cement and the drilling mud is used to displace
the cement.
90
-------
Diagram #3 shows the top wiper plug displaced to the shutoff point on
the float collar, with cement left in the casing below the float collar
and in the annul us.
Many factors go into the design of auxiliary equipment for casing,
cement requirements, and cementing techniques. All of these factors
can influence the success of a cement job. The oil operators, in con-
junction with service companies, strive to apply the design factors
necessary for the economic and successful primary cement job on each
well. (Figure 20 shown.)
Figure 20.
Now let us refer back to our original diagram of the cutaway of the earth's
surface showing the trapped fluid in the producing formation. The surface
pipe has been placed in the hole and cemented. Production pipe has been
run through the producing formation and the well is ready for completion
work. The casing can now be perforated and the well can be tested.
(Figure 21 shown.)
When we first perforate the well, bullets or jet charges are used to
drive holes through the casing, thus giving us a contact with the forma-
tion into which we have drilled. Figure 21 shows one plane of four shots,
one in each of the quadrants of the plane. Holes are shown through the
casing and the cement, and out into the formation itself.
Chemicals are usually not involved with the perforating stage. How-
ever, at times chemicals are induced and spotted to bottom so that the
perforation process will take place within a special chemical, one usu-
ally designed to give us less damage to the formation during the perforating
91
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FORMATION
CEMENT
CASING
Figure 21.
stage. If you perforate in drilling mud you can damage the formation
around the perforation and greatly restrict flow back into the pot. So
organic acids or hydrochloric acids are sometimes used as perforating
fluids.
After we have perforated, we will usually want to stimulate the
well. This simply means to get the production rate up to a higher value
than it would be naturally. It might be damaged at this point and stim-
ulation may be necessary to get production up to an economical level.
(Figures 22, 23, and 24* shown.)
*Figures 22, 23, and 24 are courtesy of the Birdwell Division of
Seismograph Service Corporation, Tulsa, Oklahoma.
92
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Figure 22.
Figure 23.
93
-------
Figure 24.
Two methods have been used extensively for stimulation. These are
fracturing and acidizing. I am going to try to cover these very quickly.
In fracturing we pump a water-base, oil-base, or acid-base fluid
into the formation at a rate greater than it can accept; the resulting
effect is that high pressures are created, and the formation is cracked
or parted by the high pressure creating the fracture. To show what this
might look like, Figure 22 is a down hole picture of an open hole com-
pletion, (no casing across the producing zone) prior to fracturing.
Following a fracturing job we see a vertical fracture across the same
94
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interval (figure 23). You can take pictures, if you happen to have a
gas well where fluids do not interfere with the picture taking operation.
By hanging a compass below the camera, we can determine the orientation
of this fracture (figure 24). We usually find that the fractures are
vertically inclined and extend in opposite directions from the well-
bore, as shown in these three figures.
The same type of fracture occurs outside our perforated casing. We
obviously cannot see it but we have means of detecting the fracture.
The fracturing principle, then, is one of driving a wedge of
fluid into the formation, creating a vertical fracture, and extending it
out some distance so that we can make this formation produce at a much
higher rate than normally would be expected considering fluid properties,
the permeability, and pressures that are involved.
The size of fracturing treatments varies greatly, from a few
thousand gallons of fluid to the largest jobs of over a million gallons
of fluid pumped while fracturing the formation. The fractures can be
extended to several thousand feet into the formation. The massive frac-
turing treatments being performed today are designed for 2,000 feet of
penetration in each direction from the well.
The fracture that we have created, is propped open by fracturing
sand that is carried in with fracture fluid. It acts as a wedge to hold
the fracture open and provides a highly conductive channel from the
reservoir in the formation back to the wellbore. This is illustrated in
figure 25. (Figure 25 shown.)
The surface equipment used in fracturing is quite extensive, very
complicated, and very expensive. (Figure 26 shown.) In figure 26 we
see a frac treatment using six pump trucks and three blenders, one
blender to each pair of pumpers, and sand trucks dumping sand into each
blender. There are three separate units shown here. Each blender
picks up the fracturing fluid that is stored in the tanks, adds the sand
to it, and with a centrifugal feeds the frac fluid-sand slurry to two
high-pressure pumpers. The high-pressure pumps in turn pump the mixture
down the pipe and out into the formation. This would represent a typical
size treatment. (Figure 27 shown.)
95
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STORAGE TANK
FRACTURING
PRINCIPLE
Figure 25.
Figure 26.
96
-------
Figure 27.
Every so often we have massive jobs, where there might be 12 to 24
of the high-pressure pumps going. Figure 27 shows a large or massive frac
treatment. A considerable amount of investment is involved in doing a
job such as this, since each pump truck today probably costs on the order
of a quarter of a million dollars by the time you get it equipped and on
location. In this case, very large tank storage is required to hold th.e
large volumes of fluid, and many sand trucks are needed to haul the sand.
(Figure 28 shown.)
97
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ZING PRINCIPLE
LIMESTONE FORMATION
Figure 28.
FRACTURE FACE
BEFORE ACIDIZING
-: - vv ;
. f «. t
-------
Figure 30.
Figure 31.
99
-------
The other method of stimulation is acidizing, which is done one of
two ways. The acid is injected at a high rate and pressure so that the
formation fractures, or it is injected at a low enough rate and low
enough pressure to force the acid into the pore structure of the pro-
ducing formation, thus improving the draining pattern (permeability)
into the well bore from the formation itself.
In the case of acidizing at a high injection rate, we are creating
a hydraulic fracture as in a frac treatment, only rather than propping
it open with sand, the acid dissolves the limestone into which we are
injecting that acid and leaves channels along this fracture pathway to
provide for conductivity.
If we take cores from the limestone formation and look at them, we
find that they are not perfectly pure limestone; there are insoluble
materials and there are some very dense areas of limestone that dissolve
at a different rate. In passing acid over the face of this limestone we
get an irregular etched face as shown in figure 29. (Figure 29 shown.)
This helps provide an open fracture with high conductivity after the acid
job. (Figure 30 shown.)
Figure 30 shows the effect of running acid over the face of a rather
pure limestone sample (panel at right). In the center panel, 15 percent
hydrochloric acid was passed across the face and you can see the etched
channels. On the panel at the left, 28 percent hydrochloric acid is
passed across and more deeply etches the surface. At any rate, between
flow characteristics and the impurities and insolubles across the face
of a hydraulic fracture, in limestone or dolomite, we get an uneven etch
pattern. This pattern provides the highly productive channels out into
the formation and the fluid—such as petroleum--can passs easily through
this channel back to the well bore and up to the surface. (Figure 31 shown.)
Figure 31 shows a large-volume acid treatment being performed in
West Texas. A large tank volume is required to hold the large volume of
acid and displacement fluid. Blenders pick up the acid and feed the high-
pressure pumpers.
That concludes my rather brief discussion on the well completion
techniques.
100
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21 May 1975
Session i: (con.)
TECHNIQUES AND CHEMICALS
USED IN WELL DRILLING
James L. Lurnmus
Chairman
101
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TOXICITY STUDY
DRILLING FLUID CHEMICALS ON AQUATIC LIFE
C. K. Grantham and
J. P. Sloan*
Abstract
Weighting materials have been added to drilling fluids since early
in the twentieth century, and the -potential environmental impact of the
Introduction of these additives as Industrial compounds Is one of con-
temporary concern. This paper Investigates the toxlclty of density build-
ing materials used In drilling mud; It reviews the nature and purposes
of these additives; and It generally discusses results of toxlclty tests
conducted on the weighting materials used In drilling fluids. General
comments correlating other Industrial or professional applications, where
possible, are Indicated to clarify comparisons of relative safety or toxlc-
lty for humans.
INTRODUCTION
Of the various functions of drilling muds, controlling subsurface
pressures is probably the most crucial. When high pressure zones are
penetrated, the hydrostatic head of the mud column must be sufficient to
offset the varying subsurface pressures. Consequently, drilling fluid
densities must vary from 8.3 to 22.0+ pounds per gallon. These weights
are attained by adding finely ground high density materials such as barium
sulfate, calcium carbonate, and iron carbonate.
Although compounds used to weight drilling fluids are naturally
occurring minerals, ubiquitous within the earth's crust and found in
virtually every living creature, it is not current practice to dispose
of expended drilling fluids into the environment. Rather, drilling fluids
are retained as a wellbore packing, treated in holding pits, or retrieved
*C. K. Grantham and J. P. Sloan are with Magcobar Operations, Oil-
field products Division, Dresser Industries, Inc., P.O. Box 6504, Houston,
Texas 77005
103
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for later use. This study examines the environmental effects of these
minerals additives to determine if they represent a harmful or toxic im-
pact upon marine life.
Today, barite (barium sulfate) is by far the most common additive
employed in drilling fluids. It is inert in alkaline, acid, and neutral
solutions, soft, clean, low in cost, has a high density, and is commer-
cially available worldwide. Two other weighting materials that are used
(less frequently than barite) are calcite (calcium carbonate) and sider-
ite (iron carbonate). Because of the acid solubility, they are used in
oil muds and brines to give density to workover, completion, and perfor-
ating fluids.
BARITE
In drilling fluids, barite accounts for 98 percent of weighting
agents used. World production in 1974 was 4.7 million short tons
(ref. 1). Of this, S3 percent was used in drilling fluids.
The physical and chemical properties of oilfield barite must meet
specifications adopted by the American Petroleum Institute (API) con-
cerning density, particle size, and chemical hardness. Primary API
quality barite deposits are found in Battle Mountain, Nevada, and Potosi,
Missouri. Smaller deposits are mined and processed in Alaska, Arkansas,
California, Georgia, Idaho, Illinois, and Tennessee. In addition to
domestically produced barite, imported barites from 12 other countries
are used in drilling fluids. Some are processed as received, while some
are blended with domestic barites to provide a more uniform product.
Barite-weighted fluids can be formulated to approximately 22 pounds per
gallon.
In barite, the percentage of purity varies between deposits. How-
ever, most of the impurities found in crude barite are removed after
grinding and crushing by mechanical (jigging) and chemical (flotation)
processes which function on differences in specific gravity. The pri-
mary contaminants which remain in all finished barite are silica and iron
compounds; in Battle Mountain barite it is silica; in Potosi it is iron
oxide; in imports from Ireland it is iron compounds; and in Greek-pro-
duced material it is iron oxide.
104
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CALCITE
Calcite is in limited use today. In 1974, approximately 3,000 tons
were sold for weighting drilling fluids. Calcite's uses are limited
[because of the mineral's low specific gravity (2.7)] to mud weights of
less than 14 pounds per gallon. It is most often used in workover or
completion fluids for normally pressured formations and depleted or
drawn-down reservoirs. Its complete solubility in hydrochloric acid in
contrast to barite insolubility makes it very desirable for this appli-
cation instead of barite. Therefore, only the purest grades of lime-
stone are selected for oilfield application.
SIDERITE
Within the last 2 years, siderite has been introduced as an acid-
soluble weighting material for workover and completion fluids. Siderite
can be used where mud weights between 14 pounds per gallon and 18 pounds
per gallon are required. Also, lower mud weights are sometimes formu-
lated by mixing siderite with calcite. Siderite, like calcite, is desir-
able as a weighting material because of its solubility in hydrochloric
and formic acids, and its specific gravity (3.8) is higher than calcite.
ANALYSIS
This analysis considers effects of water soluble constituents of
barite, calcite, and siderite on the potential impact on marine life.
In this study, dissolved constituents were differentiated from sus-
pended metals by filtering all solutions through a 0.2-micron millipore
filter. Results of the analyses indicated that each additive was inert
and exhibited no appreciable water solubility.
A typical analysis of the water soluble ions present in commercial
Battle Mountain, Potosi, Greek, and Irish barite is given in table 1. In
tables 2 and 3, typical analyses of calcite and siderite illustrate that
these minerals, like barite, are inert and exhibit no appreciable water
solubility. Generally, elements found to be inert and insoluble in
water are not considered to be toxic upon aquatic life.
105
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Table 1. Compositional analysis of drilling
mud grade barium sulfate (barite)
Properties
Specific gravity
Barium sulfate
PH
Hater solubles*
Calcium
Magnesium
Sodium
Potassium
Barium
Copper
Zinc
Lead
Manganese
Bicarbonates
Carbonates
Hydroxides
Sulfates
Chlorides
Battle
Mountain
4.24
90.8
7.5
mg/liter
1
.8
120
0
0
0.
0.
0
0.05
200
50
0
80
60
.2
,1
Potosi
4.31
80.4
7.0
20
10
20
1
0
0
0.
0
0.
90
10
0
70
30
Irish
4.34
86.3
7.2
48
22
190
18
0
0.
0.
0
0.
40
5
0
40"0
50
1
05
1
Greek
4.13
67.7
7.0
mg/liter mg/liter mq/liter
30
10
140
7
0
0.
0.
0
0.
50
10
0
160
190
1
05
*0btained after filtering through a 0.2-micron millipore filter.
Table 2. Compositional analysis* of drilling
mud grade calcium carbonate
Properties
Specific gravity
pH
Calcium carbonate
(calcite)
Si00
2
Fe
2.7
8.3
93.6%
5.7%
.05%
Water solubles*
Calcium
Magnesium
Sodium
Potassium
Bicarbonate
Hydroxide
Carbonate
Sul fates
Chloride
160
0
15
0
730
0
0
0
50
*0btained after filtering through a 0.2-micron millipore filter.
106
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Table 3. Compositional analysis* of drilling
mud grade iron carbonate (siderite)
Properties
Specific gravity
pH
Iron carbonate (Fe(CO-)9)
O C-
Hematite (Fe20 )
2
Calcium carbonate
3.75
6.00
90.0%
3.0%
5 0%
*J • \J fo
2.0%
Water solubles*
Calcium
Magnesium
Iron
Sodium
Potassium
Bi carbonates
Hydroxide
Carbonates
Sul fates
Chlorides
EPJH
8
0
0
2
5
7
0
0
44
10
*Analysis performed after filtering through a 0.2-micron millipore
filter.
In our study of the literature, we have noted that barite, calcite,
and siderite are used frequently for varied industrial and professional
purposes, including use as medicinal compounds for human consumption.
Barium sulfate is widely employed as a contrast medium for roentgeno-
graphic purposes and as an antidiarrheal and demulcent powder (ref. 2).
These medicinal compounds are administered routinely by medical doctors
as internal medicine.
Calcium carbonate (calcite), specifically used as a gastric antacid
and antidiarrheal, is widely included in the formulations of dentifrices,
cosmetics, Pharmaceuticals, and foods (ref. 3). Iron carbonate (siderite)
is used in formulations which are ingested directly by humans and animals.
Iron carbonate also has been prescribed to treat iron deficiency anemia,
and it is used as a food supplement in cattle feed (ref. 3). Iron car-
bonate has GRAS status in the Federal Food, Drug, and Cosmetic Act,
under Food Additive Amendment GRAS 121.101 (f) (NCR No. 6-01-863).
In the geosphere, barium is the sixth most abundant trace element
and is ranked as the 17th most abundant crustal element, representing
400 ppm (ref. 4). In water, the natural barium content of rivers ranges
from 0.007-15 ppm (ref. 5); in a survey of the 100 largest U.S. cities,
barium in municipal waters is found to average 43 ppb, varying between
1.7-380 ppb (ref. 6).
107
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Barium is found in all forms of life (ref. 7) and is present in
human organs from birth. Man's skeleton itself contains an average of
2 ppm barium, muscles and lungs contain 14 ppm, and human blood plasma
contains 79 ppb barium. It is estimated that humans ingest 1.33 mg of
barium daily while excreting an equivalent amount (ref. 8), resulting
in a stabilized, not cumulative, presence of barium.
Most marine life, both plant and animal, will contain higher con-
centrations of barium than their environment (ref. 9). Marine plants
concentrate barium 1,000 times and marine animals from 7 to 100 times.
Certain life forms—for example, the exoskeleton of the rhizopod xeno-
phyofera--are made up largely of barium sulfate (ref. 8). Insoluble
barium sulfate is tolerated by all species, and a barium meal or enema
may amount to 0.5 percent of the body weight (ref. 10).
TOXICITY TESTS
To study the toxicity of barite, calcite, and siderite, an inde-
pendent research firm was commissioned to conduct standard fish toxicity
tests. Fish were the logical life form because they are the most direct
link between water and marine life. Our toxicity studies, performed
according to the Acute Fish Toxicity Test of the American Public Health
Association (APHA), show that heavy concentrations of barite, calcite,
and siderite exhibit no toxicity to fish. In this standard toxicity
procedure, Moll-ien-Lsias latipinna (mollies)--a medium tolerant fish
adaptable to both fresh and salt water—were exposed to concentrations
of chemical additives up to 100,000 ppm for 96 hours. (Any higher con-
centrations of the weighting material are considered a measure of the
concentration and not the toxicity).
From the results of these fish toxicity tests, we conclude that
barite, calcite, and siderite in concentrations up to 100,000 ppm intro-
duced into fresh or sea water do not constitute a toxic environment
(tables 4,5,6).
CONCLUSIONS
The toxicity and environmental impact of any material is necessarily
evaluated on the basis of its availability for reaction. Barite, calcite,
and siderite used as drilling fluid additives are present as insoluble
metal salts. Further, they are naturally occuring materials with a wide
108
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Table 4. Acute fish toxicity test barium sulfate (barite)
Concentration
in sea water &
fresh water
1
ppm
00,000
50,000
0
No. Of
test
animals*
10
10
10
No of test animals surviving
After 24
hours
10
10
10
After 48
hours
10
10
10
After 96
hours
10
10
10
*Moll-ienisias latipinna.
Table 5. Acute fish toxicity test calcium carbonate (calcite)
Concentration
in sea water &
fresh water
ppm
100,000
50,000
0
No. of
test
animals*
10
10
10
No. of test animals surviving
After 24
hours
10
10
10
After 48
hours
10
10
10
After 96
hours
10
10
10
*Mollienisias lat-lpi-nna.
Table 6. Acute fish toxicity test iron carbonate (siderite)
Concentration
in sea water &
fresh water
ppm
100,000
50,000
0
No. of
test
animals*
10
10
10
No of
After
hours
10
10
10
test animal
24 After
hours
10
10
10
s surviving
48 After 96
hours
10
10
10
*Mollienisias latipinna.
109
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distribution throughout the earth's crust and whose cations are present
in man from birth to death, although they are not retained by the body
above required levels.
Both marine animals and plants naturally concentrate barium from sea
water in levels several times that of the water. Results of fish toxicity
tests conducted indicated that barium sulfate, calcium carbonate, and iron
carbonate are not toxic to fish in either fresh water or sea water. There-
fore, it can be reasonably concluded that the use of these weighting ma-
terials in drilling fluids do not constitute the introduction of a toxic
substance into the environment.
REFERENCES
1. "Barite," Bureau of Mines Minerals Yearbook, U.S. Department of
Interior, 1973.
2. Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition,
Vol. 3, John Wiley & Sons, Inc., New York, 1964.
3. The Merck Index, Eighth Edition, Merck & Co., Inc., 1968.
4. B. Mason, Principles of Geochemistry, Second Edition, Wiley, New
York, 1958.
5. M. Skougstad and C. A. Horr, "Occurrence and Distribution of
Strontium in Natural Water," Geological Survey Water-Supply Paper
1496-D, U.S. Department of Interior, U.S. Government Printing Office,
Washington, D.C. 1963.
5. C. M. Durfor and E. Becker, "Public Water Supplies of the 100
Largest Cities in the United States," Geological Survey Water-
Supply Paper 1812, U.S. Department of Interior, U.S. Government
Printing Office, Washington, D.C., 1964.
7. H.J.M. Bowen, Trace Elements in Biochemistry, Academic Press, New
York, 1966.
8. H.A. Schroeder, I.H. Tipton, and A.P. Nason, Trace Metals In Man,
Strontium and Barium, Vol. 25, pp. 491-517, Pergamon Press, U.K., 1972.
9. I. H. Tipton and M.J. Cook, "Trace Elements in Human Tissues II,"
Adult Subjects from the United States, Health Phys., pp. 9 and 103, 1973.
10. API 13A Fifth Edition - API Specification for Oil-Well Drilling
Fluid Materials, American Petroleum Institute, Washington, D.C., 1969.
11. Texan International Corp. Test Report Nos. 2118, 2119, 2120, 2121,
2122, 2123, April 10-11, 1975, Keith E. James, Chief Chemist, P.O.
Box 55466, Houston, Texas 77055.
110
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DISCUSSION
DR. ELLIOTT S. HARRIS (NIOSH, CDC, DHEW, Cincinnati, Ohio): The levels
that you gave--100,000 parts per million, which is equivalent to
about 10 percent—seem to me to exceed the solubility of most of
the compounds that you were talking about.
MR. GRANTHAM: Right, they do.
DR. HARRIS: It seems, then, that you are dealing with a saturated solu-
tion in each case, no matter what your apparent total levels are.
Do you have any idea what those were, because that is really the
concentration that you are concerned with?
MR. GRANTHAM: I'm not sure when you say "... what those are."
What are the saturation levels?
DR. HARRIS: What were the concentrations that you were truly dealing
with? 100,000 parts per million is equivalent to 10 percent. You
are talking about 10 percent. I doubt if you would have a 10 per-
cent solution of any of those compounds; you are dealing with a
sludge or a slurry.
MR. GRANTHAM: Right.
DR. HARRIS: All right. I am asking what the concentrations of calcite,
siderite, and barite were in solution in each of those tests you ran,
because it is the solution concentration that you are concerned
with in toxicity tests.
MR. GRANTHAM: Right. I could probably put 1 gram in the sample and
have it saturated because of the solubility of these particular
minerals. So that is what I was saying earlier. At concentrations
of 100,000 parts per million and above, we are just talking about a
concentration effect, not a toxic effect. Any toxic material would
have saturated these concentrations. There were no toxic effects.
DR. HARRIS: Was any pathology done on the fish at the end of the results?
MR. GRANTHAM: No, there was not.
DR. HARRIS: Thank you.
DR. RICHARD S, jj£ALAN_ (University of Texas, Marine Science Institute,
Port Aransas, Texas): I have a comment to make which would perhaps
lead to some discussion later. Such organisms as the mollie, a
large fish, or a shark are not the important organisms in the sea.
Ill
-------
In fact, the major bio-mass lies in the single-cell organisms
called phytoplankton. Probably the most toxic things that you could
find about your drilling mud compositions would not be those which
are soluble but, indeed, those which are insoluble because these
increase the turbidity of the ocean. From an operating rig, there
issues a big long plume of material; whether this is drilling mud or
particulates or just what, I am not sure. It is this turbidity that
is going to cut down the amount of light in the ocean, and it will
thus force these organisms, which depend upon light (photosynthesis
is their main process) to come up to a higher level. So I would
suggest that perhaps something for the panel to discuss would be,
what would be the effects of turbidity on these important organisms.
CHAIRMAN LUMMUS: Thank you for the suggestion. We will have a panel
discussion after the first three papers when we will review, re-
capitulate, and take care of this. Then we can talk about that.
112
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FISH TOXICITY OF DISPERSED CLAY
DRILLING MUD DEFLOCCULANTS
J. W. HoTh'ngsworth and R. A. Lockhart*
Abstract
This paper investigates thinning agents used in simple sodium
montmorillonite drilling fluids to defloooulate olay particles and
maintain proper gel strengths. Thinning agents (phosphates, tannins,
special lignites, and lignosulfonates) stabilize clay dispersion by
preventing strong particle association and by decreasing the energy
needed to initiate and maintain system flow. The paper describes the
application of these thinning agents and reports the results of acute
fish toxicity tests.
INTRODUCTION
Chemical-treating agents are added to drilling muds to control and
stabilize the dispersion rheology for optimum solids carrying capacity
and viscosity. Phosphates, tannins, special lignites, and lignosulfon-
ates characterize the materials used commercially for this purpose in
the dispersed clay water-base drilling mud system. This paper describes
the application of these thinning agents (deflocculants) and reports the
results of acute fish toxicity tests.
The dispersed clay drilling mud system was selected for investiga-
tion because it is one of the most widely used water-based drilling
fluids. The principal components of this system are fresh water, sodium
montmorillonite, and one or more chemical agents for rheology control.
Additional materials are added to the basic system as required to obtain
properties for different drilling conditions.
Thinning agents are required for use in simple sodium montmorillon-
ite drilling fluids for two major reasons. Firstly, clay particles will
*Dresser Magcobar, P.O. Box 6504, Houston, Texas 77005
113
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flocculate and aggregate in the presence of electrolytes or elevated
temperature and lose their effectiveness, and secondly, excessive and
progressive gel strengths are generated by the strong electrical parti-
cle association formed when the fluid is static. Low fragile gel
strengths are desirable in a drilling fluid to support weight material
and cuttings when the fluid is not being pumped. However, as high gel
strength develops, excessive pressure is required to induce flow, often
causing formation damage and lost returns. These limitations are over-
come by controlling and stabilizing the dispersion rheology with thin-
ning agents which are modifications and salts of four compound types:
phosphates, tannins, special lignites, and lignosulfonates. (Our
estimate of total industry consumption of these agents in the United
States, projected for 1975, is indicated in figure 1.)
These agents stabilize a montmorillonite clay dispersion by pre-
venting strong clay particle association and decreasing the energy to
initiate and maintain system flow.
PHOSPHATES
Although numerous phosphate salts and organo-phosphates have been
employed as dispersed clay drilling mud thinners, at the present time
only three types are commonly used: sodium acid pyrophosphate, sodium
tetraphosphate, and sodium hexametaphosphate. At low concentrations,
these dehydrated phosphates are effective thinners for fresh water
sodium montmorillonite dispersions. Normal field dosage is between 0.1
and 0.5 pounds of phosphate salt per barrel of drilling mud.
The rheological response of a sodium montmorillonite dispersion
treated with sodium acid pyrophosphate (figure 2) is typical of thinner
treatment in general, and in particular of all phosphate salts. Appar-
ent viscosity is reduced substantially and gel strengths are controlled
in a desirable range. For this demonstration, no effort was made to
adjust pH, although alkaline agents usually are added to dispersed clay
drilling muds to increase the thinner activity and control corrosion
problems associated with low pH. The phosphate-thinned mud pH is
controlled to 7-8.5.
114
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Dehydrated phosphate thinners are limited to low temperatures
(below 200° F) and to fresh water applications because of their tendency
to revert to ortho phosphates, especially at elevated temperatures.
Thinning control is lost and insoluble salts formed if calcium contamina-
tion occurs. Often phosphates are employed in muds for reducing fluid
hardness.
TANNINS
Tannin compounds are acidic organic substances extracted from
various plants, including the quebracho, wattle, mangrove, hemlock, and
redwood trees. Like the phosphate thinners, numerous tannins and tannin
blends have been widely used as dispersed clay mud thinners. These
materials were more prevalent before the advent of lignite lignosulfonate
mud systems used today. Tannin agents require a high pH for optimum
performance and lack adequate thermal stability for drilling today's
deeper wells. However, their electrolyte contamination tolerance is
superior to the phosphate compounds, and their oxygen scavenging ability
is often utilized to combat oxygen corrosion problems.
Tannin agents are used in much higher concentrations than phosphates
for drilling mud rheology control. The amount necessary to stabilize
drilling mud rheology is a function of numerous variables, but will be
dependent largely on the system's hydratable clay mineral concentration.
A concentration of 2-10 pounds per barrel of tannin compound is a typi-
cal field mud requirement.
LIGNITE
Lignite for treating drilling mud is mined principally in North and
South Dakota and differs from normal or fuel grade lignite in its high
humic acid content and caustic solubility. (The optimum weight ratio of
caustic to lignite in fresh water muds is approximately one to eight.)
Lignite is sometimes used alone with sufficient caustic for solubility,
but more often in conjunction with other thinners. Mixtures of lignites,
alkalies, and/or tannins, as well as sulfonated, sulfomethylated, and
metal chelated lignites have all been used successfully for treating
drilling muds.
117
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Drilling mud grade lignite is a polymeric humic acid with a complex
and extremely variable organic structure containing about 10 percent
inorganic inert solids. Lignite and its various derivatives are normally
used in concentrations from 2 to 12 pounds per barrel of drilling mud.
Lignites demonstrate extreme thermal stability. Drilling muds
using lignite/caustic for rheology control may be prepared that are
capable of withstanding 300° F over extended periods and 400° F for a
short time (16 hours). Unfortunately lignite/caustic solutions are sub-
ject to electrolyte sensitivity, and are precipitated by calcium contami-
nation. Chemically modifying lignite often improves its electrolyte
tolerance, but fails to prevent precipitation. Precipitated lignite
usually continues to function as a fluid loss additive although its
thinning properties are absent.
LIGNOSULFONATES
The lignosulfonate category includes simple lignosulfonate salts,
such as calcium or sodium lignosulfonates, and the modified or complexed
chromium and ferrochrome lignosulfonates. Simple lignosulfonates are
used infrequently as emulsifiers and for treating specialized lime-
caustic muds. Modified lignosulfonates are the most widely used and
versatile thinning agents available today. They possess good electro-
lyte tolerance, work well over a wide pH range, withstand most drilling
fluid levels of calcium contamination, and have exceptional thermal
stability. They are routinely used in water-base drilling muds at
concentrations varying from 2 to 10 pounds per barrel, to temperatures
approaching 400° F.
Both chromium (CLS) and ferrochrome (FCLS) lignosulfonates, the
most commonly used deflocculants, are prepared by the dichromate oxi-
dation of sulfite pulp lignosulfonate liquor. Earlier paper manufacturers
routinely burned these components for their minimal fuel value, while
others were issued permits to discharge excess quantities in plant waste
water streams. The use of lignosulfonates as a valuable chemical compo-
nent in drilling muds virtually eliminated this waste.
The lignin and lignosulfonate precursor of the modified CLS and
FCLS products have been studied extensively. Lignin is a natural
118
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polymer recovered from wood in paper pulping operations probably originating
from phenylpropane monomers. The most predominate lignin monomer is
coniferyl alcohol. Polymerization and cross-linking occur at any number
of possible sites to add to the complexity of the material. The sulfite
pulping process preferentially sulfonates the alpha carbon on the propyl
side chain, or the benzylic positions in the polymer, resulting in a
water soluble, complex benzylsulfonic acid. This sulfonation also frees
some primary alcohols by virtue of benzyl ether cleavage. This is the
site of most of the oxidation during the subsequent exothermic oxidation
by dichromate giving the chromium modification (figure 3). The resulting
carboxylic, phenolate, and sulfonate anionic functions give good chelating
sites for the reduced chromium (III) cation.
The exact nature of the resulting complex is not clearly defined at
present; however, it has been definitely shown by McAtee and Smith (ref.
1) that the chromium is firmly chelated such that it may not be removed
from the lignosulfonate complex even by strong ion-exchange resins, and
that chromium is present in the trivalent oxidation state. Evidence has
been given by Jessen and Johnson (ref. 2) and supported in the McAtee
and Smith study (ref. 1) that the chrome (III) may also interact with
the planar surface of montmorillonite clays by a base-exchange mechanism.
This indicates that chromium (III) that is added to a drilling fluid, in
the form of a chrome lignosulfonate, is either strongly associated with
the lignosulfonate or montmorillonite, such that it does not enter into
additional reactions.
TOXICITY STUDIES
Present environmental concerns stress the potential effect that
drilling mud chemicals may have if released. Drilling mud thinners
are supplied in solid, essentially dust-free form, and therefore spills
on land may be removed immediately. Release to an aqueous environment,
however, would be difficult to contain because of the product solubility
properties. Since these materials are used both on land and offshore,
we have tested four commercial products representative of the four
classes of drilling mud thinner compounds previously discussed to deter-
mine their potential effect on fresh water and sea water fish.
119
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Table 1 summarizes the study results. The fresh water and sea
water tests were conducted with Mollienisias latipinna in accordance
with the American Public Health Association Standard Methods (ref. 3).
Mollienisias latipinna was selected for this study because it has medium
sensitivity and can be adapted to fresh and sea water environments.
*
Median Tolerance Limits were established for each thinner after 24, 48,
72, and 96 hours.
This particular study indicates that the tannin class, exemplified
by quebracho, has a considerably lower median tolerance limit than any
of the other products tested. There was no reason to anticipate this
result since high concentrations of tannin compounds are frequently
found in natural water systems that flourish with aquatic life. It is
suspected that the oxygen scavenging characteristic of this material may
have been a factor in this static test procedure. Additional studies
have been initiated on the tannin compounds to clarify these results.
Sodium acid pyrophosphate shows fairly low median tolerance limits in
fresh water, and chrome lignosulfonate and lignite demonstrate the least
toxicity in both environments at all time intervals.
In earlier toxicity studies (ref. 4), test materials were separated
according to relative toxicity. Substances rated nontoxic killed no
test animals, materials designated low-toxicity killed some test animals
in concentrations of 500 to 7,500 ppm, and toxic-rated substances killed
more test animals at 70 to 450 ppm concentrations. According to these
definitions of toxicity, none of the materials tested for this paper
fell in the high toxicity category. Phosphate, lignite, and chrome-
lignosulfonate all belong in the low-toxicity group.
SUMMARY
The toxicity results presented here are conclusive with regard to
the specific test conditions cited and are indicative of the general
fish toxicity behavior of these compounds. The median threshold limits
*
Median Tolerance Limit (MTL) is the concentration of material
tested in which 50 percent of the test animals survive for a specified
period of exposure. Thus a high MTL indicates low toxicity, and a low
MTL indicates high toxicity.
121
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determined for quebracho, although sufficiently high that it can not be
classed as highly toxic, were lower than expected and cannot be explained
at present. All the other products tested, including the most widely
used drilling mud thinners on the market today, are classed as low-toxi-
city agents.
The dispersed clay-drilling muds are expected to continue their
dominance of the total drilling fluid market. This study suggests that
the thinner compounds, which are a vital part of this system, do not
offer a serious environmental threat with regard to fish toxicity.
Although there is no evidence that any of these materials have been
responsible for any environmental damage, it is in the interest of all
parties concerned to continue research programs in this area.
REFERENCES
1. J. L. McAtee, and N. R. Smith, J. Colloid and Interface Science, Vol
29 (1969), pp. 389-398.
2. F. W. Jessen and C. A. Johnson, Soc. Petroleum Eng. J., Sept. 1963,
pp. 267-273.
3. M. J. Taras, A. E. Greenberg, R. D. Hoak, and M. C. Rand, "Toxicity
to Fish," part 231, Standard Methods for the Examination of Water
and Waste Water, 13th edition, American Public Health Association,
New York, 1971.
4. F. M. Daugherty, Jr., "Effects of Some Chemicals Used in Oil Well
Drilling on Marine Animals," Sewage and Industrial Wastes. Vol. 23,
No. 10 (October 1951).
123
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EFFECT OF DRILLING FLUID COMPONENTS
MIXTURES ON PLANTS AND SOILS*
R. W. Miller and S. Honarvart
Abstract
Using undrained, greenhouse pot techniques, 51 drilling fluid (mud)
components were tested for their effects in reducing plant growth. Green
beans and sweet corn were the test plants; the soil was an excellent,
slightly acidic, uncultivated, silt loam soil (Cumulic Haploxeroll).
Each component was tested at two addition rates (high and low). The low
rates are typical concentrations used in the field. Significant bean
yield increases occurred at normal use rates with asbestos, VAMA, and
sodium dichromate. No statistically significant reductions of plant
yield occurred in soil at normal use rates with asphalt, barite, benton-
ite, calcium lignosulfonate, sodium polyacrylate, a modified tannin (Des-
co), a nonfermenting starch, ethoxylated nonyl phenol (DME)3 a filming
amine, gilsonite, a Xanthan gum, para formaldehyde, pipe dope, hydrolyzed
polyacrylamide, sodium acid pyrophosphate, sodium carboxymethyl cellulose,
sodium hydroxide, a sulfonated tall oil, and a sulfated triglyceride (Torq-
Trim).
A statistically significant (5 percent level) reduction in yield in
soil at normal use concentrations occurred with diesel oil, large alcohol,
guar gum, a plant-synthetic fiber mix (Kwik-Seal), lignite, potassium,
chloride, pregelatinized starch, a modified asphalt (Soltex), and an iron
chromelignosulfonate.
When individual components were mixed at normal rates in an equal
volume mixture of soil and liquid mud, slight growth reductions occurred
with sodium dichromate and the plant fiber mix. Severe growth reductions
*Research supported by Utah Agricultural Experiment Station, Logan,
Utah, and the Executive Committee of Drilling and Production Practice of
the American Petroleum Institute.
tR. VI. Miller, Professor of Soil Chemistry; S. Honarvar, graduate
student; Utah State University, Logan, Utah.
125
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occurred with sodium 'hydroxide. Higher1 application rates had greater
reduction of plant growth. However, these rates are not typical of nor-
mal use.
Reclamation procedures, although not attempted yet, would seem to
be relatively simple, with the exception perhaps of the problem with
diesel oil, and they involve leaching, additions of gypsum, and time.
INTRODUCTION
Oil well drillers employ a drilling fluid (drilling mud) to carry
drilling rock wastes out of the bore hole. This mud is composed of
barite (BaSO.), a small amount of bentonite, and various chemicals which
produce in the mud certain desirable properties. Some of these properties
are an increased carrying capacity, control of fluid loss, stabilizer of
unstable shale layers, torque reducer, and water viscosifier. A wide var-
iety of materials are used in the mud for these purposes.
The recent environmental awareness in the United States has prompted
well drillers to consider problems of revegetation on the aftermath of
drilling. The variety of fluid components used, the climatic variations,
soil differences, and desired plant species at various drilling sites in-
crease the amount of information needed in order to make accurate conclu-
sions.
This study is a first look at drilling fluid components which might
hinder to some extent the growth of plants. Reclamation activities have
not yet been attempted in the research.
REVIEW OF LITERATURE
No available paper in English describing research on the toxicities
to plants of drilling mud components was found. Therefore, information on
individual components was sought using a different approach.
The following categorization of the 31 components used in this study wa:
used as a guide to the review of literature.
126
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1. Materials that might produce soluble salt effects
Barite, potassium chloride, sodium acid pyrophosphate, sodium
dichromate, and sodium hydroxide.
2. Materials of petroleum origin
Asphalt, diesel oil, pipe dope, modified asphalt
3. Minerals, coal, or related natural solid deposits
Asbestos, barite, gilsonite, and lignite.
4. Organics of plant origin other than petroleum or coal-like
materials
Modified tannin, nonfermenting starch, guar gum, Xanthan gum,
iron chromelignosulfonate, plant-synthetic fiber mix, calcium
lignosulfonate, pregelatinized starch, and sulfonated tall oil.
5. Synthetic and miscellaneous organic materials
VAMA, sodium polyacrylate, modified tannin, nonfermenting starch,
ethoxylated nonyl phenol, large alcohol, filming amine, plant syn-
thetic fiber mix, paraformaldehyde, hydrolyzed polyacrylamide,
sodium carboxymethyl cellulose, and a sulfated triglyceride.
Berstein (ref. 3) listed the tolerance to salt of garden (sweet) corn
and green beans as given in table 1.
Table 1. Tolerance to salt of corn and green beans
Conductivity (ymhos/cm) at which Green Sweet
plant yield will be reduced: beans corn
ymhos/cm ymhos/cm
10 percent 1.4 2.5
25 percent 2.0 4.0
50 percent 3.0 6.0
100 percent (plant death) 5.0 8.0
127
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Of the materials considered as potential salt problems, barite is
too insoluble to be a hazard. The other four materials are all soluble
enough to cause a salt hazard if they are added in large enough amounts.
The sodium hydroxide will react in soil to form insoluble metal hydroxides
or form water with acids; the sodium will adsorb to clays and organic
matter in some part. The large amounts of potassium chloride used should
cause problems in plant growth as a result of soluble salt concentration.
Of the remaining 27 materials, insufficient literature was available
to suggest the presence of materials toxic to plants. The most prominent
hazard, diesel oil, has been long used as a herbicide or a carrier for
herbicides. Baker (ref. 2) indicates that diesel oil contains materials
of carbon chain lengths about C,. to C,g (boiling range about 250° to
350° C).
The precise action of oils on growth is mostly speculation. The oil
is known to penetrate cells and plant organs in general. Some scientists
have speculated that the oil penetrates the "oil-miscible" cell membranes
eventually destroying their semipermeable nature (refs. 8,14,16). In con-
trast, the asphalt-like residues seem not to be toxic to plants and, in
fact, to be beneficial to plants to some extent, although the beneficial
effects are usually not great (refs. 7,12).
Black walnut plants have a phytotoxin called juglone (a 5-OH-l, 4-
naphthoquinone) (refs. 4,10). Davis (ref. 4) reported juglone in all parts
of the plant. This could be a problem substance in the plant synthetic
fiber mix.
The lignosulfonates are large, organic molecules containing many aro-
matic units. Upon hydrolysis (decomposition), intermediate breakdown pro-
ducts might be toxic. Decomposition of tannins might produce phytotoxins
by a similar process.
Chromium (Cr) is a potential toxin. The normal soil content is near
100 parts per million (ppm); this study will be adding in the high but
unusual rates up to nearly 4,000 ppm Cr (ref. 5). At levels of 1,370 to
2,740 ppm Cr citrus had chlorosis (ref. 15). In greenhouse studies, oats
were stunted, and had narrow, reddish-brown leaves with necrotic (drying)
areas (ref. 15).
128
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EXPERIMENTAL MATERIALS AND PROCEDURES
The materials studied and their rates are given in table 2. A brief
list and discussion of each material is given in the following list.
p
1. Asbestos or Super Visbestos (chrysotile). Asbestos, a natural
mineral, is used to increase carrying capacity, flow properties, and
stabilize gelation of bentonite. The chemical compositon (H.MgoSipOg)
suggests that asbestos should not adversely affect plant growth.
2. Asphalt (blown). Asphalt is used as a differential sticking agent,
shale stabilizer, torque reducer, and fluid loss control agent. Pre-
pared by air oxidation of petroleum residium, asphalt is composed of
hydrocarbons (saturates, naphtheme aromatics, polar aromatics, and
asphaltene) of molecular weights from 600 to over 4,000.
D
3. VAMA or Ben-Ex . VAMA is used as a bentonite extender and selective
flocculent to remove cuttings from the cycled mud. Originally mar-
keted as a soil conditioner, VAMA is a copolymer of vinyl acetate and
maleic anhydride.
4. Calcium Lignosulfonate. This material is used primarily to aid disper-
sion of clays. Gaeliurn lignosulfonate is a substituted phenol propane:
5.
H2COH — CH -
Rl
OCH
1
1
— 0
-R2
S03HCa OCH3
The R-, and R9 may be additional phenol propane molecules.
R
Sodium Polyacrylate (Cypan ). Sodium polyacrylate is used to control
fluid loss by forming a clay-polymer network at the bore wall. It is
a polymer of acrylonitrile made to the desired molecular weight. It
resists microbial attack.
CH9 — CH — CH9 — CH — CH0 — HC
2 I 2 I 2 I
o=c-o
c=o
I
NH0
0-C=0
129
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Table 2. Drilling mud components and their concentrations added
to soil for observing effects of components on plant growth. Rates are
given in pounds per barrel (Ib/bbl) and in grams per 1.6 liters of soil,
For the test soil, 1.8 kg of soil equalled about 1.6 liters.
Levels tested
Mud Component
Ib/bbl of soil
(proposed)
g/1.8 kg of soil
(actually used)
Asbestos (Super VisbestosR)
Asphalt (blown)
Vinyl acetate polymer (Ben-Ex )
Calcium lignosulfonate
Sodium polyacrylate (CypanR)
Modified tannin (Desco*)
Non fermenting starch (DextridR)
Ethoxylated nonyl phenol (DMER)
2 and 5
1 and 5
0.05 and 0.2
3 and 20
0.5 and
0.25 and
1 and
0.5 and
1.5
3
10
3
Diesel oil
Large weight alcohol
405R)
fossil res in)(Super
(Drillaid
Filming amine (Drillaid 412R)
Gilsonite (
Lube Flow
la and 10a
0.2 and 1
0.1 and 0.3
1
and
8.18 and 20.5
4.09 and 20.5
0.21 and 0.82
12.28 and 81.9
2.05 and 6.14
1.02 and 12.3
4.09 and 40.9
2.05 and 12.27
18 and 180
0.82 and 4.09
0.41 and 1.23
4.09 and 20.5
Guar gum (Gendril Thik")
Xanthan gum (Kelzan-XCR)
Plant-synthetic fiber mix (Kwik-SealR)
Lignite (LigcoR)
Para formaldehyde
Pipe dope
Potassium chloride
Pregelatinized starch (corn starch)
Iron chrome! ignosulfonate (Q-BroxinR)
Hydrolyzed polyacrylamide
(Separan AP-273R)
Sodium acid pyrophosphate
Sodium carboxymethyl cellulose
Sodium di chroma te
Sodium hydroxide
Modified asphalt (SoltexR) R
Sulfonated tall oil (Witconnate 1840 )
Sul fated triglyceride (Torq-TrimR)
Barite
Bentonite
1
0
5
2
0
0
10
1
3
0
0
0
0
1
0
0
0
100
7
.5
.1
.1
.5
.1
.5
.5
.5
.5
.5
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
6
2
50
10
0.3
0.3
30
10
20
2
0.5
1.5
3
5
2
3
1.5
350
35
4.
2.
20.
8.
0.
0.
40.
4.
12.
2.
0.
2.
2.
4.
2.
2.
2.
364C
28.
09
05
5
18
41
41
9
09
28
05
41
04
05
09
05
05
05
6
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
and
24.
I82b
40.
1.
1.
122.
40.
81 .
8.
2.
6.
12.
20.
8.
12.
6.
955C
135^
5
18
9
23
23
7
9
9
18
05
14
3
5
18
3
14
^Percentage by weight.
b!82 g/1.6 kg of soil.
^364 g/1.6 kg of soil and 955 g/1.2 kg of soil.
d!35 g/1.7 kg of soil.
130
-------
p
Modified Tannin (Desco ). The only data available is from J. L.
Lummus (Amoco Products Co.) describing Desco as a "modified tannin
neutralized with an alkaki." Tannins are large, complex molecules
containing ring alcohols, large ring acids, and many less well-known
organics.
Nonfermenting Starch (Dextrid ). Dextrid is an adsorptive colloid
designed to limit the rate of hydration of shale formations and serve
as a filtration control agent for permeable formations. Its composi-
tion is described in US. Patent 3,256,115. It is a microbially
stable, gelatinized, starchy flour with from 1 to 5 percent paraformal-
dyhyde and 1 to 5 percent of a compound with the following structural
formula:
Where R-, and R2
are selected
chloride (Cl)
and H
8. Ethoxylated Nonyl Phenol (DME ). DME is an oil-in-water emulsifier.
9. Diesel Oil. Common diesel oil is an intermediate molecular weight
petroleum distillate. Used number 2 diesel oil.
10. Large Weight Alcohol (Drillaid 405R). Drillaid 405, a diesel oil
replacement, is a private formula and is unavailable to the writer.
It is said to be biodegradable and a nonpollutant. It reduces torque,
drag, and differential pressure, and aids in hole stability.
p
11. Filming-Amine, Inhibitor (Drillaid 412 ). Drill aid 412 is an oil-sol-
uble, water dispersable, organic, filming-amine inhibitor used to
retard hydrogen sulfide and oxygen corrosion of drill pipe. This
material's composition is a private formula and unavailable, but con-
tains amine salts. The material is used as a coating on drill pipe
rather than by treating the drilling mud.
12. Gilsonite (Super Lube Flow ). Gilsonite is used for mechanical sta-
bilization, chemical inhibition, and surface hydration. It is "one
of the natural fossil resins." According to the information from
131
-------
the supplier, it is listed in "Foods and Drugs" as being safe in
food-contact surfaces.
D
13. Guar Gum (Gendril Thik ). Guar gum is used as a water viscosifier.
It is ground endosperms of Cyamopsis tetragonc/lobus (a legume called
Guar or cluster bean). The molecule is a straight-chain mannan
having single branches of galactose. Its average molecular weight
is 22,000.
P
14. Xanthan Gum (Kelzan-XC ). Kelzan is used as a viscosifier in dril-
ling fluids. It is a xanthan gum produced by fermentation of a car-
bohydrate by the bacteria Xanthanomas campestis.
15. Plant-Synthetic Fiber Mix (Kwik-Sea1R). A material added to seal
porous geologic formations. Kwik-Seal is a blend of ground walnut
shell, two vegetable fibers, two synthetic fibers, and cellophane.
n
16. Lignite (Ligco ). Lignite is used to emulsify oils in water-based
drilling fluids and to control filtration rates of these fluids.
Ligco is a ground lignite which is a low rank of coal classified
between peat and subbituminous coal.
17. Paraformaldehyde. Paraformaldehyde is used as a preservative in con-
junction with starch. It is a polymer represented by (CH90) .
C. A
18 Pipe Dope. Pipe dope is a partially refined petroleum oil thickened
with a calcium soap of abietic acid with 10 percent red lead oxide
dispersed in it.
19. Potassium chloride (KC1). Potassium chloride is used in combination
with other chemicals, such as Separan AP-^73. It helps stabilize sen-
sitive shale formations encountered while drilling.
20. Pregelatinized Starch. This starch is an amylose carbohydrate (sugar
units) with 7.5 percent protein.
n
21. Iron Chromelignosulfonate (Q-Broxin ). Q-Broxin is used primarily as
a thinner or dispersant to lower the apparent viscosity and gel
strength of mud. Caustic soda is usually also used giving a mud of
pH 9 to 10. Additional composition is given in U.S. Patent 2,935,504.
n
22. Hydrolyzed Polyacrylamide (Separan AP-273 ). At low concentrations,
25-50 ppm (about 0.008-0.018 Ib/bbl), Separan is a flocculant for
maintaining a low-solids content. At rates of 1,000 or 3,000 ppm
132
-------
(0.3 to 1.0 Ib/bbl) in combination with 3 to 15 percent KC1, Separan
stabilizes water-sensitive shale formations encountered while dril-
ling. It has a molecular weight of 3 x 10 or greater and a formula
as follows:
CH
COOH
CH,
/0.3
CH — CH,
CONH,
'2 /0-7J n
Separan AP-273 is a partially hydrolyzed polyacrylamide and is similar
to hydrolyzed polyacrylonitriles (HPAN), differing mostly in extent
of hydrolization. HPAN has been used to form stable soil structure.
It is manufactured by Dow Chemical Company and supplied by the Shell
Development Company.
23. Sodium Acid Pyrophosphate (SAPP). SAPP is used as a reducer of vis-
cosity. Its composition, Na^H^PoOy, does not indicate any reason for
damaging action on plant growth.
24. Sodium Carboxymethyl Cellulose (SCMC). SCMC is used to reduce fluid
loss. It is composed of 70 to 99 percent sodium carboxymethyl cellu-
lose, and its formula is R-0-CHpCOONa, where R=glucose units in
chains.
25. Sodium Pi chromate. The reason for employing sodium dichromate is not
yet known, but is presumed to be for making the salt of lignosulfon-
ates which help increase clay dispersion. Its chemical composition
is Na2Cr207.
26. Sodium Hydroxide. Sodium hydroxide, NaOH, is a strong base. It is
a well-known soil dispersant and aids in the breakdown of soil aggre-
gates. It is often used in drilling muds with calcium lignosulfonate,
lignite and Q-Broxin, resulting in a mud of pH 9 to 10.
27. Modified Asphalt (SOLTEXR). Soltex is a modified, high-molecular-
weight hydrocarbon, possibly a sulfonated asphalt.
28. Sulfonated Tall Oil (Witconnate 1840R). Witconnate 1840 is a mixture
of resin acids (35-40 percent) and fatty acids (50-60 percent) from
acid treatment of pine wood.
133
-------
p
29. Sulfated Triglyceride (Torq-Trim ). Torq-Trim is used to improve
lubricity. It is a sulfated triglyceride containing aliphatic and
short-chain alcohols.
Greenhouse Procedure
The soil used is the Dagor silt loam series, a dark-colored soil
under "scrubby maple". In the U.S. Soil Classification system, Dagor
silt loam is a Cumulic Haploxeroll, fine-loamy, mixed, mesic. It has
a deep Al horizon, 0 to 34 inches. Its general properties are given in
table 3.
The study was done in two parts. Part A had individual mud compo-
nents added only to soil. Part B, done later only on materials causing
reduced plant growth, had individual mud components added to the liquid
mud, which was then added to an equal volume of the soil. The mixture
was dried, crushed, mixed, and planted. The soil-mud volume of Part B
was equal to the soil volume of Part A and contained the same weights of
components per 1.6 liter. Pots had no drainage but were watered by add-
ing water until the pot was a predetermined weight. Weight of plant
growth was estimated to allow increased pot weight with plant size.
Fertilizer nitrogen and phosphorous was added to eliminate these nutrients
as growth restrictions.
Because of timing in arrival of fluid components, several dates of
planting were involved. Each planting had its own set of controls. In
most plantings (except Part B-corn), natural light was the only light
source.
3
The mud base used was: 294 cm of water plus 13 g of bentonite,
mix well; after overnight, add 194 g of barite. Plants used were green
beans and sweet corn.
Analytical Tests
Soluble salts were determined by electrical conductivity of the sat-
uration past extract (ref. 6).
Soil pH on treatment and control samples was measured on a 0.01 Molar
CaCl?:soil suspension which results in pH values about 0.5 pH unit lower
134
-------
Table 3. Characteristics of Dagor silt loam
Item Value
Clay 10%
Oxidizable organic matter content 8.1%
Soil pH, paste 6.2%
Soil pH, 1:2 soil :0.01 M. CaCU 6.0
Cation exchange capacity 34.3 me/lOOg
Field capacity (1/3 bar suction) 34.7%
Wilting percentage (15 bar suction) 16.8%
Available phosphorus 130 kg/ha (high)
Available potassium 1,150 kg/ha (high)
than paste pH values (ref. 13). Soil characterization pH values were done
on a soil paste,' a standard procedure (ref. 13).
Moisture retentions values for one-third bar and 15 bars of moisture
suction were obtained on pressure plates using standard procedures (done
by the Utah State Soil Testing Laboratory).
Organic matter was measured by the Walkley-Black method of wet oxida-
tion with potassium dichromate and sulfuric acid and back titration with
ferrous sulfate (ref. 1).
Cation exchange capacity values were done by the Utah State University
Soil Testing Laboratory using the Standard ammonium acetate extraction and
measurement of the replaced ammonium ion. Exchangeable K was measured on
this extract.
Available P was done by the sodium bicarbonate extraction procedure of
Olsen and Dean (ref. 12).
Chromium was analyzed using an atomic absorption spectrophotometer
jfter extraction of chromium by wet digestion of plant material with nitric-
Derchloric acid or with 1:10 soil to 2 N^ KC1 extraction of chromium from
soils.
135
-------
RESULTS
Evaluation of the effects of added mud components on plant growth was
a combination of visual observations, photographic records, arid yield
values. Dry weight values are given in tables 4 and 5 for Part A (com-
ponents added to soil only). The "low rates" are the typical (normal)
concentrations that would result if the components were in muds and then
added to and mixed with an equal valume of soil. Three materials at the
normal rates increased bean growth, five caused a slight but statistically
significant reduction, and six caused even greater growth reductions.
The materials which caused reduced plant growth in soil alone were
then added to the drilling mud base and this mixture added to an equal
volume of soil, then dried, mixed, and planted. Yields are shown in table 6.
Table 4. Oven-dry yield weights, in grams per pot, of green beans
and sweet corn grown on Dagor silt loam with individual mud component
added. Each value is an average of two replication; the control
value an average of 9 for beans and 10 for corn (late planting).
Beans
Material
Nonfermenting starch
Ethoxylated nonyl phenol
Pipe Dope
Iron chrome! ignosulfonate
Sulfonated tall oil
Sul fated triglyceride
Control (soil only)
LSD (Controls vs. treatments at 95%)
LSD (Controls vs. treatments at 99%)
Low
rate
23.5
18.0
21.5
17.0
21.5
19.5
21.
6.
8.
High
rate
7.0a
23.5
20.0
6.0a
16.0,
10. Oa
1
05
25
Corn
Low
rate
28.5
38.0
34.5
26. Oa
31.0
25. 5a
36.
7.
10.
High
rate
2.0a
35.0
19. 5a
6.0a
23. 5a
11. Oa
9
78
59
aHighly significant yield decrease (99% confidence level).
Statistically significant yield decrease (96% confidence level).
136
-------
Table 5. Oven-dry yield weights, in grams, per pot, of green beans and
sweet corn grown on Dagor silt loam with individual mud component added.
Each value an average of two replications; the control value an average
of 20 replications (early planting).
Beans
Material (component)
Asbestos
Asphalt
Bar He
VAMA
Ben ton He
Calcium lignosulfonate
Sodium polyacrylate
Modified tannin
Diesel oil
Large weight alcohol
Filming amine
Gil son He
Guar gum
Xanthan gum
Plant-synthetic fibers mix
Lignite
Paraformaldehyde
Potassium chloride
Pregelatinized starch
Hydrolyzed polyacryl amide
Sodium acid pyrophosphate
Sodium carboxymethyl cellulose
Sodium dichromate
Sodium hydroxide
Modified asphalt
Controls (soil only)
LSD (controls vs treatments at 95%)
LSD (controls vs treatments at 99%)
Low
rate
29. 5a
27.0
25.0
29.5
27.0
26.5
25.0
28.0
13'°b
21. 5b
25.5
27.5
9.0C
27.5
16. 5D
21.5
28. 0_
3'°b
20. 5b
27.5
26.0
22.5
20. 5a
25.5
24.5
25
3
5
High
rate
25.0
27.0
24.5
30.0
23.0
10. Oc
26.5
22.5
3.0C
22.5
26.0
29.0
6.5C
25. Ob
10.5°
24.5
24.5
0 b
16. Ob
23.0
27.0
29.0
2-5r
4.0C
29.0
.6
.89
.18
Corn
Low
rate
45.0
45.0
46.5
48.5
41.5
47.5
46.0
41.0
14.5C
44.0
40.0
42.0
42.0
47. 0_
26. Oc
48.0
46.5
5 5C
h
38. 5b
48.5
48.5
45.5
40.0
46.5
38.5°
47.
7.
10.
High
rate
45.0
42.0,
38.0°
50.5
40.5
13. Oc
46.0
33. 5C
1.0C
17. 5b
39.5°
46.0
2.0C
34. 5C
2.0C
45.0
50.5
0.5C
2.0
46.0
45.5
45.5
2.0C
21. (£
36. 5C
3
66
17
a Statistically significant yield increase (95% confidence level).
b Statistically significant yield decrease (95% confidence level).
c Highly significant yield decrease (99% confidence level).
137
-------
DISCUSSION OF RESULTS
Three factors should be kept in mind as the results of this study
are considered. First, the "low rate" is the normal concentration used
in field work; second, no leaching of the soil was permitted; and third,
no ameliorating chemicals were added.
Although many of the materials tested in soil in Part A caused some
growth reduction, when mixed one volume of soil to one volume of mud the
results were somewhat different. The modified tannin (Desco} actually
increased bean growth at normal use rates (low rate). Also, no effects on
growth were observed at normal used levels from additions of nonfermenting
starch (Dextrid), modified tannin (Desco), the large weight alcohol (Drill-
aid 405), guar gum, pregelatinized starch, and the sulfated triglyceride
(Torq-Trim) (see table 6); growth reductions had occurred in soil only.
The materials which caused plant growth reductions in the soil-mud
mixture may not cause similar problems in the field because of a number
of restrictions inherent in the greenhouse procedure. These restrictions
and limitations need to be considered.
The absence of drainage, which would be expected to occur in the
field, eliminates leaching of any soluble toxic materials. Soluble salts--
potassium chloride, sodium dichromate, and sodium hydroxide--are readily
removed in large part by small amounts of leaching water. Leaching plus
the addition of gypsum or sulfur will help replace adsorbed sodium and
remove it from the profile, thus eliminating some or all of the problem
due to sodium hydroxide.
The majority of known organic materials listed in the literature as
phytotoxins and which seem possible to be released from the studied com-
ponents are water-soluble substances. These organic compounds should
move with water leaching down below the soil profile. Even without
leaching, these phytotoxic compounds should decompose quite rapidly (with-
in a year) and, at the worst, be temporary problems to plant growth.
Also, keep in mind the conditions of the tests: Warm temperatures
and rapid, intense growth; soil-mud mixtures of about equal volumes of
138
-------
Table 6. Oven-dry yield weights, in grams per pot, of green beans and
sweet corn grown in Dagor silt loam and the base mud mixture with the
individual mud component added. Each value an average of two replica-
tions; the soil control values an average of 12 for beans 11 for corn;
and soil-mud control values an average of 11 for beans, 12 for corn.
Material
Calcium lignosulfonate
Nonfermenting starch
Modified tannin
Diesel oil
Large weight alcohol
Guar gum
Plant-synthetic fibers mix
Lignite
Potassium chloride
Pregelatinized starch
Iron chrome! ignosulfonate
Sodium dichromate
Sulfated triglyceride
Controls, soil + mud
Controls, soil only
Beans
Low
rate
9.8a
13.3
15. Oc
6.3b
12.0 1
12.4
10.7
9.2.
0 b
9.9a
10. Oa
8.9b
10.4
12.2
10.7
High
rate
°b b
6.7b
7.8b
1.4b
2'7b
1.2b
6 5b
h
n
0 b
5 9b
h
3.7b
0 b
9.1
LSD (soil control vs treatments, 95%) 2.41
LSD (soil control vs treatments, 99%) 3.23
f Statistically significant
Highly significant yield
Statistically significant
yield decrease
(95%
Corn
Low High
rate rate
c -?b b
K / n
k
14.2 2.2°
14.1 8.5a
3.6b Ob
11.8 11.2.
.13.0 i.r
9.3a 0.3b
2'9b ° b
0 b 0 D
13.6 3.9b
11.4 3.8D
b Q b
14.5 11.2
12.8
10.1
3.52
4.69
confidence level).
decrease (99% confidence level).
yield increase
(95%
confidence level ).
139
-------
soil and liquid mud; and a MAXIMUM "accident" rate of addition as well as
the lower, normal use rate. Variations in these factors will cause changes
in plant responses. Also, beans are considered relatively sensitive to
salt and many toxins. Many native plants at drilling sites may be quite
tolerant.
With these cautions emphasized, the data of table 7 summarize much of
this preliminary phase. Only six of the final 13 components at normal use
concentrations reduced plant growth. But only four materials seem to be
of real concern.
Potassium chloride is used in concentrations too high to permit plant
growth in the residual mud. However, the salt is very soluble, and potas-
sium is a plant nutrient. Often potassium is in deficient amounts in
rainfall areas exceeding about 30 inches (75 cm) annually. In such
regions, leaching would remove excess salts and the adsorbed portion of
potassium could be beneficial to plant growth.
Table 7. Summation of the effects of 31 drilling fluid (mud) components
in reducing bean and corn growth when normal-use rates are added and the
liquid mud is added to an equal volume of soil
Material
n
Nonfermenting starch (Dextrid )
D\
Modified tannin (Desco '
Guar gum R
Large weight alcohol (Drillaid 405 )
D
Sul fated triglyceride (Torq-Trim )
Pregelatinized starch
Iron chrome! ignosulfonate (Q-Broxin)
Plant-synthetic fiber mix (Kwik-Seal)
Calcium 1 ignosulfonate + NaOH
Lignite (LigcoR) + NaOH
Diesel oil
Sodium di chroma te
Potassium chloride
Dry yield,
Beans
109
123a
102
98
85
81
82
88
80b
75b
52b
h
-,-u
b
0°
percent of control
Corn
111
110
102
92
113
106
89
73b
45b
23b
28b
°b
0D
, Statistically significant increase in yield.
About 20 and 27 percent statistically significant reductions for beans
and corn, respectively.
140
-------
The second and third most toxic components of the drilling muds
tested were lignite and calcium lignosulfonate, but only because of the
sodium hydroxide levels added with them. The high soil pH and soil dis-
persion resulting from adsorbed exchangeable sodium are the problems com-
mon to SODIC soils, which are well known to agriculturalists. The ac-
cepted treatments for such soils are the addition of gypsum (CaSCL'ZHpO)
or sulfur (elemental) followed by leaching. These treatments should solve
this problem.
The fourth most toxic material, diesel oil, may be the most difficult
problem to solve. Fortunately, alternatives to its use are already avail-
able and appear to be nontoxic (see Drillaid 405 of this paper). The dis-
tillates in diesel oil will eventually vaporize into the atmosphere leaving
limited or no phytotoxic materials. Some of its high-boiling-point com-
pounds may remain adsorbed to soil tending to "water-proof" the soil to
some extent. In areas of low yearly moisture, the intentional water-proof-
ing of soil—if the soil is also porous--has helped increase total usable
water. The long range effects of diesel oil should not exceed a year.
The influence of sodium dichromate is unclear. It is known from
other analyses in this study to be at least partly a soluble salt effect
in the unbuffered barite making up the bulk of the mud. This salt effect
is easily removed by leaching. The possibility of chromium toxicity
exists—addition rates are high enough—but experimental verification is
lacking.
Some of the remaining components decreased plant growth. Except per-
haps for toxins in black walnut shells, the plant-synthetic fibers mix
(Kwik-Seal), the tannin (Desco), and the iron chrome!ignosulfonate (Q-
Broxin), no other toxins were anticipated. The effects of the gums and
starches particularly were surprises. It is presumed that any phytotoxins
present are likely to be short lived and mostly water soluble. A combina-
tion of leaching and a few months of warm weather should largely eliminate
any toxins present. Work on these aspects of amelioration are in progress
on a limited scale.
141
-------
The writer does not believe the drilling fluid components tested,
except perhaps diesel oil, pose severe problems to growing plants. At
least three simple processes can reduce any phytotoxicity of most of the
tested materials. First, leaching can remove salt and soluble organics.
Second, soil burial can provide an adequate root zone above the mud.
Third, gypsum or sulfur can be added to correct the high alkalinity and
exchangeable sodium problem of added sodium hydroxide.
More careful studies of the soil chemistry of chromium and the
longevity of diesel oil effects are needed. These studies could clarify
the environmental effects of these mud components.
REFERENCES
1. L. E. Allison, "Organic Carbon," in C. A. Black's (ed.) Methods of
Soil Analysis, Part 2, Agronomy series No. 9. American Society
of Agronomy, Inc., Madison, Wisconsin, 1965, pp. 1367-1378.
2. J. M. Baker, "The Effects of Oil on Plants," Environ.__PoTI., Vol. 1
(1970), pp. 27-44.
3. L. Bernstein, "Salt Tolerance of Plants," U.S.D.A. Agr. Inform. Bull.
283, Washington, D.C., 1964, 21 pp.
4. H. R. Bode, Allelopathy is some Juglandaceae. Planta: Arch. F.
Wiss. Bot., vol. 51 (1958), pp. 440-480.
5. H.J.M. Bowen, "Trace Elements in Biochemistry," Academic Press, New
York, 1966, 241 pp.
6. C. A. Bower, and L. V. Wilcox, "Soluble Salts," in C. A. Black's (ed.)
Methods of Soil Analysis, Part 2, Agronomy Series No. 9, Amer.
Soc., Agron., Inc., Madision, Wisconsin, 1965, pp. 933-951.
7. R. H. Carr, "Vegetative Growth in Soils Containing Crude Petroleum,"
Soil Sci. Vol. 8 (1919), pp. 67-68.
8. A. S. Crafts and H. G. Reiber, "Herbicidal Properties of Oils," Hilgardia.
Vol. 18 (1948), pp. 77-156.
9. E. F. Davis, "The Principle of Juglans nigra as Identified with Synthe-
tic Juglone, and its Toxic Effects on Tomato and Alfalfa Plants."
Amer. Jour, of Bot., Vol. 15 (1928), pp. 620.
10. D. E. Koeppe, "Some Reactions of Isolated Corn Mitochondria Influenced
by Juglone," Physio!. Plant, Vol. 27, No. 1 (1972), pp. 89-94.
11. Skipped on purpose.
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12. W. Mertz, Chairman, "Chromium," in Geochemistry and the Environment,
Vol. I (1974) pp. 29-35.
13. S. R. Olsen and L. A. Dean, "Phosphorus," in C. A. Black's (ed.)
Methods of Soil Analysis, Part 2, Agronomy Series No. 9
Amer. Soc. Agron., Inc., Madison, Wisconsin, 1965, pp. 1035-1049.
14. R. P. Tucker, "Oil Sprays—Chemical Properties of Petroleum Oil
Unsaturates Causing Injury to Foliage, " Ind. and Engr. Chem.,
Vol. 28 (1936), pp. 458-461.
15. U.S. National Committee for Geochemistry and the Environment, "Vol.
I: The Relation of Selected Trace Elements to Health and Dis-
ease," Natl. Acad. Sci., Washington, D.C., 1974, 113 pp.
16. J. van Overbeck and R. Blondeau, "Mode of Action of Phytotoxic Oils,"
Weeds, Vol. 3 (1954), pp. 55-65.
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DISCUSSION
CHAIRMAN LUMMUS: The gentlemen who have just presented their papers on
the effect of mud additives in the environment are ready to answer
questions.
DR. PAT M. WENNEKENS (Alaska Department of Fish and Game, Anchorage,
Alaska): I think the results presented are quite interesting, but
I also think they can be very misleading. One consideration is that
in order to perform appropriate tests, we try to select the toughest
animal available, because it can be kept alive during laboratory
handling in preparation for the tests. This is in many instances a
very misleading approach, because we like to determine what is the
effect on the most sensitive portion of the biological system, not
the toughest portion of the system.
The second, concerning the last presentation, is that unless we
look at the total mass balance of where all this material goes and
what it does when it goes in different places, we don't get a per-
fect picture. As an example, by adding gypsum and leaching we can
improve the soil, but the leachate also goes someplace. This is the
area in which we are also very much concerned; any material being
used or spread on the land as a byproduct also goes someplace and
does certain things. And I think unless we make some kind of presen-
tation and look at what the total mass balance of all of the compo-
nents of the system do, we have a very misleading picture.
MR. REED E. HARRIS (National Marine Fisheries Service, Anchorage, Alaska):
It is all well and good that we have studied these things individually.
I wanted to know if, in fact, there have been studies conducted that
deal with drill muds as a whole, in other words, whether or not we have
synergistic effects on all of these different additives in drilling
muds, and what effects they might have.
I would also like to ask why the subject mollienisia was selected
as a test animal rather than some other organism?
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CHAIRMAN LUMMUS: I can answer the first question.
The effect of muds and the possible synergistic effect of
typical muds, which would contain a combination of additives, will
be studied in the next phase, phase two. In that phase we are
going to involve not only the effects of the combination of addi-
tives but also the effects of reclamation procedures.
MR. HOLLINGSHORTH: I would like to address myself to the other part
of your question dealing with the selection of M. latipinna as
a test organism. I think we stated in the paper that the test
organism M. latipinna is described as being a median sensitivity
approach and is adaptable both to freshwater and seawater environments.
Thus it makes it an ideal organism for some initial screening work.
And we are cognizant that the reactions of this particular species
are not necessarily indicative of all other organisms' responses
to these materials, but it is a satisfactory organism for doing our
initial screening work.
MR. REED E. HARRIS: Do you plan on doing work on synergisms in fresh
water? Do you plan on doing any work on freshwater species as
well as saltwater species?
MR. HOLLINGSWORTH: Yes. I am sure we will get into that, eventually.
MR. KEITH E. JAMES (Texian International, Houston, Texas): I will try
to avoid making a complete speech here. We, among other things,
run many bioassay tests. The sail-fin Mollie, M. latipinna has been
mentioned here as one of these fish. Since this question has come
up from time to time, I might make some comments on it.
We have correlated this with several other fish, a couple of
species of ocean minnows, three species of shrimp, a couple of
species of plankton. Naturally, we do not compare plankton with
shrimp or with fish; we are talking about different digestive sys-
tems and different metabolisms. The gentleman raised a relevant
question, but I would suggest you keep in mind that we are talking
about acute toxicity rather than long-term effects. Obviously, if
we kill the fish's food supply, even though it lives 96 hours, it
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is going to have a rough time thereafter. So, let us not confuse
the two different types of tests.
The sail fin mollie, which we compared with several fish, is
obviously convenient, for one thing. It will grow in both fresh-
water and saltwater, with gradual conditioning. It is also a sen-
sitive fish. If we use gar or goldfish, everything would look pretty
good. Some say trout will look terrible; but not necessarily. We
have correlated with trout in a few cases, not in our lab but
between other labs on some of the same products, and the sail fin
Mollie does not look much more (or less) stable than trout, actually.
But I do not think it is accidental that the "powers-that-be"
running LD 's and TI_M's for many years, rarely specify particular
organisms. As long as we know the organism is comparable in some
way, I think this tells us what we want to know. There have been a
lot of lists made of common fish. If there is a list of only those
that are acceptable, I would like to hear about it, but there are
only some lists of suggested fish. But I do not think we should
try to key in too heavily on one particular specie unless we can
think of some reason to eliminate it.
MR. DOYLE D. WALLER (IMCO Service, Houston, Texas): Regarding the ques-
tion asked earlier by the gentleman from the University of Texas on
turbidity, I want to make this comment.
The Department of Interior, Bureau of Land Management, has a
bulletin, Environmental Impact, 74-90, which would answer it very
well. Based on 25 years of cuttings and miscellaneous mud spills
in the Gulf of Mexico, turbidity has not proven to be any problem,
to date; neither have settlements on the bottom. The fish, plank-
ton, as well as game fish, have multiplied steadily. This is doc-
umented in that particular statement. I would suggest that the
people who have not read that do so.
DR. GEORGE H. HOLLIDAY (Shell Oil Company, Houston, Texas): I understood
that Dr. Rice at the Marine Fishery Service at Auke Bay had made an
offer to do some testing of hole muds, and that that particular offer
had been rejected--! am not sure whether it was by EPA or by the
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National Marine Fishery Service. I wonder if Mr. Harris would like
to talk a little bit about the proposal that was made and perhaps
the history behind it?
MR. REED E. HARRIS: All this work is preliminary; we were trying to get
funds or get a study funded by the various participants in the dril-
ling operations in Cook inlet. And Mr. Rice has accepted, or I
think would be amenable to accepting a study if it were funded by
the various companies that are involved in oil exploration.
As we talk about this, we are now in the process of talking to
some of the oil companies, including Phillips, Shell, and some of
the other operators to conduct studies that relate to the possible
effects of muds and their additives on marine life. I think Mr.
Rice, at the Auke Bay lab, National Marine Fishery Service Lab, would
be amenable to do those studies if they are funded.
We would also like to contract out an in situ study on some of
the effects of muds "in place" on the bottom. This way we will not
be dealing with individual components in drilling muds; we will be
dealing with the real fact.
I do not know if any of you are aware that in Alaska we have
not patently accepted this idea that drill muds are harmless. And
there have been cases where we have asked that the drilling muds and
cuttings be hauled ashore until we can find out. So, basically,
that is what we are after right now; we are trying to find out so
that the companies do not feel like we are leaning on them.
I believe that once we can undertake a study, and we can show
one way or the other whether or not in real life there is an impact
upon the marine environment or the marine biota, then we will modi-
fy our stipulations on our Corps of Engineers permits.
But I believe Mr. Rice would be willing to accept the oil
industry's money if they are willing to find out what the impact will be.
I am not aware that he has refused any study of that sort. In
fact, he is doing work for Shell Oil right now on the toxicity of
Cook inlet crude.
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DR. RICHARD S. SCALAN (University of Texas, Marine Science Institute,
Port Aransas, Texas): I have a comment regarding the subject of
the environmental impact statements and the effects of long-term
drilling in the ocean. One thing we do not have, and for which the
Bureau of Land Management is now funding quite a large amount, is a
baseline study to know whether or not there has been an effect on
the environment. We are engaged in such a study in South Texas
waters; such studies will go on in the East Coast, the West Coast,
and in Alaska. These studies are designed to find out what now
exists so that we will be able to make some statements about
whether or not the environment has been affected by such things as
drilling muds or the drilling activities themselves.
Now, as far as the turbidity is concerned, as I mentioned
awhile ago, I am a chemist, but the biologists tell me that the one
thing that they will be able to see beyond any doubt is that you
can measure and correlate the turbidity of the waters with the or-
ganisms, the microorganisms, primarily with phytoplankton, after
the phytoplankton come zooplankton and the fish follow them. I
don't know whether it is good, bad, or indifferent to force the
phytoplankton to a higher level where they can get the sunlight.
My point is, that this is probably the one thing that will be
affected, and the one sort of thing that will come out of such
studies as these baseline studies that the Bureau of Land Manage-
ment is now sponsoring.
DR. ROBERT Y. GEORGE (University of North Carolina, Wilmington, N. C.):
I would like to make two brief comments with reference to the ques-
tions raised. And I would like to address a question to Dr. Miller.
The comments are primarily pertaining to the acute experiments,
fish toxicity experiments, which were reported. Obviously, there is
a need for chronic or long-term study to follow up. Mere survival
does not answer a lot of the questions we need to know about the
behavior changes and related alteration in physiological processes
concerning the health of the animals in terms of their ability for
growth and reproduction.
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With reference to the turbidity, of course, the plankton
trapped in a plume of mud cannot photosynthesize like the normal
algae or diatoms do, but turbidity is not necessarily a long-term
phenomenon. And migrating animals have a tendency to escape.
The question I have in mind for Dr. Miller concerns the higher
nodulation that is encountered in the beans. Is it seen only in
the barite substrate or in other substrates? And are there other
factors that induce nodulation?
DR. MILLER: There is no possible way to know this because there was not
enough information taken. We only made observations of the pots
because we had other things that we were needing to do.
I presume that the nodulation is a combination of two things,
at least. The first is that a lack of nitrogen nearly always increases
nodulation. A second is that any kind of toxicity hindering bacterial
growth might reduce nodulation. So there is no way to know.
It simply appeared that the bean in the barite was; much more
nodulated than any of the test pots. Lignin, lignite, and calcium
lignosulfonate all seemed to be fairly well nodulated in spite of
the fact that they are organic substances. So I have no information
of value that I can give you on that.
DR. C. S. GIAM (Texas A & M University, College Station, Texas): I think
one of the problems that we are having here is the fact that we
really have not investigated the effects of various chemicals on
biota very carefully. But I would like to point out and remind some
of you that in cases where petroleum or copper have been studied, at
lower levels they were found to be beneficial to the systems; at
higher levels they are toxic.
So when we talk about toxicity, especially when we talk about
high and low dosages without actually mentioning the number, we have
got to be very careful.
Concerning copper in particular, there are some studies (NSF-
IDOE-CEPES) in which copper concentrations used were near or slightly
higher than natural (ambient) levels. At certain parts per billion
150
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level, copper was reported to increase growth of particular organisms.
However, at 10 or a hundredfold beyond this level, there was an inhi-
bition of growth on these organisms.
So, we may be in a controversy over nothing (various concentra-
tions of copper gave different observations).
DR. WENNEKENS: In some of your additives you have a byproduct of hem-
lock and cedar. Is this hardwood, or does this include the bark?
I mean, does it include both the bark and the wood or only hardwood
or bark, or what? What kind of material is it? Can you give me
any information on this?
CHAIRMAN LUMMUS: I assume, I believe I am correct, that it includes
only hardwood? Is that correct?
DR. MILLER: No. It is an extract like your quebracho or hemlock or red-
wood.
MR. HOLLINGSWORTH: Yes. I think the quebracho extract, for example,
comes from the heartwood of the quebracho tree whereas most of the
others are bark extracts, water-soluble extracts. I haven't gone
over the entire list, but I think that is essentially correct.
DR. WENNEKENS: I asked the question because there are some studies that show
that some trace sediments in the woods—and especially in the bark,
where they are concentrated—actually are hormone inhibitors. And
I question it because some of those woods are known to be very resis-
tant to rot, meaning that they have some biocidal properties, which
have components that are essentially biocidal. And there has been
some work demonstrating hormone inhibitors to the metamorphosis of
larvae.
CHAIRMAN LUMMUS: When you asked the question, I was thinking in some of
the slides that we had some wood fibers and plant fibers. Now,
these are mostly used in lost circulation materials, because this
would be the ground-up wood. We are talking about some of the
extracts; they would be from the bark. I hope that clarifies it.
DR. MILLER: The point I want to make is that unless we look at what
components are most liable to have some direct effects, again, as I
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told you, you can put cedar shavings in your closet for mothproofing
of your closet, that means you are killing the moths. But some of
those components actually can inhibit the larvae to metamorphose,
to go from a larva to an adult. And a question that we have
is essentially what this does if you release this material
in an area where you have a very high shrimp juvenile or shrimp
larvae that are being spawned at the present time.
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USE OF A BIOASSAY TEST IN EVALUATING THE TOXICITY
OF DRILLING FLUID ADDITIVES ON GALVESTON BAY SHRIMP
E.G. Chesser and W. H. McKenzie*
Abstract
The effect of drilling fluids and drilling fluid additives on
marine life is obviously an important consideration when drilling in
coastal and offshore waters. This paper describes the use of a bio-
assay test to determine the degree of toxicity of drilling fluid ad-
ditives to Galveston Bay shrimp. Shrimp were chosen as the test
organism since they are not only an important commercial food crop
but a biologically important food for fish and other marine organisms.
The method used is patterned after that given in the Standard
Methods for the Examination of Water and Wastewater, 13 ed., prepared
and published jointly by American Public Health Association, Water
Pollution Control Federation, and American Water Works Association.
Methods of collecting, acclimatization, and exposure as well as the
test apparatus are described. The results of 96-hour salt water
toxicity tests with several common drilling fluid additives are
given. The study is by no means complete but the procedure appears
to be a reliable and meaningful approach to measuring the toxicity
of most drilling fluid additives to shrimp.
INTRODUCTION
Two of the most important drilling areas for the oil and gas
industry are the estuaries and offshore waters of the Louisiana and
Texas Gulf Coast. During drilling operations in these areas, using
water base muds free of oil, the formation cuttings are normally
disposed of by adding directly to the water. With modern high-speed
shale shakers, the quantity of drilling fluid associated with these
cuttings is minimal, but some drilling mud is lost along with the
*Chesser and McKenzie are with Milchem Incorporated, Houston,
Texas 77027.
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cuttings. The components in the fluid are quickly diluted by the
water until only a few parts per million of any one component exist
in the vicinity of the well site.
A variety of chemicals are used in water-base drilling fluids,
and concentrations vary considerably depending upon the type of sys-
tem being used. The major added components of most water-base muds
other than water are commercial bentonite and barite. Several in-
vestigators (refs. 1,2) have shown these components to be essentially
nontoxic to marine life. Barite and bentonite have been used in Gulf
Coast offshore drilling since its inception in 1947. The increasing
fish harvest along the Louisiana Gulf Coast as reported by Brashear
(ref. 3), is further proof that these materials have not adversely
affected the fish population over the past 20 years.
To reduce drilling problems and well cost, the industry is con-
tinually looking for improved drilling fluids. As any drilling fluids
researcher will quickly note, there are a number of factors which must
be considered prior to and during the development of any new drilling
fluid system. One of these factors, which has always been important
but is receiving increased attention, is the relative toxicity of the
materials to be used in these systems. Their effects on humans as
well as plant, animal, and marine life must be considered,,
This increased awareness has prompted Milchem Incorporated to
establish test facilities to evaluate the effect of drilling fluid
additives or systems on marine organisms. This paper describes the
adaptation of a static bioassay test utilizing Galveston Bay shrimp
(littoral penaeids). The test is patterned after the Standard Meth-
ods for the Examination of Water and Wastewater, 11 ed., prepared
and published jointly by American Public Health Association, Water
Pollution Control Federation, and American Water Works Association.
WHY SHRIMP
Shrimp were chosen as the test organism since they are not only
154
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an important food crop but are biologically important as food for
fish and other marine organisms. They are relatively abundant and
generally available from live bait houses in the Galveston Bay area.
In addition, they adapt quite well to a laboratory test environment.
Three littoral penaeids (brown, pink, and white) are abundant
enough to be utilized profitably as food; however, for commercial
catch statistics, they are grouped under one category. The approx-
imate total Texas shrimp landings for 1973 were over 80 million
pounds (ref. 4).
As reported by Becker et al. (ref. 5), littoral penaeids range
the Atlantic coast from New Jersey through the Gulf of Mexico and
West Indies to Uruguay. They occur in estuaries and littoral zones,
predominantly on mud bottoms from the water's edge to 45 fathoms,
rarely to 90 fathoms. They have an extended spawning season that
probably varies in different parts of their range. Spawning occurs
in deepwater and the young enter estuarine brooding grounds as post-
larvae; they penetrate into low salinity shallow water and grow
rapidly in the warmer months. As shrimp grow, they move gradually
to deeper, saltier water and eventually return to the sea. A study
of the time of emigration of brown shrimp from the Galveston Bay
System by Trent (ref. 6) showed two peak periods, the first in May
and the second in June. His study also showed the size of the emi-
grating shrimp increased significantly as the season progressed.
SHRIMP SOURCE
Both white shrimp (Penaeus setiferus) and brown shrimp (Penaeus
aztecus) have been used in the test program. These are obtained
from live bait houses near San Leon and Galveston, Texas. Twenty-
gallon plastic drums fitted with battery powered aerators and filled
with Galveston Bay water are used to transport the shrimp back to
the Houston laboratory. At the laboratory they are transferred to
a 150-liter holding tank which is filled with Galveston Bay water
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collected at the same time and same location as the shrimp.
On the first trip for shrimp, the 150-liter holding tank was
filled with synthetic seawater prepared with "Instant Ocean Sea
Salt"* and Houston tapwater. Transferring the shrimp from the
relatively cold baywater (50°F) to the synthetic seawater at
68°F, the latter having equilibrated in the laboratory overnight,
resulted in a loss of over 50 percent of the supply. There was
also a considerable difference in pH of the two waters, a 7.4 pH
for the baywater as compared to 8.0 for the synthetic seawater.
This difference in pH may also have contributed to the high death
rate. On the next trip for a new shrimp supply, sufficient bay-
water was obtained for the holding tank and the test aquariums.
All tests have since been run in the baywater as there is no
particular problem in obtaining a sufficient volume of this water
for the tests. Sudden temperature changes and variations in pH
and salinity are thus avoided, and the shrimp are kept in their
natural water environment.
Though baywater is still being used, acclimatization tests
have been made in synthetic seawater in which the temperature,
salinity, and pH were adjusted to that of the baywater. With
these adjustments, the shrimp survival rate has been good, and
there appears to be no particular problem in using the synthetic
seawater for the bioassay test.
LABORATORY AND TEST EQUIPMENT
The test laboratory is isolated from the central air condition-
ing system of the main building and is equipped with a 2-ton window
air conditioner to assure that the air temperature is maintained at
68°F to 70°F. To assure that the water temperature does not drop
below 68°F, the aquariums are equipped with "Supreme"! 100-watt
thermostatic heaters.
*Aquarium Systems, Inc.
tEugene G. Danner Manufacturing, Inc.
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Figure 1. 36-liter aquarium with aerator, filter, and heater.
The 150-liter tank in which the shrimp are first placed is used
as a holding tank and supply source for the smaller aquariums in
which acclimatization and exposure period tests are conducted. The
smaller aquariums hold 36 liters and are equipped with "Silent Giant"*
aerators (see figure 1). During acclimatization, they are also equipped
with charcoal and flow filters.
Ten shrimp were placed in each 36-liter aquarium giving 3.6
liters and 18 sq. in. per shrimp. It was soon obvious that this
did not provide sufficient floor space for the shrimp. Several would
crowd together in one corner resulting in fighting and the subsequent
death of a number of those in the tank. As shown in figure 2, this
problem was alleviated by placing fish netting in the tank, thereby
greatly increasing the surface area for each shrimp to occupy as well
as providing something for them to cling to. It was observed that
shrimp are quite possessive to territory and prefer to remain isolated
from each other. They are also cannibalistic and quickly devour any
of their number that die.
During the acclimatization period, the shrimp are fed small
*Aquarium Pump Supply, Inc.
157
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158
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frozen brine shrimp. The charcoal and filter floss aid in the
removal of any waste food and excretion. The Galveston Bay water
is quite murky when freshly obtained but usually clears up in 2
to 4 hours with the filter operating. In some cases the water is
much slower to clear, which can be due to the waste from a dead
shrimp.
Figure 3. View of 36-liter aquariums during acclimatizati
on,
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ACCLIMATIZATION AND TESTING
To acclimatize the shrimp to the laboratory environment before
exposure to the test additive, they are transferred from the large
holding tank to the 36-liter aquariums. As stated above, the test
tanks are filled with Galveston Bay water and the aerator arid filter
are operated continuously during this period. An oxygen analyzer is
used to assure that the D.O. does not drop below 4.0 ppm. Six of the
small aquariums are used for each test, one for control and five for
different concentrations of the test chemical with 10 shrimp each.
The shrimp are acclimatized in these tanks for a period of not less
than 12 days. Acclimatization periods of 12 to 21 days were used.
A view of several of the 36-liter test aquariums is shown in figure 3.
During the acclimatization period, the shrimp are carefully ob-
served and the dead are quickly removed. The number of shrimp (10)
in each tank is maintained constant by resupplying from the large
holding tank. The incidence of disease and death within a period
of 4 days immediately preceding the test is normally not more than
5 percent. The number of mortalities for two different acclimatiza-
tion periods is shown in table 1. Note that the death rate does not
stabilize to an acceptable level until after the eighth or ninth day,
indicating the 10-day minimum period as stated in the Standard Method
(ref. 7) is justified.
Before starting the actual static exposure period, screening
tests using a few shrimp in small containers are made with various
concentrations of the material to be tested. The purpose of these
preliminary runs is to locate the general concentration range to be
used in the 96-hour tests. Since five concentrations are tested for
each run, two are chosen which, based on the screening tests, will
be above the TL5Q and two will be below.
After the acclimatization period, the shrimp are removed from
the test tank for a brief period until the chemical to be tested is
added. The material to be tested is thoroughly mixed in the water
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Table 1
Run A: Mortalities for 12-day acclimatization period
Date
10-24-74
10-25-74
10-26-74
10-27-74
10-28-74
10-29-74
10-30-74
10-31-74
11-1-74
11-2-74
11-3-74
11-4-74
Test
Tank
#1
0
0
1
0
0
0
0
2
0
0
0
1
Test
Tank
#2
1
2
2
2
0
0
1
0
1
0
0
1
Number of
Test
Tank
#3
0
4
2
1
1
3
1
0
1
0
0
0
mortalities
Test
Tank
#4
0
4
0
0
1
0
1
0
0
1
0
0
Test
Tank
#5
2
3
1
0
2
0
1
0
0
0
0
0
Test
Tank
#6
0
1
3
1
0
2
0
0
0
0
0
1
Run B: Mortalities for 14-day acclimatization period
Date
12-16-74
12-17-74
12-18-74
12-19-74
12-20-74
12-21-74
12-22-74
12-23-74
12-24-74
12-25-74
12-26-74
12-27-74
12-28-74
12-29-74
Test
Tank
#1
2
1
2
0
0
0
0
0
2
1
0
0
0
0
Test
Tank
#2
0
3
2
0
0
0
0
0
2
0
0
0
0
0
Number of
Test
Tank
#3
3
1
1
0
0
0
0
0
1
0
0
0
0
0
mortalities
Test
Tank
#4
3
0
0
0
0
0
0
0
1
1
0
0
0
0
Test
Tank
#5
0
2
0
1
0
0
0
0
1
0
0
0
0
0
Test
Tank
#6
0
1
1
1
2
0
0
0
0
0
1
0
0
0
161
-------
to assure good dispersion or solution, but violent agitation or vor-
texing is avoided to prevent foaming or frothing in the tank. During
this interval the shrimp are held in a secondary tank having the same
acclimatization conditions. Great care is required in the removal and
return of the shrimp to assure that none are injured. They are removed
with soft, fine mesh nets and are returned to the same aquarium from
which they were taken. If one should be dropped or injured, it is re-
placed by one from the large holding tank. The shrimp are not fed for
3 days before the static testing is begun, nor are they fed during the
96-hour exposure period. This is to avoid large fluctuations in their
metabolic rate and fouling of test solutions with metabolic waste prod-
ucts and uneaten food. The charcoal and flow filters are not used dur-
ing the run and the air from the aerators is reduced to a fine stream
of bubbles with pincher clamps.
The shrimp are carefully observed during the first hours of ex-
posure since this is a critical period for them. Mortality checks are
made and recorded at 24, 48, 72, and 96 hours. When the material test-
ed forms a clear or transparent solution, the checks are relatively
simple. In cases where the water is darkly colored with high concen-
trations of materials such as tannins or lignosulfonates, only those
shrimp near the glass wall (figure 4) can be seen clearly enough to
determine their condition; therefore, it becomes necessary to carefully
remove the shrimp for an accurate count.
CALCULATIONS
The results of the bioassay tests are expressed with the term
"tolerance limit" (TL) as outlined in the Standard Method (ref. 7).
By definition, a 96-hour TL^g of a test material is that concentration
in which 50 percent of the fish survive for 96 hours. The TL5g is
equivalent to the median tolerance limit (TL ). The 96-hour TL5Q is
estimated by plotting the data on semi logarithmic coordinate paper
with concentrations on the logarithmic and percentage survival on
162
-------
Figure 4. Inspection of shrimp in darkly colored water.
the arithmetic axis. A straight line is drawn between two points
representing survival at two successive concentrations, one which
was lethal to more than half and one which was lethal to less than
half the shrimp. Thus the TLgQ is an interpolated value rather than
a determined value by an actual test of that specific concentration.
It is important that data points be obtained below and above the TL,
value. An example of this graphical computation and the corresponding
data is shown in figure 5.
'50
163
-------
COMPUTATION OF TL
50
Number of Test Animals Surviving
Concentration No. of Shrimp Tank No. 24 hrs. 48 hrs. 72 hrs 96 hrs
400 ppm 10 1 10 10 10 10
800 ppm 10 2 10 9 9 9
1000 ppm 10 3 10 10 9 8
1500 ppm 10 4 ""0986
2500 ppm 10 5 10 9 7 4
Control 10 69999
300C
250C
a 2ooc
£ 192 c
o
H
H
(3
W
U
8 15°C
innr
1 1 1
TEST CONDITIONS
Water Temperature = 68°F
J» Tank = j.6
liters/shrimp
\ Acclimatization Time = 14 days
96-hr TLC_
50
\ Length of Test = 96 hours
\ Number of shrimp = 10
\ Test Organism = Penaeus setiferus
\ (White Shrimp)
. \
\
\
\
\
\
U
A
^"
1
i
10 20 30 40 50 60 70 80
TEST ANIMALS SURVIVING, %
90 100
Figure 5.
164
-------
The authors are aware of other terms used in reporting toxic-
ity data such as "lethal dose" (LD) and "lethal concentration" (LC).
In addition, there are more sophisticated methods for calculating
these values such as the use of logarithmic-probability graph paper
and the more refined methods of probits (ref. 8) and logits. The
simpler method of calculation was used since it appears to be quite
adequate for materials tested thus far.
NINETY-SIX-HOUR TL5Q RESULTS
Two common types of drilling fluid additives which serve as
deflocculants are tannin and lignosulfonates. The 96-hour Tl_5g for
an iron-modified Hemlock Bark extract (tannin), a chrome-treated
lignosulfonate, and an iron-lignosulfonate are shown in table 2. As
will be noted, the modified Hemlock Bark extract shows the lowest
tolerance limit and the iron-lignosulfonate the highest. It should
be pointed out that the chrome in the chrome-treated lignosulfonate
Table 2. Ninety-six-hour TL-5Q values for
several drilling fluid additives
Additives Test organism 96-hr TL5Q, ppm
Modified hemlock
Bark Extract
Chrome-treated
lignosulfonate
Iron-
lignosulfonate
Nonwater dispersable
def oame r
Low molecular wt.
polyacrylate
Cellulosic-calcium
White shrimp
(Penaeus setiferus)
White shrimp
(Penaeus setiferus)
White shrimp
(Penaeus setiferus)
Brown shrimp
(Penaeus aztecus)
White shrimp
(Penaeus setiferus)
White shrimp
265
465
2,100
Eratic
3,500
1,925
carbonate workover (Penaeus setiferus)
additive
165
-------
is present as trivalent chromium, and no hexavalent or unreduced
chromium is present. Neither the modified bark extract or the iron-
lignosulfonate contain any significant amount of chromium.
A lignosulfonate concentration of 200 to 300 ppm will impart a
distinct brown color to water. The principal author has observed
numerous drilling sites in water locations over the past 20 years in
which lignosulfonate muds were being used. In not one of these has
the lignosulfonate content been present in sufficient quantity on
the cuttings to produce a visible coloration of the water.
As is well known by drilling fluids engineers and technicians,
mud additives range from high water solubility to nonwater dispersa-
bility. One such nonwater dispersable compound which is used as a
defoamer was tested with the bioassay procedure. Shrimp mortalities
were very erratic as they had to penetrate the surface before coming
in contact, with the compound. Only relatively small concentrations
of these type materials are used and the possibility of getting any
significant amount on the water surface in actual use conditions is
practically nil. This test did point out however, that it may be
desirable to employ some slight surface agitation when testing mate-
rials of this nature in order to produce surface movement as would
occur under natural conditions.
The results obtained with an acid-soluble workover additive are
also shown in table 2. Note that the TL.™ was 1925 ppm. This mate-
rial is composed essentially of graded calcium carbonates and a high
molecular weight cellulosic polymer. It is designed to impart vis-
cosity to the workover system and at the TUjQ concentration imparts
a measurable viscosity increase to the water in the test tank. This
viscosity effect may have influenced the mortality rate of the shrimp
in addition to any toxicological effects from the additive. It would
be highly unlikely that a concentration approaching the Tl_50 value for
the material would ever be encountered in the water surrounding the
workover operation.
The T1_5Q for a low molecular weight polyacrylate as shown in
166
-------
table 2 was found to be 3,500 ppm. This particular compound has a
molecular weight below 5,000. Much higher molecular weight poly-
acrylates are also used in drilling fluids, and it would be inter-
esting to see how their TL™ values compare with low molecular weight
ones.
The tests run thus far have covered only a small number of the
chemicals used in oil well drilling fluids. Additional materials
are scheduled and those will be run as time permits. The procedure
is time consuming, but to use shortcuts and haste would likely affect
the reliability of the data. Only individual mud components have been
run thus far though it is planned to test whole muds to determine if
any synergism of components exists.
In general, it can be concluded that with the modifications and
additions that have been made, the test method is a satisfactory
means for determining the acute toxicity of drilling fluid additives
to Galveston Bay shrimp. The data, of course, cannot be extrapolated
to other marine species or other habitats but should serve as a use-
ful tool in the selection of compounds for new drilling fluid additives.
REFERENCES
1. F. M. Daugherty, Jr., "Effects of Some Chemicals Used in Oil
Well Drilling on Marine Animals," Sewage and Industrial Wastes,
Vol. 23 (October 1951), pp. 1282-1287.
2. M. R. Falk and M. J. Lawrence, Acute Toxicity of Petrochemical
Dhl1ing_F1uids Components and Wastes to Fish, Technical Report
Series No. CEN T-73-1, Fisheries and Marine Service, Environment
Canada, 1973.
3. Nugent Brashear, Jr., "Fishing and the Offshore Petroleum Indus-
try," paper SPE 4197 presented at Second Biennial Symposium on
Environmental Conservation, Lafayette, Louisiana, November 13-14,
1972.
4- The University and the Sea. Vol. 7, No. 6 (Nov.-Dec. 1974),
p. 10. Center for Marine Resources, Texas A. & M. University,
College Station, Texas.
167
-------
5. C. D. Becker, J. A. Lichatowich, M. J. Schneider, and 0. A.
Strand, Regional Survey of Marine Biota for Bioassay Standard-
ization of Oil and Oil Dispersant Chemicals, American Petroleum
Institute Publ. No. 4167, April 1973.
6. Lee Trent, "Size of Brown Shrimp and Time of Emigration from
the Galveston Bay System, Texas," Proc. Gulf Caribb. Fish Inst.,
19th Ann. Sess., Nov. 14, 1966, pp. 7-16.
7. Standard Methods for the Examination of Water and Wastewater,
13th Ed. (1971) pp. 562-577.Published jointly by the American
Public Health Association, American Water Works Association,
and Water Pollution Control Federation.
8. J. T. Litchfield, Jr., and F. Wilcoxon, "A Simplified Method
of Evaluating Dose-Effect Experiments," J. Pharmacol. Exper.
Therap., Vol. 96 (1949), pp. 99-113.
168
-------
ACUTE TOXICITY OF WELL-DRILLING MUDS TO RAINBOW TROUT,
Salmo Gairdneri (Richardson)
R. H. Weir and B. Moore*
Abstract
The acute toxicity of drilling muds to rainbow trout (Salmo gaird-
neri) was investigated under 96-hour static bioassay test conditions
for a Canadian Arctic exploratory well. Samples were taken at various
well depths and tested at various concentrations to determine the
lethal concentration to 50 percent of the test population in 96 hours
(96 hr LCrn). In the sample series it was found that the toxicity
o U
could be grouped as to its relationship with the active mud system and
the depth at which the sample was taken. Results of the toxicity anal-
yses defined three distinct groups of toxicity. The first toxicity
group exhibited an LC value of <20 percent mud concentration by vol-
o U
wne. The dominant toxic factor being the high level of KCl that was
used in drilling the surface portion of the hole. The second toxic
group exhibited LC values in the range of 36 to 70 percent mud concen-
" oU
tration by volume. The toxicity of this group was characterized by the
lack of a dominant chemical or physical toxicant. The toxic action
appeared to be the result of the combination of the drilling components
present within the unweighted mud system (8.8 -9.2 Ib/gal). The third
toxic group exhibited LCcn values of 9 to 16 percent mud concentration
ou
by volume. Toxicity characterisation was generally a continuation of
the multifactor toxicity of group two, but at a much higher toxic level
due to the increase in solids and viscosity that are associated with
weighted muds.
INTRODUCTION
The potential water pollution problems associated with the handling
and disposal of drilling fluids in Canada's Arctic regions is of relatively
recent concern. With the advent of onshore drilling in the flood plains'
of the Mackenzie Delta in the late 1960's and the commencement of offshore
*R. H. Weir, Biologist in Charge; B. Moore, Contract Biologist;
Environmental Protection Service, Aquatic Toxicology Laboratory, Edmonton,
Alberta, Canada.
169
-------
drilling in the shallow regions of the Beaufort Sea, Hudson Bay, and the
Arctic Ocean in 1974-75, an industry/government research program was
established in March 1973. The purpose of this program was to investigate
the magnitude of the pollution problem associated with current methods
of handling sump fluids from onshore exploratory drilling locations and
the disposal of waste drilling fluids from offshore exploratory operations.
For the past 2 years, the Environmental Protection Service's
Aquatic Toxicology Laboratory, Edmonton, Alberta, tested drilling
waste discharges from 10 Canadian Arctic wells for acute toxicity to
rainbow trout (Salmo gairdneri] under 96-hour static bioassay condi-
tions. Rainbow trout were selected as the test organisms a:; current
Federal Government environmental regulations and guidelines recognize
rainbow trout as the standard bioassay test organism.
For the purpose of this paper, data from a single well in the
Beaufort Sea area (figure 1) are presented. The well is fairly typical
for the Beaufort Sea area in that a water base KC1-gel-polymer mud
system was used for the surface hole section, a water base gel-polymer
mud system was used for the unweighted section of the hole and a gel-
barite weighted system was used for the lower portion of the well.
This paper examines the relationship between the acute toxicity of
the samples, expressed as 96-hour LCrQ* values, and the type of mud
system used.
MATERIALS AND METHODS
Sample Collection
The drilling mud samples were collected in two 25-gallon polyethy-
lene-lined barrels. After collection, the samples were shipped to the
Environmental Protection Service, Aquatic Toxicology Laboratory, Edmon-
ton, by the fastest means available. Upon receipt, all samples were
stored at 4°C until tested. Table 1 lists the dates, depth of hole at
sampling, and the sample site in the mud system for each sample.
*Sample concentration (percent sample by volume) that kills 50
percent of the test rainbow trout in 96 hours.
170
-------
155'
150
145'
140'
&>«*.*.
I ^ VJ
* ^--^
fc , d C(i( r-
i\-f/;j-./rv:-^]; ?
Figure 1. Beaufort Sea area.
171
-------
Table 1. Sample series data
Date
April 25, 1974
May 4, 1974
May 5, 1974
May 6, 1974
May 7, 1974
May 10, 1974
May 12, 1974
May 16, 1974
May 27, 1974
June 3, 1974
June 15, 1974
Depth (ft)
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
Sample site
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Shaker Under Flow
Testing Procedures
The water used for both the holding and acclimation of the fish
stocks and the diluent used in performing the bioassays was received
as Edmonton City water. This water was treated to maintain the following
characteristics:
pH 7.0 - 8.0
Hardness (CaC03) 70 - 80 mg/1
Total Residual C12 <0.01 ppm
Free C12 <0.01 ppm
Temperature 10° ± 1° C.
Table 2 lists the experimental parameters that were maintained
during the testing program.
Mortality checks were made at the following times: 0.25, 0.50,
1.0, 2.0, 4.0, 8.0, 12, 24, and every subsequent 12 hours up to a total
172
-------
Table 2. Test parameters
Parameter Level
Test volume 40 litres
Test pH* 6.0 - 9.5
Test temperature 15° C ± 1.0° C
Dissolved oxygen >6.0 mg/1 (by aeration)
Fish species Salmo gairdneri (Richardson)
No. of fish/concentration 8
Loading densities >2.0 1/gm/expt.
Photoperiod 12 hour light/12 hour dark
*Adjusted by reagent grade HC1 or NaOH.
of 96 hours. During the first 8 hours, the checks were made as frequently
as possible to insure that the individual times of mortality were recorded.
Death was regarded as the cessation of all movement by the fish
for greater than 1 minute, even after prodding. Dead fish were removed
immediately and the time of death recorded. The weight and fork length
of each fish was measured and recorded. At the end of the experiment,
all remaining fish were killed and measured.
Chemical monitoring of the bioassay tests involved regular 12-hour
checks for dissolved oxygen, pH, temperature, and conductivity throughout
the 96 hours or until all of the fish died in the concentration.
Raw data was in the form of percent mortality at each mortality
check for each concentration. Using the methods of Litchfield (ref. 1),
this data was plotted as cumulative percent mortality vs. time on probit-
log graph paper and the best eye-fitted line was drawn if three or more
points were available. The point where the line intersected 50 percent
mortality was read as the median lethal time* (LT™) and, where possible,
95 percent confidence limits were calculated for this value.
*Median lethal time (LTrg) is the mean time to 50 percent mortality
of a population in a single concentration. The term mean survival time
(MST) is equivalent.
173
-------
For each experiment where two or more concentrations had LTrrv
bu
values, these values were plotted vs. concentration on log log graph
paper (ref. 2) and an eye-fitted line was drawn to 96 hours. The 96-
hour LCrQ was read at this point.
All data was processed on a Hewlett-Packard 9.830A Data System.
RESULTS
Field sample data for the well, as reported by the operator, are
presented in table 3. Included are the depth at time of sampling and
the corresponding values for solids (% vol.), calcium (mg/1), and
chloride (mg/1).
Bioassay test results are listed in table 4. The data reported
includes the depth of hole at sampling, test concentrations of the sam-
ple as percent sample by volume, LT5Q and 95 percent confidence limits,
Litchfield slope, and LC5Q range as well as the LCrQ derived from the
plotted data. The IC™ values were compared with the depth of the hole
to produce a toxicity profile (figure 2). Conductivity and chloride
levels were also plotted in relation to depth and a definite trend was
exhibited (figures 3 and 4). These trends were compared to the toxicity
profile to show possible correlations with the toxicity of the samples.
The three types of mud systems used in drilling the well (surface,
unweighted, and weighted) were related to the toxicities of the samples
to attempt a correlation as to component group and toxicity.
DISCUSSION
In this testing program it was found that the acute toxicity of the
drilling fluids tested was directly related to the different types of
mud systems used.
The initial mud system that was used was a KC1-gel-polymer mud.
This mud was used for the surface portion of the hole to a depth of
3,000 feet. The 3,000-foot sample was very toxic, having an LC™ of
174
-------
Table 3. Field sample data
Depth (ft)
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
13000
Solids (% vol.)
5.0
3.5
5.0
5.75
5.0
5.25
6.0
7.0
7.0
16.0
39.0
Ca (mg/1)
1,000
750
500
150
50
50
75
75
75
0
0
Cl (mg/1)
16,500
5,600
4,600
4,500
4,100
3,700
3,400
2,600
2,000
1,750
1,850
10 percent by volume (table 4). Corresponding to this high toxicity value,
high values for chloride, calcium, and conductivity (table 3, figure 3)
were noted. These high levels, especially the chloride, when related to
the low LC(-n value and very short LT^ times at 60 percent and 40 percent
suggest that the primary toxic component was the KC1. Beckett et al.
(ref. 4) report that KC1 and the polymer components were toxic at similar
levels (i.e., LC™ 1,800-2,000 mg/1). However, with the estimated higher
amounts of the KC1 in this mud system, one could conclude that it contrib-
uted the most to the toxicity in this mud. The gel having a reported
LCj-Q value of 10,000 mg/1 (ref. 4) would have some, but not a major toxic
effect on the sample, as solids values were moderate (table 3).
With the change of mud systems from a KC1-gel-polymer system to an
unweighted gel-polymer mud at the 4,000-foot sample a five- to six-fold
decrease in toxicity was observed. This was likely due to the elimina-
tion of the KC1 with the resultant drop in chloride (figure 4) and
conductivity (figure 3) values. The LC™ value decreased to 55 percent.
Samples from 4,000 feet through to 9,000 feet exhibited the toxic
175
-------
Table 4. Bioassay results
Depth Cone.
(ft.) (%/vol.)
3,000
Surface hole mud 60
50
40
30
20
4,000 100
Unweighted 8Q
middle hole mud
60
40
20
5,000 100
80
60
40
20
6,000 100
80
60
40
20
7,000 100
80
60
40
20
8,000 100
80
60
40
20
LT5Q (hr.)
(95% contid. limits)
0.22(0.14
1.45(1.38
10.5 (7.3 -
15.0 (10.3
33.0 (25.2
0.23(0.21
1.15(0.74
40.0(26.5 -
0.15(0.13
0.40(0.32
7.20(4.50
75.0(54.0 -
0.22(0.10
15.5(6.79 -
—
—
—
0.10(0.08
0.16(0.11
0.77(0.46
—
—
0.11(0.09
1.45(0.24
39.0(32.4 -
—
—
- 0.34)
- 1.52)
15.0)
- 21.8)
- 43.2)
- 0.25)
- 1.78)
60.5)
- 0.18)
- 0.50)
- 11.40)
104.1)
- 0.46)
35.38)
- 0.12)
- 0.23)
- 1.28)
- 0.13)
- 8.64)
49.9)
Litchfield LC50
slope (%/voT.J
1.59
1 .08 Range <20
1.70 Plotted 10%
1.72
1.47
1.12
1 _89 Kange 40gg Range 20
-------
Table 4. Bioassay results (con.)
Depth
(ft.)
9,000
10,000
'eighted bottom
hole mud
11,000
12,000
13,000
Cone.
(%/vol.)
75
60
45
30
15
75
60
45
30
15
75
60
45
30
15
50
40
30
20
10
50
40
30
20
10
LT5Q (hr.)
(95% confid. limits)
14.5(8.39 - 25.05)
31.0(23.77 - 40.44)
45.0(30.9 - 65.4)
—
—
0.29(0.23 - 0.36)
8.0(2.8 - 22.9)
23.0(17.7 - 29.9)
24.0(12.0 - 47. 8)
—
0.36(0.26 - 0.49)
5.4 (4.6 - 6.3)
6.8 (5.4 - 8.5)
11.5 (7.7 - 17.3)
32.0(26.1 - 39.2)
8.2(7.1 - 9.5)
9.8(8.1 - 11.9)
10.5(7.6 - 14.4)
62.0(16.3 - 235.9)
—
7.0(6.4 - 7.6)
7.4(6.6 - 8.3)
9.1(7.9 - 10.4)
19.5(15.8 - 24.0)
63.0(44.5 - 89.2)
Li tch field
slope
2.22
1.47
1.70
—
—
1.37
2.94
1.45
2.04
—
1.56
1.18
1.27
1.79
1.33
1.24
1.33
1.59
4.76
—
1.14
1.18
1.21
1.35
1.59
LC5Q
(%/vol.)
Range 30
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properties of this unweighted gel-polymer mud. The samples still re-
mained acutely toxic to the trout as the samples still contained enough
gel and polymer to exert a toxic influence. This was clearly evident at
the 100 and 80 percent concentrations as noted by the extremely short
LT,-n values. However, the toxicity profile of this mud system can be
ou
described as moderately toxic with some variation (figure 2). No single
toxic agent was in high enough concentration to predominate. Each of
the chemical and physical mud parameters involved contributed towards
the acute toxicity either separately, or in combination. The precise
characterization of these relationships was beyond the scope of this
study.
The third mud system, a weighted gel-barite system, was used during
the 10,000- to 13,000-foot samples. As a result, solids values increased
(table 3) resulting in a corresponding increase in acute toxicity. The
LC(-Q values of 9-16 percent were considerably lower than those of the
unweighted mud system. The increase in mud viscosity and solids content
is evident in that the samples had to be diluted to 75 or 50 percent
(table 4) before the trout could be introduced to the sample. (A slight
increase in conductivity was noted, and calcium and chloride levels
decreased.) In general, the particulate suspended solids are known to
exert their influence through abrasion and erosion of sensitive gill
tissues (ref. 3). The associated viscosity used to support the solids
appeared to exert its toxic influence by way of mechanical suffocation
in higher test concentrations (ref. 4).
pH was not a significant source of toxicity in any of the samples.
As these muds characteristically have pH values in excess of 9.5, pH
adjustment of the sample to the range 6.0 to 9.5 was made to minimize
the potential for pH toxicity.
Due to the lack of adequate and reliable mud composition data, mud
component usage data, and replicate tests, further discussion as to the
toxic properties of the muds, their components, and their action cannot
be made.
In conclusion, the overall acute toxicity trend from the surface to
bottom hole was for a shift from a high KC1-related toxicity to a moderate
181
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multifactor toxicity with a final high toxicity as a result of a high
solids effect.
REFERENCES
1. J. T. Litchfield, "A Method for Rapid Graphic Solution of Time-
Per Cent Effect Curves," J. Pharmac. Exp. Ther., Vol. 97 (1949),
pp. 399-408.
2. J. B. Sprague, "Measurement of Pollutant Toxicity to Fish - I.
Bioassay Methods for Acute Toxicity," Water Research, Vol. 3
(1969), pp. 793-821.
3. EIFAC (European Inland Fisheries Advisory Commission), Water Quality
Criteria for European Freshwater Fish, 1965.
4. A. Beckett, B. Moore, and R. H. Weir, "The Acute Toxicity of Selected
Drilling Components to Rainbow Trout, Salmo gairdneri (Richardson)."
Environmental Protection Service, Edmonton, Alberta. Unpublished,
1975.
182
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BACTERICIDES USED IN DRILLING
AND COMPLETION OPERATIONS
T. J. Robichaux*
Abstract
Bactericides are often added to drilling muds and completion fluids
to prevent microbial degradation of organic additives and to suppress the
formation of H S by SRB. Of all possible additives, baotericides are the
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Table 1. Drilling fluid additives and
their primary functions
barium sulfate
caustic (NaOH, Na2C03, etc.)
calcium compounds (CaO,Ca(OH)2,
CaCl2sCaS04,2H20)
hydrocarbons
(diesel oil, lease crude oil)
sealants (scrap, cellulose,
rubber, etc.)
thinners (tannins, lignosul-
fonates, quebracho, lignins,
etc.)
emulsifiers (lignosulfonates,
alkyl ethylene oxide adducts,
hydrocarbon sulfonates)
bactericides (substituted
phenols, formaldehyde,
amines, etc.)
fluid-loss control additives
weighting agent
pH adjustment
conditioning for use in calcium
formation, pH control
fluid loss control, lubrication
seal against leakage to forma-
tion.
dispersion of mud solids
forming oil-in-water or water-
in-oil emulsions
protection of organic additives
against bacterial decomposition.
reduction of fluid loss to
formation
molecules to cell structure, carbon dioxide, and water. Such micro-
bial degradation reduces or destroys the effectiveness of the addi-
tive and spoils the rheological properties of the fluid.
Sulfate-reducing bacteria (SRB) are specific microbial organisms
which grow under anaerobic conditions and derive their source of
energy by reducing sulfates and materials containing oxidized sulfur
with the concurrent production of hydrogen sulfide. These bacteria
are widely distributed in nature and can be inadvertantly added to
drilling or packer fluids in water used in the fluids. If such con-
taminated water is injected into the producing formation, the bac-
teria may grow and produce corrosive amounts of hydrogen sulfide.
If the water is left as a packer fluid and contains sulfates, bac-
184
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terial growth may occur, adding to the corrosion problems in the
tubing and casing annul us.
BACTERICIDES AS FLUID ADDITIVES
To prevent bacterial growth, bactericides are frequently
added to drilling and completion fluids. These additives are gen-
erally organic chemicals, such as formaldehyde, pentachlorophenol,
alkyl amines, or mixtures of such chemicals. There are other meth-
ods of controlling bacterial growth, such as pH control or control
of ionic strength. However, bactericide addition is the most com-
mon and most direct method. Table 2 is a list of generic types of
bactericides and some examples of chemicals commonly used.
Generally, bactericides which are not cationics are used in
drilling muds. These are aldehydes and phenols. They are effective
against aerobic bacteria and fungi as well as against anaerobic SRB.
The principal need for such agents is in (1) water base muds that
contain starch, CMC, and other organic materials which are subject
to microbial attack, and (2) in low solids fluids which contain
sulfates.
Table 2. Types of biocides in use
Aldehydes
Chlorinated Phenols
Quaternary Amines
Diamine Salts
Other
- formaldehyde, paraformaldehyde,
gluteraldehyde
- pentachlorophenol, alkyl dichloro-
phenol, sodium salts of phenols
- alkyl dimethyl ammonium chloride,
coco dimethyl benzyl ammonium
chloride
- acetate salts of coco or tallow
diamines
- caustic, alkyl phosphates, heavy
metal salts
185
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Bactericides most often used in packer fluids and comple-
tion fluids are quaternary amines or acetate salts of coco amines.
These materials are most effective against SRB and also function as
film-forming corrosion inhibitors. Thus, two advantages are gained
by their use—hydrogen sulfide generation is suppressed, and general
corrosion is inhibited.
Because bactericides are surfactants, they will have an effect
on the muds to which they are added. For example, quaternary amines
will cause certain clay materials to flocculate. Therefore, selec-
tion and use of bactericides should be made with an understanding
of what the bacteriade will do to mud properties.
Bactericide Regi stration
Of all the additives used in drilling fluids, bactericides are
the only additive which must be registered with the Environmental
Protection Agency. Bactericides are included in the laws governing
pesticides—a group of chemicals which cover herbicides, sanitizers,
insecticides, and rodenticides. Every manufacturer and distributor
of such products must register any and all formulations for which
claims of pest control are made.
EPA registration procedures require registrants to establish
efficacy towards target organisms, treating schedules, and environ-
mental hazards of products prior to registration. Literature de-
scribing the product, its safety, first aid for treating accidents,
as well as specific instructions for uses must accompany the products
when sold. Labels on each container specifically state the active
ingredients and concentrations, the degree of potential hazard to
humans, and precautions to be taken to avoid environmental hazards.
This registration provides the potential user with the opportunity
to tighten the use of bactericides to provide sufficient protection
without overtreating in the vague hope of doing a lot of good. It
also places the responsibility upon the user to take necessary pre-
cautions to prevent escape of the chemicals into the environment.
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TOXIC EFFECTS OF BACTERICIDES
Bactericides are made and used to kill bacteria. Such chemi-
cals are, therefore, potentially damaging to other living organisms.
As water soluble chemicals, bactericides will be carried into the
aquatic environment readily, posing a hazard to fish and birds. The
hazard can become a reality in many different ways. The chemical
may kill insects and larva on which fish feed, thus depleting the
flood supply. The chemical may have an acute effect on fish, causing
physiological damage which results in inability to swim, to escape
capture by predators or in death due to poisoning. The chemical may
pose a threat to birds and other wildlife by poisoning the water they
drink or the insects and crustaceans which birds eat. Important to
remember also is the potential hazard of bactericides to man. By
introduction into the water cycle, these chemicals pose a potential
threat to potable water supplies.
Compared to many other industrial chemicals, bactericides cur-
rently used for drilling and completion operations are relatively
low on the hazard scale. Table 3 is a compilation of environmental
data for the classes of chemicals being used. Current standards of
Table 3. Typical environmental data
Bactericide
type
Aldehydes
CI Phenols
Quats
Amines
Toxaphene
LAS
TL-50 ppm
(fish)
50 - 400
0.2 - 1
0.2 - 5
0.4 - 4
0.025
3 - 4
LD50 gm/kg
(birds)
5 - 15+
5 - 15+
>5
>5
—
—
BOD5
100
<20
95+
90 - 100
—
100
TL = toxicity limit; LD = lethal dose; LAS = linear alkyl sulfates,
187
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mean toxicity limit (TL50) to fish and mean lethal dosage (LD50)
to ducks and quail, are shown compared to toxaphene, a pesticide,
and linear alkyl sulfates (LAS), an ingredient in washing detergents.
Table 3 is not intended as a definitive statement of limits,
but lists data drawn from several studies of toxicities of chemicals
to various aquatic species. As can be seen, most bactericides in
use are considerably less toxic than toxaphene and more nearly in
the order of LAS detergents.
Another measure of environmental concern is the persistency of
a chemical in the aquatic environment. The biochemical oxygen de-
mand (BOD5) values shown in table 3 are a rough measure of whether
the chemical will persist. The data indicate that all are degraded
to some extent by natural processes. With the exception of chlori-
nated phenols, all are degraded to near 100 percent of theoretical
in 5 days. Toxaphene, by comparison, is a very persistent material
which can accumulate in the food chain causing chronic poisoning by
biomagnification.
There is no disguising the fact that misuse of mud bactericides
can cause damage to the environment. However, with proper controls
and use, the danger is minimized. By their chemical and biological
nature, the chemicals are a relatively low level hazard.
Loss to jtie Enyi ronment
Several avenues exist whereby bactericides may be lost into
the environment from drilling and completion operations. With the
exception of spillage, most of the avenues tend to be either self-
limiting or of incidental consequence. It is important to remember
that bactericides are made and used to kill living organisms. They
are, therefore, hazardous to other living creatures—such as fish
and birds. By using proper precautions, the environmental hazards
can be minimized.
The most obvious means of accidental loss of bactericides are:
• Fluid loss to a permeable zone. Bactericides will be car-
ried with any water lost to a zone along the drilling path. Because
188
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fresh water zones are most often cased off before muds are treated,
little likelihood exists for contaminating useful water zones. Water
loss to other formations is generally minimized by filter cake build-
up or by including fluid loss additives in the drilling fluid. After
completion, all but the completed zones are cased—or cemented off in
dry holes—practically eliminating return of the bactericide to an
area of concern.
• Fluid loss to the target zone. Here again, a bactericide
will be carried into a zone by water or mud lost to the zone. When
the zone is tested, or completed and produced, at least part of the
biocide may return with produced fluids. Such treated water should
be either diluted with other produced fluids or contained with mud
for subsequent disposal .
• Injection into a formation during fracing. To prevent in-
noculating a formation with SRB, frac fluids are sometimes steri-
lized with bactericides. This water will return when the well is
produced, bringing back some of the bactericide. This water must
be handled properly to avoid dumping chemical into the environment.
Directing this water through a water disposal system is an acceptable
alternative to dumping.
• Disposal of mud and packer fluids. Suitable practices must
be worked out to dispose of such fluids from each drill site. Be-
cause many other chemicals are also present in muds and packer fluids,
bactericides are only a part of this problem.
• Spills. The accidental upset is always a danger in any op-
eration. Properly designed SPCC plans for emergency actions to be
taken in the event of a spill will minimize contamination from this
source.
Mechanisms for Removal
In the event that some bactericide-treated water does escape to
the environment, certain natural forces will eventually reduce the
hazards.
• Dilution by produced or receiving waters. Bactericides are
189
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lethal only above certain concentrations. Dilution by other pro-
duced water and/or receiving water will reduce concentrations to
below hazardous levels.
• Absorption on clay and soil. Cationic bactericides such
as quaternary amines and other amines are readily adsorbed onto
clays and similar active surfaces. Anionic bactericides may also
be adsorbed by some soil particulates. In such form, the bacteri-
cidal function is inhibited. Therefore, bactericide in solution
which is spilled onto the ground may be leached from water by ad-
sorption, reducing the hazards to fish and aquatic life.
• Incorporation into benthic deposits. In streams and water
bodies there is a natural flocculation and precipitation process
which acts as a natural water purifier. This process can adsorb
dissolved surface active materials such as bactericides. In so
doing, the solids carry the adsorbed chemicals to the bottom to
become part of the bottom sediments.
• Biological decomposition. Although a bactericide in use
concentration is lethal to microorganisms, bacteria can and will
utilize the chemical once it is diluted below lethal concentration.
This method of removal is dependent upon sufficient dilution. But
it will take place whether the chemical is dissolved in water or
adsorbed on clay or bottom sediments in water. Substituted phenols
are the most resistant to microbial decomposition, and persist long-
er if lost into the environment.
• Reactions with other chemicals. Aldehydes and amines in the
environment of heavily treated muds may react with other chemicals
in the mud to produce a nonlethal chemical product. Although non-
lethal, loss of this material is still a pollutant.
• Polymerization at elevated pH. Prior to completion, most
muds are often made quite basic with caustic. This high pH will
cause polymerization of most aldehyde forms of bactericides and
salt out many amine forms. Loss after this occurs will be less
hazardous to the environment than loss of the unreacted bactericide.
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SUMMARY
Bactericides are often necessary additives to drilling and
completion fluids. Like other mud additives, they present a poten-
tial hazard to the environment if not used and disposed of properly.
Mud disposal is probably the most probable operation through which
bactericides may be introduced into the environment. Thus, mud dis-
posal should be carefully designed. Because bactericides must be
registered through Environmental Protection Agency procedures, a
great deal is known about the effectiveness, treating concentrations,
and health and environment hazards of the chemicals. Proper use of
these chemicals will reduce the chances of environmental damage
through normal usage.
SELECTED BIBLIOGRAPHY
Gawel, L. J., and R. L. Huddleston, Amer. Oil Chem. Soc. Mtg. April
1972, "The Biodegradability of Low Concentrations of Certain
Quaternary Ammonium Microbials by Bacteria."
Becker, C. D., and T. 0. Thatcher, "Toxicity of Power Plant Chemi-
cals to Aquatic Life," USAEC Report HASH 1249, UC 11 (Battelle
Labs), June 1973.
Kemp, H. T., et al., "Water Quality Criteria Data Book -Vol. 5
Effects of Chemicals on Aquatic Life," Office of R & D, En-
vironmental Protection Agency R-800942, Sept. 1973.
Mud Engineering, Magnetic Cove Barium Corporation, Houston, Texas.
191
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DISCUSSION
MR. H. H. ZUIDEMA (Shell Oil Company, Houston, Texas): Mr. Robichaux in
a table showed an LD5Q for birds, and LD5Q is usually expressed in
grams or milligrams per kilogram of body weight. Did I understand
that this was in grams per gram of total diet?
MR. ROBICHAUX: This is expressed in grams per kilogram of feed for the
bird.
There are two ways of determining an LD And I was more
familiar with your mechanism for determining the concentration of
the poison per kilogram of body weight of the deceased bird.
But in recent requirements of the EPA, they want grams per kilo-
gram of food that the bird consumes in a 3-day period.
MR. ZUIDEMA: Three-day period. Thank you.
MR. ROBERT B. ALLRED (Sun Oil Company, Richardson, Texas): Mr. Weir,
where did you get your samples? From underneath the shale shaker,
as I understood you to say?
MR. WEIR: That is right.
MR. ALLRED: That was hole mud, then?
MR. WEIR: It was hole mud, after the cuttings had been removed. We did
not have control over our samples which were supplied by the group
that we were working for. They were taken by the operator from the
shaker under flow.
*1R. ALLRED: That is not representative of what goes into the sea.
1R. WEIR: That is right; we knew that. We have tested other samples; we
have done toxic testing on actual discharge materials.
)R. JOSEPH G. MONTALVO (Gulf South Research Institute, Baton Rouge, Louisiana)
I would like to address a comment to all three of the panel members.
When one presents data on bioassays, one has to be quite careful that
the data does include a detailed chemical analysis of the consti-
tuents in the sample, if one is doing the bioassay work on a sample
such as barite or mud. This detailed list of chemical analyses
should include the major constituents, the minor constituents, and
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the trace constituents. I think in the field of pesticide bioassays,
it has been established fairly recently that in some instances the
measured toxicity was not due to pesticide in the study but was due
to the presence in the pesticide of a very minor impurity that had
a toxicity far greater than that of the pesticide in the study.
So I think these studies would be more meaningful if we were
provided with a list of the chemical constituents in the additives.
Thank you.
MR. ROBICHAUX: I agree wholeheartedly.
A lot of times, however, and particularly in the pesticide field,
as we find ourselves trying to register pesticides, we are given the
ground rules on which to play the game. And so we test the pesticide
as such.
Now, along with that, the pesticide branch of the EPA is fur-
nished with a complete list of active and inert ingredients. As a
matter of fact, you even have to supply them with your manufacturing
process.
So that while we quote here on the basis of generic types, I
agree with you that many things need to be said about it. If you
are talking about how dangerous a particular pesticide is, then you
take it as a whole, as if it were a whole chemical.
MR. CHARLES F. JELINEK (Food and Drug Administration, Washington, D.C.):
One thing that all of you in these operations should consider, is the
fact that the LD5Q acute toxicity tests are fine as far as determining
damage to certain biota in the environment. But then beyond that,
the most important biota to any of us personally is ourselves. We
have to consider the fact that fish may only have a few parts per
million of some contaminant in them, which will not damage them at
all, yet this level in the fish we eat might be quite damaging to
us. Therefore, materials such as the chlorinated phenols, which are
not biodegraded easily, are those that you should all be particularly
careful in handling. If they ever get into streams arid become bio-
magnified in the food chain, you might very well have concentrations
that would be toxic to you and me or any other consumer.
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DR. STEPHEN P. MURRAY (Louisiana State University, Baton Rouge, Louisiana):
As a physical oceanographer interested in currents and dispersion
processes, I am having a difficult time relating to the concern about
the levels of toxicity for different animals, the shrimp, rainbow
trout, and so forth. What do we expect in the environment itself?
We don't expect the extremely high concentrations that, I guess,
we are having in the lab studies. The natural processes in the sea
are extremely rapid around the offshore rigs and I am particularly
familiar with that.
If someone could provide a picture of what a mud spill would
look like, what would we really be up against in a significant acci-
dent on an offshore platform, had a lot of mud turned loose suddenly.
Or, are we looking at chronic spillage from the platform? I think
Mr. Weir mentioned he might even have some field concentrations;
those would be a lot more meaningful to me. What concentrations do
we expect in the real environment?
I tend to think that it would be very low, based on my exper-
iences with spray and oil spills.
MR. WEIR: Dennis Wright, a biologist from the Fisheries and Marine Ser-
vice, Environment Canada, could probably answer that.
MR. DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba, Canada):
We have been experimenting with "chironomid" larva--a freshwater
insect—and we have been able to show that very thin layers of
drilling fluids, one millimeter thick, will cause about a 50 per-
cent decrease in the survival of these insects over about a 3-week
period. And I think, judging from some of the studies that we made
in the Mackenzie Delta, that these layers are quite probable in the
environment.
We looked at one lake where they had a spill of some fluid; we
have seen up to about 5 or 6 millimeters of mud on the bottom, and
the bottom fauna has been severely reduced in this lake.
MR. CHESSER: May I make a comment to what we have seen offshore?
Lignosulfonate, of course, will impart a brown coloration to
the water at a relatively small concentration, and we have observed
195
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this over a number of years where water-base fluids have used
considerable amounts of the lignosulfonate and where these
cuttings have gone into the water. I have never seen any coloration
development from the fluid that has been attached to these cuttings,
which indicates it would be a relatively small amount at that point.
MR. DANNA W. LARSON (Exxon, Houston, Texas): Tomorrow afternoon Dick
Zingula will be addressing this subject, the insight to measurements.
DR. GEORGE R. HOLLIDAY (Shell Oil Co., Houston, Texas): Shell will also
be presenting a discussion.
Mr. Weir, I would just ask a question of you to be sure that
I understand.
Your values were presented in percentages, I assume, in parts
per million and milligrams per liter. We are talking about 90,000
parts per million as your minimum toxicity level; is that correct?
MR. WEIR: Well, what we measured was the hole mud sample. And it is the
percentage as it was diluted from 40 liters. Fifty percent was one
to one. So it was a percentage of the sample. It was the amount of
the dilution of the hole mud, which was not determined in parts per
million, no.
DR. HOLLIDAY: So we can relate that to parts per million to get some
correlation with that of the other gentleman?
MR. WEIR: Most of the work we have done in the hole muds have been in per-
centages. We have tried working back, but it doesn't work that well.
We have tried to do it on a parts per million basis by individual com-
ponents, but we have not been able to get reliable data.
DR. HOLLIDAY: Under those conditions, then, would you expect to dis-
charge half an ocean full of mud into the ocean so as to get this
pollution? I am having trouble getting the correlation between one
to one, if I discharge the mud into a receiving body of water.
MR. WEIR: We were not concerned in our experimentation with receiving
water. We were looking at the acute toxicity of the sample to be
controlled, not as to its effect on the receiving water or the dilu-
tion required to make it nontoxic. We were interested in what was
the toxicity characteristic of the mud, per se.
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MR. IRVING J. GRUNTFEST (Environmental Protection Agency, Washington, D.C.):
While the vendors are here, the question arises of what is the
fraction of a particular ingredient (for example, a bactericide) used
here of the total national production of that ingredient. Since we
are concerned with a domestic problem, is this in any case a substan-
tial or a dominant fraction of the total production of a particular
material used in this application? Or is it more typical that the
materials that are used here are used in enormously larger quantities
in other applications? I address the question particularly to the
vendors of the various materials. I think barium sulfate is probably
a material that is used to a greater extent here than in other appli-
cations I have heard of, but I think bactericides that you have
mentioned are probably used in much greater volume in other applications.
MR. ROBICHAUX: Speaking of bactericides, specifically, you are perfectly
correct. As a matter of fact, in our own company we have several
bactericides and we do not have any registered for use in drilling
muds.
That is not true with some of the others who are in the same
sort of business we are in. But I feel in the producing operations,
in secondary recovery operations, and in saltwater disposal opera-
tions, the preponderance of bactericides used in the petroleum
industry are used in other than drilling fluids.
As you say, the other chemicals that you find here would
probably fit a very wide spectrum because barium sulfate is most
heavily used in the drilling fluid business. As to how you would
have your chemicals distributed in industrial uses, I think you
would find everything from barium sulfate on one extreme to the
bactericides on the other.
W. RICHARD S. SCALAN (University of Texas, Marine Science Institute,
Port Aransas, Texas): Mr. Weir, I wonder, since your samples
came from below the shale shaker, whether you can eliminate the
effects of the materials that might have been picked up from the
borehole from your experiments?
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MR. WEIR: We did not look at the effects of the formation as to what it
is contributing to the toxicity on this sample series., but we have,
in other test series, looked at it and tried to see whether or not
the actual drill cuttings of the formation were contributing to the
toxicity of the samples. I cannot give any information about that.
It is still in the draft stage of the report.
MR. WRIGHT: Mr. Chesser, in your bioassays with the brown shrimp, did
you do any comparison between feeding and not feeding the organisms
during the test?
MR. CHESSER: No. We more or less followed the standard procedure where
we did not feed them 3 days prior to the test nor during the test.
We have made no variation of the feeding operation.
MR. WRIGHT: I see. It would seem highly probable that in an organism
with a high metabolic rate, such as the shrimp, that you could get
significant effects by not feeding them; they would probably starve
to death during the 7 days of the test.
MR. CHESSER: I don't believe so, because we have a control tank that is
not involved in any of the chemicals. We had good mortality rates
in that control tank.
MR. WRIGHT: What sort of mortalities were you observing in the control?
MR. CHESSER: For the most part there would be none. In some tests we
may have had one.
CHAIRMAN LUMMUS: I will attempt to summarize our session briefly. I
think you will agree that we have covered a lot of ground here
today in telling you people some of the techniques and methods
involved in drilling of an oil and gas well, and a water well, also
some of the chemicals used. We don't have all of the answers yet,
but at least I'm encouraged that some very substantial research work
is going on that's going to enable us in the future to document
some of the effects of some of these materials. This should be of
considerable help to the EPA in setting reasonable regulations, one
which all interested can live with.
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22 May 1975
Session II:
ENVIRONMENTAL IMPACT OF CHEMICALS
USED IN WELL DRILLING
C. S. Giam, Ph.D.*
Chairman
'Professor of Chemistry and Oceanography, Chemistry Department, Texas A & M University,
College Station, Texas.
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INTRODUCTORY REMARKS
C. S. Giam, Ph.D.
I think it is truthful to say that the organizer of this program is
quite brave. He is brave in trying to bring together biologists, engi-
neers, chemists, administrators, all under one roof to discuss the topic
of environmental impact. To handle such a topic properly will require
quantitative data, numbers, not just statements that at high concentra-
tions something happens, at low concentrations something happens. This
is not meant to criticize any previous speakers or future speakers but
only as a general statement. I think that to isolate a particular event
or an episode and say that under these conditions one observes toxicity,
or no toxicity, such statements are incomplete (because this episode may
not seriously affect the environment as a whole). It is a difficult
topic but I am glad that EPA has taken the trouble to organize this dif-
ficult conference.
I do not know in detail how the speakers were selected, but in every
conference there is just so much time, so there are constraints in select-
ing speakers.
Those who are officially speaking today will, obviously have a chance
to say what they feel about today's topic. But to those of you who are not
official speakers, I would suggest that you do contest, that you do agree
or disagree with some of the statements made. So I encourage as many of
you as possible to really state your case; wherever possible, minimize
your emotions, and have as many facts as you can.
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THERMAL DEGRADATION OF DRILLING
MUD ADDITIVES
Leroy L. Carney and Dr. Lawrence Harris*
Abstract
Muoh research effort and expense by service companies and oil
companies alike lias been devoted to studying the temperature stability
of drilling fluids. "Even though about 98 percent of the wells drilled
have bottom hole temperatures of less than 250° F, fluids must be de-
signed for drilling the wells which encounter temperatures above the
250° F range.
Since the rheology and fluid loss characteristics of drilling
fluids are influenced by additives that are primarily organic in nature,
their degradation with respect to increased temperature in drilling
fluid environments is discussed. Basically, with increases in tempera-
ture and pressure many reactions are catalyzed or expedited toward com-
pletion. Thus, reactions such as neutralization and hydrolysis are
very important in drilling fluid stability.
This paper groups drilling fluid additives into three temperature
ranges and discusses their relative temperature stabilities and degrad-
ation products. While the common additives used in drilling fluids have
been examined for temperature stability, we have selected some of the
most widely used additives for examples of how thoroughly these inves-
tigations have been carried out.
"Because of the complexity involved with many of these reactions,
a wide spectrum of analytical tools have been utilized to discern what
various degradation products are evolved with respect to incremental
increases in temperature.
Thermal degradation of lignosulfonates is discussed as an example
of a widely used drilling mud additive.
*Leroy L. Carney, Group Leader, Drilling Fluid Research, Chemical
Research and Development Department; Dr. Lawrence Harris, Development
Chemist, Chemical Research and Development; Halliburton Services, Duncan,
Oklahoma.
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INTRODUCTION
A survey of the 1974 Petroleum Engineering literature reveals the
following percentages concerning boreholes drilled in the United States
as equated to the average bottom hole static temperature encountered.
98.5 percent of boreholes were less than 250° F
1.3 percent of boreholes were greater than 250° F
but less than 350° F
0.2 percent of boreholes were greater than 350° F
Therefore, we might say that the majority of the industry's drilling
fluids and additives are not subjected to temperatures over 250° F.
However, a great portion of the research effort on drilling fluids and
related additives is devoted to studies involving temperatures above
250° F. A drilling fluid must be formulated to perform satisfactorily
over the total temperature range encountered during the drilling of a
particular well. Therefore, it is imperative to ascertain information
on the temperature stability of any additive that will be used in a
particular drilling fluid system. From a practical aspect, drilling
fluids are subjected to elevated temperatures and their performance
is observed. These evaluations, while useful for drilling purposes, are
empirical in nature but do not relate to actual temperature degradation
of the individual components in the system.
DISCUSSION
For this discussion, let us group some commonly used drilling mud
additives according to three temperature brackets:
I. Commonly used drilling fluid additives that do not perform
satisfactorily above 250° F:
A. Starches
B. Guar gum
C. Xanthanates
D. Orthophosphate
II. Commonly used drilling fluid additives that perform satis-
factorily above temperatures of 250° F, but not above 350° F:
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A. Sodium and calcium lignosulfonates
B. Tannins
C. Dual-substituted cellulose derivatives
D. Polyvinyl acetate/maleic anhydride copolymers
E. Certain surfactants
F. Some corrosion inhibitors
G. Carboxymethyl cellulose
H. Hydroxyethyl cellulose
III. Additives that are temperature stable above 350° F:
A. Clay minerals
1. Bentonites
2. Attapulgites
B. Weighting Materials
1. Barium sulfate
2. Calcite
3. Iron carbonate
4. Iron oxide
5. Lead sulfide
C. Salts
1. NaCl
2. KC1
3. Calcium sulfate
4. Calcium chloride
D. Bases
1. Sodium hydroxide
2. Calcium hydroxide
3. Potassium hydroxide
E. Lignites
1. Mined lignites
2. Caustisized lignites
3. Sulfoalkylated lignites
F. Modified lignosulfonates (organometallic)
G. Acrylates & acrylamides
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H. Most lost-circulation materials
I. Asphaltenes and gilsonites
The materials listed above by temperature groupings are by no
means ironclad, since overlapping of some of these materials does
occur in regards to temperature functionality. Also to be considered
are complexes which form with hydrated bentonite particles. For ex-
ample, certain bentonite/guar complexes will maintain a rigid gel
structure above 400° F.
Since bentonite is the basic ingredient of water-base drilling
muds, the interaction of additives with bentonite must be considered
in all cases. Due to this interaction, the thermal stability or
functionality of organic drilling fluid additives will vary considera-
bly and are determined under the conditions of the drilling fluid sys-
tem employed.
The thermal stability of cellulose derivatives are especially
susceptible to the pH, oxygen content, and metal ion concentrations of
the drilling fluid. For example, CMC is more stable to temperature in
a pH range of 7 to 9 (ref. 1). The change in characteristics of CMC
solutions that may occur during storage or actual use under drilling
fluid conditions is usually observed as a decrease in the apparent
viscosity of the system.
This viscosity decrease that occurs upon heating to temperatures
of 200° F in the absence of oxygen or other oxidizing agents is caused
by a decrease in the intramolecular bonding in the CMC polymer that
allows the polymer chains to uncoil. This effect is reversible and the
viscosity will return as the drilling fluid is cooled.
As the temperature is increased above 250°-300°F, the additional
viscosity reduction that results may be caused by scision of the poly-
mer chains, resulting in a decrease in the degree of polymerization (DP)
This change is permanent and the viscosity will not return upon cooling.
At these higher temperatures under highly alkaline conditions in
the presence of oxygen or other oxidizing agents, oxidative degradation
of the cellulose polymer chain occurs (lower DP). The degradation
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temperature will be considerably lower in the presence of oxidizing
agents. Peroxide formation is the primary result of oxygen attack on
the polymers (ref. 2). Decomposition of the peroxides can lead to
polymers (ref. 2). Decomposition of the peroxides can lead to polymer
degradation resulting in permanent loss of viscosity. Wheatham found
that at a pH of 12.3, a reducing condition minimized the rate of de-
gradation at 350° F (ref. 3).
The presence of certain trivalent metal cations can extend the temp-
erature limit of some cellulose derivatives by introducing crosslinking
in the polymer chains.
Certain other mud additives that we have considered as less temp-
erature-stable (<300° F) are starches, xanthan gums, guars, vinylacetate/
maleic anhydride copolymers, and polyphosphates. Guar gums, starches, and
xanthan gums can undergo oxidative temperature degradation in the
presence of oxidizing agents. Xanthan gums will deacetylate at pH > 9
but this affects the system viscosity very little. The presence of small
amounts of salts will increase the heat stability of xanthan solutions
and trivalent metal cations can crosslink this polymer to increase heat
stability. These are just a few examples of some ramifications that
can occur in drilling fluid systems.
While empirical data is relied upon for practical applications
of drilling fluid, much research effort has been expended behind the
scenes, resulting in detailed studies of various drilling fluid addi-
tives. Let us look at lignosulfonates as one example. Modified lig-
nosulfonates gained rapid prominence as a very effective dispersant
in water-base drilling fluids. They are used successfully at moderately
high temperatures, but incremental amounts must continuously be added
to maintain effectiveness at higher down-hole temperatures. The greater
depths and increasingly higher temperatures of recently drilled oil
wells thus indicate a need for determining more precisely the effect of
temperature on drilling mud additives.
The complexity of the lignin molecule from which the lignosulfon-
ates are derived, has made quantitative determinations difficult, parti-
cularly in drilling mud systems. A study was designed by Skelly &
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Kjellstrand (ref. 4) to determine the temperature at which lignosul-
fonate decomposition begins and the extent to which it proceeds under
various Conditions. This study was primarily chemical in nature and
was not intended to prescribe absolute limits on the use of lignosul-
fonates under field conditions.
A standard procedure for achieving the aims of the program was
developed (ref. 4) utilizing appropriate apparatus; it consisted of
the following steps:
1. To 350 ml of a 5 percent bentonite slurry was added 25 g
of lignosulfonate dispersant, followed by 233 g of barite,
both with thorough mixing. The resulting mud weighed approx-
imately 12 Ibs/gal.
2. The slurry was adjusted to pH 10 with sodium hydroxide.
3. The entire mixture was charged to a stirred autoclave equipped
with a high-pressure water-cooled reflux condenser and nitro-
gen inlet valve.
4. The autoclave was pressurized to 400 psig with nitrogen and
the apparatus checked for leaks. A valve at the top of the
condenser was opened and the apparatus vented to atmospheric
pressure and the valve closed.
5. The mud was then heated to the desired temperature with stir-
ring and held at that temperature for 2 hours.
6. The reaction vessel was pressurized to 400 psig with nitrogen.
This was done as a practical expedient to prevent flooding of
the condenser during the following step.
7. The valve at the top of the condenser was opened slightly to
allow the gases to escape at a rate of 9 liters/hour.
8. The vented gases were collected for 2 hours in a scrubber
containing 500 ml of standard sodium hydroxide solution
while maintaining the desired temperature. The pressure
was maintained at 350-400 psig with nitrogen during the
venting period.
9. Gas samples (200 microliters) for gas chromatographic analy-
sis were removed from a point in advance of the scrubber
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every 20 minutes during the venting period.
10. Carbon dioxide was determined by titrating aliquots of the
scrubber solution with standard hydrochloric acid and cor-
recting for acidity due to hydrogen sulfide.
11. Hydrogen sulfide was determined by acidifying aliquots of
the scrubber solution and titrating with standard iodine
solution to a starch end point.
IDENTIFICATION OF GASEOUS PRODUCTS
The products of the reaction were identified in part by mass spec-
trometry, gas chromatography, infrared spectroscopy, polarography,
chemical analysis and paper chromatography.
Noncondensable gaseous products from the reaction at 410° F were
identified as carbon monoxide, carbon dioxide, and hydrogen sulfide.
Traces of methyl mercaptan were also present. A mass spectrographic
scan from mass 0 to mass 500 showed pertinent peaks at mass numbers
34 (hydrogen sulfide) and 47 (methyl mercaptide radical). These data
were obtained by bleeding the gases directly from the reactor into the
mass spectrometer. Carbon monoxide was determined qualitatively by
means of an M.S.A. carbon monoxide indicator tube. Carbon dioxide was
identifed by gas chromatography, utilizing a one foot by one-fourth
inch aluminum column packed with silica gel (ref. 5). The concentra-
tion of the sulfur-containing gases in most cases was too low to be
detectable by this method. Hydrogen sulfide was verified chemically
by reaction with lead acetate and with cadmium acetate. A method for
differentiating between hydrogen sulfide and methyl mercaptan em-
ploying mecuric cyanide and mercuric chloride was used; however, the
methyl mercaptan concentration was too low for detection by this
method (ref. 6).
DEGRADATION TEMPERATURE STUDIES
A series of tests were carried out in which the temperature was
varied from 280° F to 450° F. Results showed that hydrogen sulfide
evolution was negligible below 400° F but became significant at 450° F.
209
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Reagent blanks showed that significant quantities of hydrogen sulfide are
not emitted at any of these temperatures when lignosulfonates are absent.
The evolution of carbon dioxide in this same series, however, is a
better measure of the temperature at which lignosulfonate degradation
occurs.
The effect of heating for two 4-hour periods showed that gas evolu-
tion began to approach a significant level at about 370° F. At 450° F,
the evolution of carbon dioxide became excessive, compared to the poten-
tial carbon dioxide possible from the complete degradation of the ligno-
sulfonate. For example, based on an analysis of lignosulfonate for car-
bon (39.3 percent), hydrogen (4.85 percent), sulfur (5.81 percent) and
ash (20.41 percent), the quantity of oxygen (calculated by difference)
present in the molecule would prevent the formation of more than 10.0 g
of carbon dioxide from the quantity of lignosulfonate used. (This
assumes that only a negligible quantity of dissolved oxygen was present
since the experiments were conducted in a nitrogen atmosphere.) Based
on this figure, it was shown that 21 percent of the potential carbon
dioxide can be collected after two 4-hour heating periods at 450° F.
This does not include additional decomposition, as evidenced by the
formation of carbon monoxide that was not measured quantitatively in
these experiments.
The rate of carbon dioxide formation was indicated by plotting
gas chromatographic peak heights vs. time. This data was somewhat ob-
scure because gaseous products were allowed to collect for 2 hours be-
fore venting was started. Therefore, a plot was made using data ob-
tained by starting the venting under 400 psig of nitrogen as soon as the
desired temperature was reached. Heat-up time is still a factor; but,
as would be expected, the magnitude of the peaks becomes higher and the
slope of the curves becomes steeper as the temperature inceases. At
450° F, the plot does not give a straight line. During the first hour,
the decline in apparent reaction rate is quite rapid. During the final
3 hours, however, the rate of decline is much slower, particularly
when compared to the slopes obtained at lower tempratures.
The effect of removing some of the mud components from the system
210
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was studied. A change in the pattern of gas evolution was noted when
barite was removed from the system. In the absence of barite, a notice-
able increase in the evolution of hydrogen sulfide occurred at 410° F.
This effect was even more apparent at 450° F. The increase in produced
hydrogen sulfide was accompanied by a slight decrease in the quantity
of carbon dioxide evolved. In view of this, the study of gas evolution
from lignosulfonates at lower temperature, 280° F-3700 F, was repeated
without barite.
It was interesting to note that the "barite effect" was not seen
at temperatures of 370° F and lower.
The final pH of the muds (6.0-7.6) after heating 4 hours was lower
than in previous tests in which barite was present. With barite present,
the final pH was normally 8.0-8.2.
ANALYSIS OF RESIDUAL PRODUCTS
The study of the nonvolatile residual components of the reaction
mixture presents a more difficult analytical problem than a study of
the gaseous products. For example, literally hundreds of organic com-
pounds are possible from the degradation of lignosulfonates and an ab-
solute identification of all such products formed would be impractical
and of little importance with respect to drilling muds. Some brief
studies were made, however, to learn something of the nature and type
of residual products that form during thermal treatment of lignosulfonates,
Paper chromatographic analyses were made on filtrates obtained after
heating lignosulfonate solutions at 410° F and 450° F. The formation of
at least two phenolic type products (Rf. 0.14 and Rf. 0.91), not origi-
nally present in the reaction mixture, was detected. In addition, one
compound found in the unheated reaction mixture (Rf. 0.27) was present in
a greater quantity after heating. The chromatograms were developed in
a 4:1:1 butanol:acetic acid:water system and sprayed with a 0.5 percent
alcoholic solution of 2,6-dichloro-l,4-quinone-4-chlorimide (ref. 7).
As a matter of interest, vanillin and isoeugenol, two of the more common
products derived from lignin, were chromatographed in the same solvent
system giving Rf's of 0.91 and 0.94. Odors reminiscent of these com-
pounds were detectable in filtrates heated at 410° F and 450° F.
211
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Another approach involved analysis of the liquid and solid phases
of the residual products for total carbon. After removal of the gaseous
decomposition products, the residue was thoroughly stirred and an
aliquot was pressure filtered exhaustively until the filter cakes were
essentially dry. The filter cakes were analyzed for total carbon by
the standard carbon hydrogen method. The filtrates were analyzed for
carbon by a modified Van Slyke carbon dioxide method. The carbon con-
tent of the filter cakes was higher after heating at 450°F than after
heating at 280°F and 410°F indicating insolubilization of the ligno-
sulfonate products, probably by polymerization and/or carbonization.
Further clues as to the distribution of the organic phases of the
mixture can be obtained by analysis of the filter cakes and filtrates
for sulfur (assuming that complete cleavage of the sulfonate group has
not occurred).
It had been hoped that iron and chromium analyses would be helpful
in determining the distribution of organic matter between the filter
cake and the filtrate. Initially, the chromium is present as a ligno-
sulfonate complex that is completely soluble in water at pH 10.
In the presence of bentonite and barite, however, chromium is
essentially completely retained on the filter cake both before and after
heating. The small quantities of chromium noted in the filtrates
before heating are reduced even further after heating. This was indi-
cated by polarographic analysis to be in a complexed form. No evidence
of soluble noncomplexed chromium was noted in any of the tests.
An interesting facet of the data was that most of the chromium
is retained on the relatively small quantity of solids formed during
heating of aqueous solutions of ferrochrome lignosulfonates at 410°F
and 450°F. Similarly, iron was also found to be concentrated primarily
on the filter cake.
Some conclusions drawn from this investigation by Skelly and
Kjellstrand were:
1. The major gaseous product liberated during lignosulfonate
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degradation was carbon dioxide. Hydrogen sulfide and
carbon monoxide were formed in lesser quantities. Traces
of methyl mercaptan were also present.
2. Under the stated conditions, lignosulfonate degrada-
tion begins at about 330°F and progresses continuously
until serious decomposition is noted at 450°F.
3. In weighted mud systems, the evolution of hydrogen
sulfide is negligible at temperatures below 410°F.
4. As would be expected, the rate of gas evolution becomes
increasingly more rapid as the temperature increases.
5.. Removal of barite from the system changes the pattern
of gas evolution, particularly with respect to hydrogen
sulfide evolution at high temperatures.
6. Phenolic type compounds are formed during the reaction.
7. Part of the organic phase of the reaction mixture is
insolubilized after heating.
8. The complexed iron and chromium of the ferrochrome
lignosulfonate are retained on the filter cake both
before and after heating of lignosulfonate-based muds.
From the empirical data of mud rheology versus temperature and a
detailed chemical study of thermal degradation of lignosulfonates, it
has been concluded that lignosulfonates definitely temperature degrade,
Because of this definite temperature degradation of lignosulfonates
in drilling fluids and its importance by the function of the fluids,
a method was devised by Carney, Skelly, and Gullickson (ref. 8) to
determine the quantity of undegradated lignosulfonates in drilling
the quantity of undegradated lignosulfonates in drilling fluid systems.
The first step of the method basically consists of suspending a
small sample of the drilling fluid in water; one milliliter is usually
sufficient. Ammonium acetate is added to the dilute water suspension
in order to buffer the solution and to flocculate the clay minerals
that are present. The suspension is then centrifuged until the clay
minerals and other solids are separated from the lignosulfonates.
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The supernatant solution is examined by ultraviolet absorption, and
the optical density difference due to the 281 nm peak is determined
(figures 1 and 2). This difference can then be related to the con-
centration of lignosulfonate present in the original sample.
The following general procedure is applicable to most water-base
drilling muds containing modified lignosulfonates:
1. Pipette 1 ml of mud from a well-stirred suspension.
2. Dilute with water to 200 ml, add 5 ml of IN ammonium
acetate and dilute with water to 250 ml (higher and
lower dilutions may be used, depending on the con-
centration of lignosulfonate in the mud).
3. Centrifuge aliquots of the well-mixed suspension at
13,000 rpm for 10 to 15 minutes.
4. Place a portion of the clear supernatant solution in
a 10 mm silica cell. Scan and record the spectrum from
320 to 240 nm. Any scanning instrument capable of
operating from the 500 to 240 nm wavelengths is suitable.
(Beckman DBG and DBGT instruments were used.)
5. From the chart, measure the difference in optical
density due to the 281 nm peak. Determine the llgno-
sulfonate concentration by reference to an appropriate
standard curve.
By using the ultraviolet absorption spectrum and the absorption
maximum of lignosulfonates at about 281 nanometers, the following
conclusions were ascertained using the optical density difference
as related to the presence of lignosulfonate.
1. The concentration level of lignosulfonate in a water-base
drilling fluid can be determined.
2. The relationship between the optical density difference
obtained by ultraviolet absorption and analysis, and
rheology, can be used as a reference point to maintain the
optimum treatment level for lignosulfonates in drilling
mud.
214
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14 LB/GAL LIGNOSULFONATE
IN WATER
O.D.
DIFFERENCE
0.810
-0.486
0.324
225 250 275 300 325 350
WAVELENGTH (NM)
Figure 1. UV absorption maxima of lignosulfonate.
215
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Z
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UJ
to
s=
o
o
c
o
o
CO
3
o
•r—
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3. The lignosulfonate content of the treating chemical can
be monitored to insure product quality of the material
on location.
4. The effects of high temperatures in a mud system can
be determined and remedial action taken.
5. Various points in a mud system can be monitored. For
example, the amount of lignosulfonate present in a fluid
before and after centrifugation can be determined and
a material balance made.
6. The quantity of lignosulfonate left on solids retained
on shaker screens can be estimated and the quantity in
the mud passing the screens determined.
7. Mud filtrates can be analyzed to show a relationship
between total lignosulfonate contained in the system and
the amount of lignosulfonate that will pass through the
filter cake and be carried by the filtrate.
In conclusion of this paper, we would like to point out once
again that temperature stability of drilling fluid systems are under
continual research study in many laboratories and temperatures above
700°F are currently under investigation.
REFERENCES
1. John Kelly, Jr., "Oxidative and Thermal Degradation of Technical-
Grade Sodium Carboxymethyl Cellulose in Drilling Muds at 300°F and
350°F," Socony Mobil Oil Co., Dallas, Texas, 1968.
2. L. F. McBurney, Ind. Eng. Chem., Vol. 41 (1949), p. 1251.
3. P. E. Whetham, "The High Temperature Stability of Sodium Carboxy-
methyl Cellulose in Drilling Fluids," API Drilling Fluid Study
Committee, Houston, Texas, May 23, 1958.
4. W. C. Skelly, and J. A. Kjellstrand, "The Thermal Degradation of
Modified Lingosulfonate in Drilling Mud,: API, Division of Pro-
duction, Dallas, Texas, March 2-4, 1966.
5. C. T. Hodges and R. D. Matson, Analytical Chemistry, Vol. 37, No. 8
(July 1965). JL
6. F. Challenger, "Aspects of the Organic Chemistry of Sulfur," Academic
Press, New York, 1959, p. 18.
217
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7. M. R. Sahasrabudhe, Journal of the A.O.A.C. , Vol. 47, No,, 5 (1964).
8. L. L. Carney, W. 6. Skelly, and R. Gul licks on, "Quantitative Deter-
mination of Lignosulfonates in Drilling Fluids by Ultraviolet
Absorption Analysis," AIME Fall Meeting, New Orleans, La,., Oct. 1971.
DISCUSSION
DR. VLADIMIR ZITKO (Environment Canada, Winnipeg, Manitoba, Canada): Did
you find any difference in stability between the lignosulfonates from
the sulfite process and lignosulfonates from the kraft process? I
understand both are used.
MR. CARNEY: There would be quite a difference. Lignosulfonates from the
sulfite process, where we normally use what is called a "bisulfite,"
cook, where your wood chips up to that point are treated the same
as in the kraft process; however, here they are put in a digester.
In the digestor is put freshly prepared bi]sulfite cooking liquor.
This can either be calcium, sodium, or ammonium bisulfite. Under
temperature, pressure, and long cooking, this sulfonates the alpha
carbon atom on a phenylpropane chain of the benzene range. This deams
the lignin, which up to that point is used as a binding agent, water
soluble, over the entire pH range.
As a matter of fact, the pH, when it comes out of the digestor,
is about 1. This is taken, then, into multieffect vaporators and
evaporated up to about 50 percent solids. It can then go various
ways. It can be desugared; it can be stripped of the loosely oc-
cluded sulfur dioxide, and so on.
The kraft lignin, even though you take the chips like
the bisulfite process, is quite a different process in that you
are dealing with high alkalinity. You are getting back to what we
used to do in drilling fluids by using quebracho extracts, and this
type of thing, where we mixed these with caustic soda, taking advantage
of the alkalinity for solubility. Therefore, those muds could not run
at lower pH's; you would have a pH of 12.5 or higher. So your
kraft cook is a very high pH cook, but by taking advantage of this you
then separate the lignin from the cellulose. If you reduce the pH of
your kraft lignin, commonly called black liquors, you would drop out
the lignin as totally water insoluble. Now, you could use this as a
218
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source of lignin and sulfonate this through conventional sulfonation
reactions, but you're adding onto the cost here because you are al-
ready making a separation; then you have a subsequent sulfonation,
which would run the cost of the sulfonated kraft lignin fairly high.
Some of this may be used, but I would say probably in limited
quantities in relationship to the bisulfite process sulfite liquor.
You would have a purer lignin, from the kraft process and you
could actually change your degree of sulfonation. This makes it use-
ful as wetting agents, which are partially soluble materials that can
be used and made into combination weighting agents and dispersants.
But I would say that the kraft lignin has a very limited use as drill-
ing fluid dispersants.
CHAIRMAN GIAM: I notice from your slide, that high-temperature drilling
conditions are at a very low percentage. In the near future would
you expect more wells with high temperatures?
MR. CARNEY: Well, this is a pretty difficult question to answer because
you have some experts who study the decomposition of hydrocarbons
that truly do not think you will find hydrocarbons at the greater
depths and temperatures. You have others that think that you will.
We have, as mentioned yesterday, two wells that were drilled
in Western Oklahoma—one to 29,500 feet and one to 30,441 feet.
These were completed upper hole at about 14,000 to 15,000 feet with
some gas show. There was no commercial productivity at those
depths where the temperature was 450° to 470°.
CHAIRMAN GIAM: I would like to pose this question to those of you who are
dealing with drilling muds at high temperature. If, indeed, you do
have pentachlorophenol in your system, say two molecules of it, and
if, indeed, you do have sodium hydroxide, and if, indeed, you do have
high temperatures, I would imagine that a cylindrical drilling hole
would resemble a beaker or flask (chemical reaction vessel), perhaps —
and I use the word perhaps—to carry out a condensation reaction
(that is, pentachlorophenal condenses to the highly toxic octachlorodi-
benzo dioxin). Under certain conditions, pentachlorophenol, with a
base at high temperatures, will, on paper, anyway—and this statement
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has to be verified—condense to give you a compound called dioxin.
If, indeed, it gives dioxin, dioxin is one of the most potent toxins.
Before I go on further maybe I could ask Dr. Zitko. Are these
conditions likely to give dioxin?
DR. ZITKQ: Yes. I think these conditions are likely to give dioxin. But
I do not think anybody looked: it has not been determined whether it
actually happens.
MR. CARNEY: Well, let me say this. You may take some of these things in
the laboratory and you may put them in the autoclaves and react them,
and certainly you would form some of these reactions because tempera-
ture and pressure normally are catalysts for various reactions.
However, as I pointed out before, if you had a well in which the
bottom temperature was going to be 400 degrees, I do riot think you
would sell any operator on a starch mud. Therefore, fortunately, when
we have drilling fluid programs designed for high temperature, we nor-
mally would not have these materials present. So they do not have an
opportunity under these extreme downhole conditions to get together.
Certainly, we do use caustic. Certainly, as temperature in-
creases the reactivity of the caustic increases.
But, normally, we would not have a material like this in a hot
mud.
DR. PAT M. WENNEKENS (Alaska Department of Fish and Game, Anchorage,
Alaska): There is one aspect I would like to inquire about concern-
ing physical chemical processes. As you go deeper and deeper you are
going to go into some hyperbaric conditions in which the pressure
effects are also going to influence your reactions. And I would like
to get into perspective, essentially, what the effects of both pres-
sure and temperature are going to play in your evaluation of your
chemical reactions.
MR. CARNEY: That is a very good question. These things are under contini
ous study. Once again, it is quite expensive, because the equipment
that we must use to reach high pressure and high temperatures in thes
reactions is quite expensive.
We have autoclaves that we are now studying drilling fluids at
700 degrees and 50,000 pounds of pressure. These little jewels are
220
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quite expensive, and one or two runs on those runs into a lot of
research money. But pressure is certainly being considered as is
temperature.
Now, I emphasized temperature here today because that was the
topic of this paper. But along with the temperature we also include
the pressure. So, just as in cementing schedules, we run certain
casing schedules; we run the temperature and the pressure that would
accompany that.
Certainly this does have effects, we find, and we have to some-
times be the leaders in the field, in studying pressure effects on
solubilities. Regarding hydrogen sulfide for example that we some-
times are concerned with, we cannot find in the literature, even solu-
bility in various media at high temperatures and pressures. We have
the proper equipment and have actually injected hydrogen sulfide in
all of its forms at 400 degrees Fahrenheit and 20,000 pounds of pressure
and studied the reaction mechanisms and the end products, and the solu-
bilities. Sometimes it becomes important where you would have a greater
solubility under pressure, and if you bring materials uphole and the
pressure is released, then you may have gases flash off because you have
supersaturated the solution due to the pressure.
221
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GROUND-WATER PROBLEMS ASSOCIATED
WITH WELL-DRILLING ADDITIVES
D. Craig Shew, Ph.D., and Jack W. Keeley*
Abstract
The importance of ground water -is discussed along with the conse-
quences of its degradation. The subsurface environment as a receptor
of pollution is discussed in terms of its biological, chemical, and
physical characteristics. Suggestions are made as to the technology
required for preventing ground-water contamination.
Since many of the topics covered in this session—including the
degradation, contamination potential, movement, and toxicity of well-
drilling chemicals--deal directly with the ground-water problems
associated with these chemicals, and since it would be presumptuous
to attempt to compete with experts in these areas, I think it would
be of greater value to discuss the subsurface environment as a recep-
tor of these materials and then perhaps to pose a challenge to those
whose profession brings them to the exploration of oil, gas, water,
and our natural resources.
It is, indeed, gratifying that this conference is even consider-
ing ground water as a part of the environment. Not too many years
ago, our subsurface water resources were not given consideration in
forums such as this and were not even mentioned in polite society.
It has only been recently that scientists have begun to appreciate the
vastness of ground water and have begun to consider the consequences
of its destruction.
It is surprising to realize that while 95 percent of this country's
freshwater lies below the surface of the earth, most of our laws, re-
source planning, research, and academic training deal primarily with
*D. Craig Shew is Research Chemist and Jack W. Keeley is Chief,
Subsurface Environmental Branch; Robert S. Kerr Environmental Re-
search Laboratory, U.S. Environmental Protection Agency, Ada, Oklahoma.
223
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surface waters. Consequently, when we are done with these activities,
our money is spent, and our human resources have gone on to other
things, we will have addressed something less than 5 percent of our
water problems.
It is not surprising that ground water has been neglected by just
about everybody. You cannot swim or fish in it or go on midnight strolls
along its shores. Even our august courts have held ground water in awe.
Allow me to read a decision from the early part of this century in
which the courts passed judgment on this vast resource which accounts
for over 95 percent of our freshwater:
The laws of its existence and progress cannot be known
or regulated. It rises to great heights and moves
collaterally by influence beyond our apprehension. These
influences are so secret, changeable, and uncontrollable,
we cannot subject them to the regulation of law, nor build
upon them a system of rules. Because the existence, origin,
movement, and course of such waters, and the causes which
govern and direct their movement are so secret, mysterious,
occult, and concealed, an attempt to administer any set of
legal rules in respect to them would be, therefore,
practically impossible.
In keeping with tradition, in 1971 the Senate Public Works Committee on
the Federal Water Pollution Control Act Amendments stated that because
"the jurisdiction regarding groundwater is so complex and varied from
State-to-State" EPA was not being given authority to set standards in
this area. So, we can see that the importance and, indeed, the
existence of ground water has been an extremely difficult thing to
grasp. We find that the implications of its destruction are exponen-
tially more difficult to deal with. This is due principally to the
lethargic nature of the movement of ground water and the more subtle
movement of pollutants through either the saturated or unsaturated
subsurface environment. The retention time of pollutants in this
environment is commonly measured in decades or centuries as opposed to
air where it is measured in hours or in reservoirs where pollutants
remain for a matter of months. The obvious conclusion then becomes
that we simply cannot allow this underground water resource to become
polluted and lost because it cannot economically be recovered.
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We all know that the nitrate ion is highly soluble. There are
reports, however, that indicate that under the influences of rainfall
and evaporation, the nitrate ion may take from 8 to 50 years to move
only 30 meters downward in alluvial material. It is a reasonable
assumption that some organic compounds and their degradation products
or metals would move at a considerably slower rate. We can draw the
reasonable conclusion that ground water could be monitored for many
years near a suspected source of pollution and be declared safe while
in fact pollutants are surely and inevitably moving to or through the
aquifer.
As a receptor of pollution, the subsurface is an extremely com-
plex environment which changes dramatically in only short distances--
vertically or horizontally. A pollutant entering a medium-textured
soil would find an extremely large available surface area over which it
must pass. For example, the surface area 10 feet below and 5 feet on
either side of a septic tank lateral 50 feet long would be roughly
equal to the wetted surface of the Mississippi River from its conflu-
ence with the Ohio to the Gulf of Mexico. In traversing an area of
this magnitude, the chances are good that a pollutant will undergo
physical, chemical, or biological alteration.
Biological activity is certainly of prime interest in the movement
and fate of pollutants in this subsurface world. Almost all of the
knowledge we have in this area is confined to the topmost layers of
the earth's crust known as the true soil zone. We know that in this
area an intense biological community exists which is biochemically
diverse and multitudinous. It is an area where biological climate can
change from aerobic to anaerobic within small distances dependent upon
the nature of the waste, the availability of moisture, and the poten-
tial for aeration.
We are aware that aerobic bacteria are principally responsible for
waste stabilization in conventional treatment facilities. We have
found that anaerobic bacteria can also play an important role in the
degradation of those pollutants which are considered to be stable.
DDT, for example, has been found to degrade rather rapidly in an anaero-
bic subsurface environment. NTA, the proposed substitute for phosphates
225
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in detergents, was found to degrade anaerobically. We find ourselves
interested not only in the parent compound but its degradation products
which may even be more toxic or more soluble than the parent compounds.
The movement of bacteria and viruses is proportional to the size
of the voids available for their passage. Where bacteria generally
measure a few microns in size, viruses are smaller by roughly two
orders of magnitude. The nature of the subsurface then becomes para-
mount where highly fractured formations will allow passage for consider-
able distances, while consolidated sands, for example, will prove quite
limiting.
Of course, if we are to consider the subsurface biological community
in terms of its capacity to degrade pollutants with which it comes into
contact or the contamination problems that biological life may cause,
we must also consider viability in addition to the ability to move
through the subsurface environment. Subsurface water generally experi-
ences an increase in salinity with depth. Surprisingly, however, we
can find highly mineralized water at very shallow depths while relatively
fresh water can occasionally be found in rather deep formations. Al-
though the availability of water to microbes is limited with increased
osmotic pressure, many species of bacteria grow in highly mineralized
water, even up to 30 percent salt.
Temperature is one of the most important and limiting factors
to the survival of microorganisms, although the effects of pressure,
acidity, and other parameters cannot be disregarded. Generally,
optimum growth for predominant species ranges between 25° and 40°C with
the ultimate temperature for survival being 80° to 100°C. In the upper
layer of the earth's crust, biological activity is a direct function
of seasonal temperatures; while at increased depths, temperature fluctua-
tions are reduced. Temperatures increase generally at about 30°C for
every 1,000 meters of depth. At this rate of increase, most biological
activity would be prevented at about 1,800 meters (5,900 feet) and
would virtually cease below 2,500 meters (8,200 feet).
Hydrostatic pressures increase at about 0.1 atmosphere for every
meter of depth, or something less than 0.5 psi per foot. We know that
226
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there are many exceptions to this rule of thumb, but the point remains
that pressure increases with depth. Generally, microbes are capable
of growing at 200-300 atmospheres provided other factors are acceptable.
Although some biological activity has been reported above this pres-
sure, it would seem that the increase in temperature would be limiting
before the increase in pressure.
In order for biological activity to occur, there are several
conditions which must be satisfied. Carbon in the form of carbon dioxide
or organic matter along with lesser quantities of nitrogen, phosphorus,
and sulfur in either organic or inorganic form must be present for the
synthesis of protoplasm. The subsurface offers a plentiful source of
carbon, principally in the form of carbonates; but, appreciable amounts
exist as organic matter incorporated into sedimentary deposits at the
time of their formation. Although much of this carbon is in petroleum
deposits, even greater amounts are present in a finely disseminated
bitumen.
Nitrogen, phosphorus, and sulfur are probably available in the
subsurface as organic or mineral matter. Like carbon, these nutrients
are required for all biological life, but in lesser amounts. It would
not seem likely that they would limit such activity. The possibility
remains high, however, that limited availability of one or more of these
elements will restrict the level of microbial activity.
The availability of molecular oxygen is pretty well confined to
the upper layer of the earth's crust where replenishment can occur by
gas interchange. Even here, its presence is a function of the rate of
gas exchange and the utilization of microorganisms. Although this area
is not often important in drilling for oil or gas, it is critically
important when dealing with water table aquifers where pollutants must
pass through it during the percolation of recharge water.
Since deeper formations are far removed from the zone of aeration
and the movement of water and the rate of recharge is near zero, it is
not likely that appreciable oxygen or other easily reduced matter could
be present. However, the electron acceptors for truly anaerobic
organisms are probably present in large quantities at these low depths.
The availability of electron acceptors is limiting in the sense that
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they are replenished at a very slow rate which would account for low
biological activity allowing the survival of organic matter, particu-
larly petroleum, over long geological times.
The existing state of knowledge is not advanced enough to allow
more than speculation on how long microorganisms have been in some of
these deeper formations. It is complicated because those organisms do
not differ from those found at the surface. Those found in deep forma-
tions may have been deposited with the sediments millions of years ago,
or they may have migrated there over very long times. Many do have the
capacity to propel themselves either to reach better living conditions
or to escape a more hostile environment.
The overriding point is that while drilling we pass through forma-
tions which permit the existence and activity of biological life. The
community has obviously been in a rather delicate balance for very long
periods of time. While drilling we introduce, at least locally,
additives which disturb this ancient biological balance, and it is the
consequence of this disruption that is of importance to us at this
gathering. The significance of such a disturbance to ground-water
pollution and pollution control resides in the potential interactions
of the microorganisms and pollutants introduced and these interactions
on the quality and availability of ground water.
Conceptually, we would consider that altering an existing biological
community would be beneficial in that organics can be eliminated and
nitrates reduced by denitrification. There is also some evidence that
the metabolic products of degradation of some drilling additives might
be less desirable than the parent compounds either from the standpoint
of toxicity or in the reduction of permeability.
At this point, I think some of our experience in subsurface
research is pertinent. We have found, for example, that DDT which
was considered biologically stable is in fact degraded in the sub-
surface environment. We know that DDT has been considered particu-
larly toxic to man. In ground water, DDT does not migrate to any
great extent due to its low solubility and high affinity for formation
material. The important question then concerns the nature and
228
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solubility of the anaerobic degradation products. If they become
free to move through the aquifer and are more toxic than the parent
compound, our microbes have behaved in a detrimental manner.
Not long ago a compound called NTA (nitrilotriacetic acid) was
suggested as a substitute for phosphates in detergents. The substi-
tution was suggested as a means to reduce one of the nutrients be-
lieved to be a major cause of eutrophication in surface waters. It
was feared, however, that the degradation products, resulting from
conventional aerobic waste treatment, might cause cancer. To that
point, the scientific community was convinced that the compound was
anaerobically stable. We became concerned because millions of septic
tanks in the country treat waste anaerobically and, as pointed out
earlier, we often find anaerobic conditions in shallow surface soils.
We found that NTA was indeed degraded in simulated anaerobic
ground-water conditions by bacteria actually taken from shallow
aquifer sands. In this case, however, it appears that the bacteria
are working for us in that the end products of degradation are harm-
less and that intermediate products are short lived.
Those of us interested in ground-water resources find ourselves
in a rather pathetic position. For years we have tried to get resource
planners to consider this abundant water supply. We have tried to get
everyone to appreciate the importance of preventing ground-water pol-
lution from the standpoint of the long residence times involved. The
Safe Drinking Water Act which was passed last December provided for
the first time legislation which covered ground water, and suddenly
everybody is asking questions for which we simply do not have answers.
Research concerning the underground environment is lagging behind that
of surface water and waste treatment by many years.
Basic to the understanding of the fate of any pollutant in this
underground world is the understanding of that world as a receptor of
pollution. It is a very complex world and a very variable world in
which simply measuring its components is difficult.
How can we be sure that samples taken to identify the biological
community are not contaminated by drilling? How can we be expected to
229
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measure the oxidation-reduction potential below the surface of the
earth without altering it during sampling? What means could be
made available to determine the amount and composition of gases at
great depths?
Obviously, those of you who have spent your lives drilling for
oil, gas, water, and other resources are best equipped to develop
drilling techniques which will allow us to answer these questions.
In the past you have had to develop unique techniques to answer your
own particular needs. I am suggesting that a problem is before you
again in that the protection of our tremendous ground-water reserves
is as important to our future needs as any problem you have faced
in the past.
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CHEMICAL APPLICATIONS IN OIL- AND GAS-WELL-
DRILLING AND COMPLETION OPERATIONS
A. Gene Collins*
Abstract
An investigation was made of the chemicals used and their ap-
plications in oil- and gas-well-drilling operations as they may
affect ground waters. The study indicated that some of the constit-
uents used in oil-base muds or drilling fluids, water-base muds,
and well-completion additives, if improperly handled or in the event
of an accident, could contaminate ground waters. Chemicals are used
in these drilling muds and well-completion additives to control bac-
teria, calcium, corrosion, density, dispersion, emulsion, foam, fil-
trate reduction, flocculation, heavy shale, lost circulation, lubri-
cation, pH, surface activity, and viscosity. Although contamination
of potable ground waters by drilling operations is possible, experi-
ence has shown this to be the exception rather than the rule.
INTRODUCTION
In 1833, Fauvelle (ref. 1) in France observed that drill bit
cuttings were brought to the surface by the flow of water during an
artesian well-drilling operation. M. T. Chapman in 1890 obtained a
patent on a rotary-well-drilling method concerned with circulation
and recirculation of water containing clay particles generated in
the well bore. These are some of the earliest recorded uses of
drilling fluids.
In addition to the removal of drill cuttings, it became apparent
that drilling fluids (muds) were useful in increasing wall support
of the hole, sealing permeable formations for exclusion of high-pres-
sure gas and water, and preventing gas blowouts and lost circulation.
Drillers recognized a relationship of the colloidal properties of the
*Project Leader, U.S. Energy Research and Development Adminis-
tration, Bartlesville Energy Research Center, Bartlesville, Oklahoma.
231
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different types of clays to water loss, lubrication and cooling of
the bit and drill pipe, and gelling tendencies of clay fluids. The
drillers began to prefer certain types of clays, and it was soon
recognized that drilling fluids containing clays had a disadvantage
because they tended to seal off oil- and gas-bearing formations,
necessitating the removal of the clay sheaths from producing forma-
tions.
Because clay in a water-base drilling fluid has the tendency
to seal thoroughly an oil- and gas-bearing formation, some drillers
use oil-base or oil-emu!si on drilling fluids, especially in well-
completion operations. Water-base fluids also have the detrimental
tendency of causing the reservoir rock to become water-wet, forming
a "water block" that adversely affects the flow of oil into a well.
The first major efforts to create oil-base drilling fluids occurred
in 1935 (ref. 1).
An opening or cylindrical hole from the ground surface to a
subsurface oil- or gas-bearing formation is an oil or gas well.
Such an opening usually is lined with a metal pipe cemented in
place, and production equipment is fastened to the cased hole to
regulate and control oil or gas withdrawal rates. Before drilling
a well, some knowledge of the geologic formations to be penetrated
is useful, as is knowledge of the approximate depth of the target
petroleum-bearing zone. This information is needed so that the
appropriate diameter, length, and type of tubular goods can be
selected in planning the well.
Most States have and enforce laws requiring the setting of
surface casing to protect the fresh-water subsurface sands from
invasion by brines and hydrocarbons from deeper horizons. There-
fore, a minimum of two strings of casing—the surface casing and
the oil-string casing—almost always will be required. Additional
strings of casing may be required if heaving shales are found while
drilling, if abnormal pressures are encountered, or if a zone of
lost circulation is found. Each additional string of casing requires
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more capital and increases the cost of the well.
If appropriate precautions are not taken in planning, drilling,
and completing an oil or gas well, disastrous consequences can occur.
For example, during drilling operations or when pulling the drill
pipe, a well may blow out if adequate mud pressure is not maintained.
Such a situation may develop if the mud line is accidentally broken
or if the well casing is not properly cemented to competent zones.
In spite of the numerous possible accidents and potential haz-
ards of drilling and completing wells that intersect brine and fresh
water aquifers, little ground water pollution has occurred. This
record is to the credit of the petroleum industry because of its con-
stant endeavors to maintain safe nonpolluting working procedures.
USES OF DRILLING FLUIDS
The most modern drilling method is the rotary system which re-
quires a circulation of drilling fluid for removal of drilled cut-
tings from the bottom of the hole to keep the drill bit and the
bottom of the hole clean (figure 1). The drilling fluids are pumped
from ground surface through a drill pipe and bit to the bottom of
the hole and returned to the surface through the annul us between
the hole and the drill pipe. The flow of formation gas, oil, and
brine into the drill hole is blocked by the drilling-fluid column
which produces a hydrostatic pressure that counterbalances or ex-
ceeds the formation pressures.
Drilling fluids or drilling muds are used in well drilling for
several reasons. Some of the major functions of drilling fluids and
of the constituents in them are to control bacteria, calcium, corro-
sion, density, dispersion, emulsion, foam, filtrate reduction, floc-
culation, heaving shale, lost circulation, lubrication, pH, surface
activity, and viscosity.
Bactericides are added to reduce and control the bacteria in a
drilling fluid. Common bactericides are paraformaldehyde, hydroxides
233
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CJ«
c.
Drilling fluid
holes
Cone
4f-Stondord line
^ pipe
formation
Oil hole
Rgure 1. Schematic of a drill bit illustrating the influent of drilling fluid and
effluent of drilling fluid plus drill cuttings.
of sodium or calcium, and sodium pentachlorophenate.
Calcium precipitators are used to remove excess calcium from
the drilling fluid. Calcium compounds are solubilized in the drill-
ing fluid when the drill bit is drilling into rocks containing an-
hydrite or gypsum. The excess calcium compounds destroy the effec-
tiveness of other chemicals in the drilling fluid if they are not
removed. Some of the compounds used to remove the excess calcium
are sodium hydroxide, sodium carbonate, sodium bicarbonate, and
barium carbonate.
Corrosion inhibitors are added to drilling fluids to prevent
corrosion of the mud-circulation system: drill pipe, string, and
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bit. Chemical agents used to control corrosion include water-soluble
amines such as high molecular weight imidazoline. Most of the amine
inhibitors are marketed under brand names. Copper carbonate and cal-
cium hydroxide are used in some applications as a corrosion inhibitor
as are oxygen or sulfide scavengers such as formaldehyde, sodium sul-
fite, and iron oxide. One high-temperature inhibitor is a combination
of sodium arsenite plus alky! phenolethylene oxide. Most emulsified
oil-base muds exhibit excellent corrosion-inhibition properties.
Density controllers are used to control the density or weight
of the drilling fluids. High-density fluids are used to control well
backup pressures resulting from subsurface formation pressures, facili-
tate the pulling of drill pipe, control formation caving, and resist
loss of circulation.
Higher density fluids are used to counteract formation pressures,
which can be very high in abnormally pressured or geopressured zones.
The hydrostatic gradient of fresh water is 0.433 psi/ft and of brine
containing 80,000 parts per million (ppm) of sodium chloride (Nad),
0.456 psi/ft, whereas a geopressured zone may be as high as 1.0 psi/
ft or equal to the entire geostatic weight of the overburden (ref. 4).
In such a situation, a mud weight of 19.3 Ib/gal would be necessary
to prevent a well from blowing out. In the Gulf Coast area, formation
pressure radients that exceed 0.465 psi/ft (9.0 Ib/gal mud density)
usually are considered abnormal pressures (ref. 4). Compounds used
to increase the density of drilling fluids include barium sulfate,
calcium chloride, calcium bromide, calcium carbonate, iron oxide,
and lead sulfide.
Dispersants and thinners are chemicals that can change the vis-
cosity and the amount of dissolved and/or suspended solids in the
drilling fluid. For example, dispersants can be used to change a
gel strength or increase or decrease the mud weight. Deflocculation
is a prime purpose of a thinner to minimize association of clay parti-
cles. Emulsification is the formation of a substantially permanent
heterogeneous mixture of two liquids. Emulsifiers used in formulating
235
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drilling fluids are surface-active agents such as soaps, sodium
sulfonates, or sodium alkyl sulfates.
Foaming agents are added to drilling fluids to cause foam
while drilling in aquifer formations. Such foams permit air or
gas drilling through water-bearing formations. The chemical agents
used are surface active or surfactants and include organic sodium
sulfonates, and alkyl benzene sulfonates both branched-chain and
linear-chain. Most of the foaming agents are sold only by brand
name.
Defoamers are used to control foaming action that sometimes
occurs with salt-water muds. Common defoamers are long-chain al-
cohols, silicones, and sulfonated oils.
Filtrate reduction in drilling means reducing the amount of
drilling fluid that passes into the rock formation being drilled.
Chemicals added to the drilling fluid to inhibit loss of fluid to
the formation include sodium carboxymethyl cellulose, bentonite clay,
barium carbonate, oil-base muds, various lignosulfonates, sulfonated
asphalt, and pregelatinized starch.
Flocculating or coagulating agents sometimes are used to form
a stronger drilling mud gel. Such an agent causes suspended col-
loidal particles to group together or "floe" and settle out of solu-
tion forming a gel precipitate. Chemical agents that are used include
clays such as bentonites, aluminum sulfate, calcium sulfate, and fer-
ric sulfate.
Shale-control additives are used to inhibit the swelling and
caving of shales caused by hydrous disintegration. Products used
to control heaving shales include calcium chloride, calcium sulfate,
calcium oxide, calcium lignosulfonate, sodium chloride, sodium sili-
cate, colloidal asphalt, sulfonated asphalt, polyanionic cellulose,
gilsonite, aluminum lignosulfonate, and chrome lignite.
Lost-circulation additives are used to plug a zone into which
the drilling fluid is being lost, to prevent a complete loss of the
drilling fluid into the formation being drilled, and hence a loss
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of drill fluid circulation from the bottom of the drill hole to the
top. Agents used to plug such a zone include inorganic chemical
grouts or cements containing mixtures of silicates, metallic oxides,
and limestones; organic chemical grouts containing mixtures of acrylic
monomers with catalysts; causticized lignites; fibers such as sugar
cane, straw, pig hair, cedar fiber, ground nut shells, expanded per-
lite (volcanic rock); shredded cellophane, ground rubber; mica; car-
bonates; shredded leather; oil soluble resins; and barite.
Lubricants are added to drilling fluids to reduce the friction
coefficient at the drill bit. Common lubricants are graphite, soaps,
crude oil emulsions, organic polymers, gilsonite, water-dispersable
asphalts, and oil-dispersable asphalts.
The pH, adjusted by the addition of an acid or a base, is ad-
justed because certain mud or fluid additives often are soluble at
a certain pH.
Surfactants or surface-active agents are used in drilling fluids
to reduce the interfacial tension between contacting surfaces such as
water and rock, or water and oil. Surfactants were discussed under
emulsifiers, foamers, defoamers, and flocculators. Therefore, the
type of surfactant added to the drilling fluid is dependent upon
what surfaces are involved and the kind of reaction desired.
Viscosifiers are constituents added to the drilling fluids to
build a high viscosity-dissolved solids interrelationship. Some of
the compounds employed as viscosifiers are attapulgite and bentonite
clays, quebracho, polymeric lignosulfonate (crude oil emulsifier),
long-chain-polymer xanthum gum, calcium magnesium silicate, causti-
cized lignite, sodium tetraphosphate, sodium acid pyrophosphate,
sodium hexametaphosphate, organic polysacchoride, and pellitized
crysotile asbestos.
Sulfonated drilling muds are prepared by: (1) sulfonating as-
phaltic crude oil with sulfuric acid, followed by neutralization with
sodium silicate and ion exchanging with hydrated lime; or (2) absorb-
ing concentrating sulfuric acid on a porous carrier, e.g., diatomace-
ous earth, and then sulfonating asphaltic crude oil with acid carrier,
followed by partial neutralization with sodium hydroxide and ion ex-
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changing with hydrated lime.
The usual asphaltic crude oils that are used yield a 5- to 7-
weight-percent carbon residue and have an API gravity in the range
of 26° to 31°. Some blends may contain an 18° API asphaltic crude
oil with a 12-weight-percent carbon residue blended with a paraffinic
42° API crude oil with a 0.5-weight-percent carbon residue. These
muds are usually mixed with oil at the drilling site and used in the
drilling operation. As the cuttings plus the used drilling mud are
recovered from the well, the drilling mud is usually separated from
the cuttings and reused.
The use of quebracho, starch, and carboxymethylcellulose in
formulating drilling muds has decreased in the last decade; whereas,
the use of chrome llgnosulfonates has increased. The use of lime-
treated mud systems has also decreased; whereas the use of low-solid
muds, invert emulsions, and chrome lignosulfonate systems has increased.
Chemical Treatment of Completed Hells
Wells are treated with acids to increase the permeability of the
reservoir rocks. This increases fluid flow and increases the recovery
Of oil and gas; it also improves fluid injection in secondary oil-
recovery and disposal operations. Hydrochloric, nitric, sulfuric,
hydrofluoric, formic, and acetic acids are used. Such treatments
produce soluble compounds including calcium chloride, sodium sulfate,
sodium fluoride, etc., and in addition, may leave partially spent
acids in solution.
The volume of acid used to acidize a well may vary from 500
to several thousand gallons depending upon the amount of acid-
soluble strata, the thickness of the horizon being treated, and
the calculated productivity of the well (ref. 4). Table 1 lists
the approximate amounts of hydrochloric, formic, and acetic acid
used in the United States in 1969 for oil- and gas-well treatment.
Corrosion Inhibitors
Table 2 lists the approximate amounts of corrosion inhibitors
used in well drilling operations in 1969 (ref. 4).
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Table ]. Volume of acids used for oil-
and gas-well treatment
Acid Gal/yr
Hydrochloric 8.7 x 107
Formic 2.0 x 105
Acetic 1.0 x 1Q5
NOTE: gal x 3.785 = liter.
Table 2 . Types and amounts of inhibitors used in
oil- and gas-well treatment
Inhibitor
Sodium arsenite
Imidazoline
Abi ethyl ami ne
Coal tar derivatives
Acetylenic alcohol-alkyl pyridine
Ib/yr
1.0 x 1
1.25 x l
7.0 x 1
2.5 x 1
3.0 x 1
06
06
05
05
05
NOTE: Ib/yr x 0.454 = kg/yr.
Table 3. Types and amounts of other additives used
in oil- and gas-well treatment
Additive
Lactic acid (44 percent)
Citric acid
Alkylaryl sulfonic acid
Zirconium oxychloride (20 percent)
Quaternary ammonium derivatives
Polyacryl amide
Polymers
Guar gum
Fluid loss agents
Emulsion preventers
Ib/yr
5.75 >
2.0 >
5.0 >
2.5 >
2.0 >
6.0 >
1.0 >
5.75 >
1.8 >
4.5 >
< 105
< 104
< 105
< 105
< 105
< 105
< 105
< 106
< 106
< 105
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Other Additives
Table 3 lists the approximate amounts used in 1969 of some of
the other additives used in drilling fluids.
WATER-BASE AND OIL-BASE SYSTEMS
Drilling fluids usually consist of water-base or oil-base sys-
tems. The water in the water-base systems, where water is the con-
tinuous phase, can be fresh water, brackish water, saturated salt
water, or gypsum-treated water. The pH of these waters will range
from about 7 to above 11 (ref. 2).
An oil-base system is a fluid in which oil is the continuous
phase and water is the dispersed phase. The system may contain 50
percent water by volume in the liquid phase in invert emulsion muds.
Oil used in these systems usually is a mixture of asphalt and diesel
fuel. Diesel fuel is used to thin and reduce viscosity, whereas as-
phalt and clays are used to thicken and increase viscosity.
Oil-base muds (not the invert emulsion type) contain up to 5
percent water, which is emulsified into the system with caustic soda,
or quick lime, and an organic acid. Therefore an oil-base mud is
differentiated from an invert emulsion mud primarily by the amount
of water; yet both types are water-in-oil emulsions (ref. 2).
ESTIMATED COST OF DRILLING FLUIDS
Drilling fluids are expensive; an average cost is about. $200
per well per day. Drilling fluids must be continually replenished
because of loss of fluid to porous rocks in the hole and to the
formation of the wall sheath. If circulation is "lost" in a very
permeable or cavernous formation, large amounts of new drilling
fluid are used. The volume of drilling fluid in use at any given
time during a drilling operation ranges from about 500 to more than
1,500 barrels. Assuming that there are 1,500 drilling rigs in use,
the annual drilling fluid cost is about $100 million.
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Considerable money is invested in drilling muds, especially
in the heavier muds; consequently, they are recovered for reuse.
Such muds are primarily used for emergencies, such as lost circu-
lation and high-pressure kicks from both gas and salt water. Many
of the used muds are treated with high concentrations of lignosul-
fonates to produce a stable mud with specific properties.
CONCENTRATIONS OF SOME CONSTITUENTS
IN SOME OILFIELD BRINES
Because all types of drilling fluids can be prepared with
natural oilfield brines, the constituents found in these brines
plus the concentrations of the constituents should be considered.
Tables 4, 5, and 6 show the concentrations of some constituents
found in oilfield waters in the United States. Table 4 contains
an analysis of oilfield waters from Tertiary age sedimentary rocks;
table 5, Jurassic age sedimentary rocks; and table 6, Pennsylvanian
age sedimentary rocks. The data shown in the tables are the highest
values found, the average values, and the number of samples analyzed
(ref. 4).
COMPOSITION OF CRUDE OILS
Crude oil sometimes is used in preparing oil-base drilling
fluids. The composition of crude oil varies from one geologic res-
ervoir to another. The solubilities of petroleum hydrocarbons in
water is small. Aromatics are less than 0.2 percent soluble in
water, whereas n-octane and heavier hydrocarbons are less soluble
than 1 ppm (ref. 5) at room temperature and pressure. The solubility
of n-octane is 11.8 ppm at 149°C, and the solubility of topped crude
oil is 20 to 40 ppm at 150°C (ref. 6).
Table 7 illustrates the approximate amounts of paraffin hydro-
carbons in some crude oils taken from Tertiary, Jurassic, and Penn-
sylvanian age sedimentary rocks. The compounds in crude oils that
boil above 527°F are removed by vacuum distillation (ref. 7).
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Table 4. Tertiary system, highest concentration in mg/1 of a constituent
found, average concentration, and number of samples analyzed
Constituent, mg/1
Lithium
Sodium
Potassium
Rubidium
Cesium
Calcium
Magnesium
Strontium
Barium
Boron
Copper
Chloride
Bromide
Iodide
Bicarbonate
Carbonate
Sulfate
Organic acid
as acetic
Ammoni urn
Highest
27
103,000
1,200
0.6
0.4
38,800
5,800
420
240
450
1
201,300
1,300
35
3,600
300
8,400
1,900
2,700
Average
4
39,000
220
0.24
0.20
2,530
530
130
60
36
0.63
64,600
85
28
560
75
320
140
230
No. of samples
169
379
176
11
9
376
368
142
140
170
3
380
323
322
364
8
139
53
64
POSSIBLE WAYS DRILLING FLUID MAY CONTAMINATE GROUND WATER
Chemicals used in well-drilling operations could contaminate
ground waters in the following manner:
(1) If the conductor casing and/or surface casings shown in
figure 2 are not properly cemented to competent subsurface zones
below the upper ground-water horizons.
(2) If there is an improperly plugged and abandoned well in
242
-------
Table 5. Jurassic system, highest concentration in mg/1 of a constituent
found, average concentration, and number of samples analyzed
Constituent, mg/1
Lithium
Sodium
Potassium
Rubidium
Cesium
Calcium
Magnesium
Strontium
Barium
Boron
Chloride
Bromide
Iodide
Bicarbonate
Sulfate
Organic acid
as acetic
Highest
400
120,000
900
0.10
0.10
56,300
5,200
2,080
50
50
210,000
6,000
40
2,640
1,480
12
Average
10
57,300
140
0.10
0.10
25,800
2,500
320
10
13
141,000
1,200
16
140
210
12
No. of samples
80
85
9
1
1
85
84
9
7
9
85
80
8
72
78
1
the area, drilling fluids may escape into a deep porous or cavernous
formation, come back up the improperly plugged well, and contaminate
a near-surface fresh-water aquifer, as shown in figure 3.
(3) If during drilling operations a high-pressure zone is
drilled, inadequate mud weight is used, and the well blows out through
the top of the hole, drilling fluids can be spilled on the ground with
possible contamination of fresh-water aquifers (see figure 4). The
blowout may even relocate the surface and/or conductor casings.
(4) If during drilling operations a deep very porous fresh-
water aquifer is penetrated, it is possible that considerable drill-
243
-------
Table 6. Pennsylvania!! system, highest concentration in mg/1 of a
constituent found, average concentration, and number of
samples analyzed
Constituent, mg/1
Lithium
Sodium
Potassium
Rubidium
Cesium
Calcium
Magnesium
Strontium
Barium
Boron
Minganese
^Chloride
Bromide
Iodide
Bicarbonate
Carbonate
Sulfate
Organic acid
as acetic
Ammonium
Highest
35
101,000
710
2.30
8.50
205,000
15,000
4,500
640
70
105
270,000
3,900
1,410
1,200
70
5,400
2,300
3,300
Average
7
43,000
170
0.55
0.15
9,100
1,900
600
30
15
60
87,600
490
210
130
40
430
430
300
No. of samples
45
951
57
25
19
950
947
70
41
54
2
950
57
52
897
2
756
44
51
tng fluid can escape into the porous zone before it can be sealed
(see figure 5).
(5) If a drilling-fluid storage tank or associated lines should
rupture and spill fluid on the ground, the fluids can seep into the
earth and contaminate ground waters (see figure 6).
(6) If during drilling operations a deep vugular and cavernous
fresh-water aquifer is penetrated, it is very likely that large amounts
244
-------
Table 7. Approximate amounts of paraffin hydrocarbons in some crude oils
taken from Tertiary, Jurassic, and Pennsylvanian Age rocks
Boiling
point,
OF
95-122
123-167
168-212
213-257
258-302
303-347
348-392
393-438
439-482
483-527
Hydrocarbon, Tertiary,
C numbers percent
C
C
C
C
C
C
C
C
C
C
7
8
9'
11
13
17
19
22
26
32
Cl
, C
, C
C
9
, c
, c
, c
, c
0
12
14' C15, C16
18
20' C21
23' C24' C25
28' C29' C30' C31
33' C34
-
-
6
9
7
6
5
6
5
6
-
-
.5
.0
.5
.6
.4
.0
.8
.3
Jurassic,
percent
5.
4.
5.
6.
7.
7.
6.
5.
6.
6.
5
8
6
7
9
5
6
9
0
3
Pennsylvanian,
percent
2
2
3
4
4
4
4
5
6
7
.1
.3
.6
.5
.8
.7
.3
.0
.0
.1
of drilling fluid will escape into the zone before it can be plugged
or sealed, as shown in figure 7.
(7) If during drilling operations a high-pressure zone is en-
countered, it is possible that the well may blow out and pollute an
upper fresh-water aquifer with some drilling fluid, as shown in
figure 8.
(8) If the chemicals used during well completion operations
escape into a fresh-water aquifer because of improper casing or
tubing, they may cause contamination.
Most States have and enforce laws which prevent the above types
of contamination from occurring.
245
-------
Conductor casing
Surface casing
Drill bit
water aquifer
Improperly sealed surface
casing and or conductor casing
Limestone
Limestone
Figure 2. Illustration of how improperly sealed surface casing ana/or
conductor casing may provide an entry for a
contaminant into a fresh water aquifer.
246
-------
Improperly plugged
well
River
.:,Y^!-::V.>.?
Wolfcampian
^^= Virgilian
Figure 3. Illustration of how an improperly plugged well may provide
an entry for a contaminant into a fresh water aquifer
and eventually into a surface river.
247
-------
Drill bit
Conductor cosing
Surface casing
Well blowout at top
because of low mud
weight and penetration
of high pressure zone
in we! I .
Figure 4. Illustration of a well blowout caused by
penetration of a geopressured zone while
drilling with inadequate mud weight.
Deep fresh
water aquifer .
Very porous sandstone
^_—~-r- —
^Influx of mud filtrate
because of very high
porosity and permeability
of deep fresh water aquifer
Figure 5. Illustration of drilling fluid infiltrating
into a very porous and permeable
fresh water aquifer.
248
-------
Conductor cosing
Surface cosing
Well blowout becojse
n mud Itne
Drill bit
Figure 6. Illusfratfon of a well blowout because of a
ruptured or broken mud line.
Conductor Cosing
Sjrfoce casing
into fresri water aqj fer
because cf »rccmp*'e~t sioles
ond vjgj ior zone5
Figure 7. Illustration of drilling fluid contamFnating a
deep fresh water aquifer because of incompetent
shales, cavernous area, or vugular zone.
249
-------
Conductor casing—fHr
Possible break
to surface
Possible pollution
of upper sand
Surface casing— 4S»
r>:«^ Oil sand
L imestone
Drill pipe
t'/c-^^••'X^'/.' Oil sand
ii ijii^tkffiii
liiiTynT
_'! li^WL
L imestone
I sand
Figure 8. HlustraHon of well blow out into subsurface zone with
ultimate contamination of a near surface fresh water aquifer.
250
-------
Water-Base Drilling F1uids
The type and extent of possible contamination of a ground water
is dependent upon the type and amount of drilling fluid that might
mix with the fresh water. A water-base drilling-fluid system often
is prepared with a natural brine, brackish water, or gypsum-treated
water; therefore, it is likely to contain high concentrations of
chloride. Any ground water mixing with this type of drilling fluid
will be contaminated by the original brine and by the added drilling
fluid chemicals. Assuming that the drilling fluid contains 100,000
rng/1 of chloride or some other water-soluble contaminant, then 1
barrel of the drilling fluid mixed with 400 barrels of potable ground
water containing 10 mg/1 of chloride will result in a mixture contain-
ing approximately 259 mg/1 of chloride, an increase of almost 250
mg/1. The above can be calculated by the following equation:
VDF ' CDF
where,
Si' Cp,r» C = Concentration of water-soluble contaminant in
mixture, drilling fluid, and potable ground
water, respectively, mg/1;
Vpjr> V , V., = Volume of drilling fluid, potable ground water
and mixture, respectively, bbl.
If the relative volumes of drilling fluid and contaminated water
are unknown, the relative volumes can be calculated from the water-
soluble contaminant analysis as:
CM - Cw
(RV) = 100 (2)
r - r
LDF Lw
(RV)w = 100 - (RV)Dp (3)
251
-------
where,
(RV)Dp, (RV) = relative volumes of drilling fluid and potable
ground water, respectively, percent.
The water-base systems are those in which water is the contin-
uous phase. Fresh water is used in some systems, and pH of the drill-
ing fluid will range from 7 to about 9.5. This type of system is
sometimes used to spud a well.
Brackish water is used in some systems, and the brackish water
often is sea water obtained from the open sea or bays. The pH of
the system a-gain ranges from 7 to 9.5.
Brine or nearly saturated salt water is used in some systems.
The brine can be a natural oilfield brine or it may be a fresh water
saturated with salt.
A gypsum-treated drilling fluid is fresh, brackish, or brine
water treated with calcium sulfate. A lime-treated drilling fluid
has a pH greater than 11; sodium hydroxide or calcium oxide are used.
Oil-Base Drilling Fluids
Mixing of ground water with an oil-base drilling fluid will
produce a different type of contamination because oil is the con-
tinuous phase and water is the dispersed phase. Oil and water do
not mix well, and most oils are almost insoluble in water at low
temperatures and pressures. At the present time, diesel oil is
most commonly used as the oil phase in oil-base drilling fluids.
Crude oils were used extensively in the past in preparing oil-
base drilling fluids. Some heavy crude oils possess a specific
gravity of about 1, contain about 5 weight-percent sulfur, and
have an overall minimum boiling point of about 270°C. Conversely,
some light crude oils contain virtually no elements other than car-
bon and hydrogen, have 0.8 or less specific gravity, and distill
below 270°C. The major nonhydrocarbons in crude oils are basic and
nonbasic nitrogen and sulfur compounds and acidic and nonacidic oxy-
gen compounds. Usually the nonhydrocarbons are more highly concen-
252
-------
trated in the heavier portions of the crude oils. In an overall
classification, most crude oils can be classified as naphthem'c,
paraffinic, or intermediate; the naphthem'c type usually is the
heaviest, the paraffinic the lightest.
POSSIBLE POLLUTION FROM NATURAL GAS
Blowouts of natural gas wells can contribute to pollution,
especially if the natural gas contains appreciable quantities of
hydrogen sulfide. Many gas wells contain enough hydrogen sulfide
to pollute fresh water they may contact. Such contact may develop
if a well is faulty and communication between the gas zone and an
upper fresh-water zone occurs. Brines associated with hydrogen
sulfide-bearing gas zones also contain appreciable quantities of
the sulfide.
RESIDUAL SALT CONCENTRATIONS BENEATH
OR NEAR ABANDONED UNSEALED PITS
Unsealed surface pits that are used to contain drilling fluids
used for the disposal of oilfield brines could contaminate fresh
surface waters, potable ground waters, and fertile land. Figure 9
illustrates a suction pit, settling pit, and reserve pit which often
are used in mixing and storing drilling fluids. Because of chemical
and physical phenomena and dispersion, the movement of soluble pol-
lutants from these pits is complex. For example, the soluble pollu-
tants move slowly in relation to the soil water-flow rate, and dis-
persion effects a displacement which causes the contaminated zone
to grow.
The Kansas State Department of Health studied the soils beneath
and near an oil unsealed brine disposal pond that had been abandoned
for 10 years (ref. 4). During its use, the pond received more than
29,000 metric tons of salts, and most of those soluble salts probably
escaped by soil leaching and downdrainage and penetrated below the
253
-------
/
Su
pit
/
z\
/
/
/
////
Drilling fluid
reserve pit
////XW//// //X///////////
////
ion
10'
/////
V
'////.
^////
Sett
6 to
Ditch
4
!
\
5
8
i
i
1
|
j
/V///
ing pi
///X/
t
8 feet deep
10'
Dump
Pumn
1
1
1
_
_
\
///
Jet
I -i.
1
1
to1
///,
flow
/
S/////S/
line
Ditch
Standpipe
Derrick
floor
"
'
2
Drilling fluid
return
flow line
o
i
n n 24 •
il-j
24 -30
Figure 9. Illustration of suction pit, settling, pit, and reserve pit-
used in mixing and storing drilling fluid.
underlying limestone formation. Eleven test holes were drilled into
the soil and shale beneath and adjacent to the pond, both above and
below the natural drainage slope. Chemical analysis of the test-hole
core samples indicated that more than 430 tons (about 1.4 percent of
the original) of soluble residual salt still remained to be leached
out of the soil and shale in the pond area. This amount of soluble
254
-------
or Teachable salt remaining in the area indicates that the return
of the subsurface water and soil to their prepollution level is a
very slow process and may take several decades. Network pollution
zones appear to form where formation fracture conjugates occur.
Leaching appears to be entirely dependent upon the flushing mechanism
provided by meteoric water.
The cation concentrations in the clay minerals were evaluated
by X-ray diffraction techniques to trace cation transportation rates.
Chloride analysis was selected as the most useful single means of
detecting the presence of oilfield brine pollution, but the associated
cation concentration should also be determined to formulate a more
complete picture. Cation absorption studies are apparently useful
in differentiating brine-polluted soil and shale, clay mineral studies
provide the information on the environmental characteristics of the
pollution media, and cation exchange information aids in explaining
the apparent differential transportation rates of ions in brine
seepage solutions (ref. 4).
REHABILITATION OF A DRILLING FLUID CONTAMINATED AQUIFER
Consider some of the methods that might be used to rehabilitate
a fresh ground-water aquifer that has been contaminated by drilling
fluid. A determination must be made to ascertain the type of drill-
ing fluid contaminant, how much of the aquifer is contaminated, and
the direction in which the aquifer water is moving and at what rate.
With this knowledge, a rehabilitation plan can be organized (ref. 8).
Some possible methods include: containment, accelerated dis-
charge, use, and deep-well disposal. The water in most subsurface
aquifers moves slowly. The actual rate is dependent upon many vari-
ables. However, assuming that the rate is about 200 feet per year
and further and that the movement of a particular aquifer is toward
a river, which is about 10 miles from the point of contamination, it
then can be calculated that it will require about 260 years for the
aquifer to flush the contaminants into the river.
255
-------
A costly method would be to contain the contaminant by con-
structing an impermeable underground wall around it. The exact
cost of this method is dependent upon the type of wall, depth of
aquifer, size of contaminated area, and yearly maintenance costs.
A second alternative is to drill a well into the contaminated
zone and pump out the aquifer until the contaminant is removed.
The contaminated water must then be disposed of in some acceptable
manner, or used.
If the contamination is not too severe, the water might be
used for irrigation with or without mixing with fresh water, or
the contaminated water might be pumped into a deep well for dis-
posal (refs. 4,8).
REFERENCES
1. J. E. Brantly, "History of Oil Well Drilling," Gulf Publishing
Company, Houston, 1971.
2. T. R. Wright, "World Oils 1975-76 Drilling Fluid File," World
Oil, Vo1- 180> No- ! (1975), pp. 35-69.
3. American Petroleum Institute, Glossary of Drilling-Fluid and
Associated Terms, API Bull., Dll, 18 pp., API, Dallas, 1965.
4. A. G. Collins, "Geochemistry of Oi 1 field Waters," Elsevier
Publishing Company, New York, 1975.
5. C. McAuliffe, "Determination of Dissolved Hydrocarbons in Sub-
surface Brines," Chemical Geology, Vol. 4, No. 1/2 (1969), pp.
225-234.
6. L. C. Price, "The Solubility of Hydrocarbons and Petroleum in
Water as Applied to the Primary Migration of Petroleum," Ph.D.
Dissertation, University of California, Riverside; Ann Arbor,
Michigan, Univ. Microfilms, 73-83, 1973.
7. C. M. McKinney and E. L. Garton, "Analyses of Crude Oils from
470 Important Oilfields in the United States," U.S. BuMines,
Rept. of Inv. 5376, 1957.
8. J. S. Fryberger, "Rehabilitation of a Brine-Polluted Aquifer,"
Environmental Protection Agency Report, EPA-R2-72-014, 61 pp.,
1972.
256
-------
DISCUSSION
DR. RICHARD S. SCALAN (University of Texas, Austin, Texas): I would take
exception with Mr. Coll in's statement that paraffins are probably the
most soluble components in crude oil. Indeed, I would think that the
lighter molecular components, aromatics, might be more soluble in
water than paraffins.
What is more, if one were going to use crude oil for an oil-base
mud rather than something like diesel oil, one would probably have
things such as nitrogen, oxygen, and sulfur compounds that would be
more soluble than the paraffins.
MR. COLLINS: That is right. Did I say that they were the most soluble?
Yes, the aromatics, such as the benzenes, are more soluble.
MR. T. J. ROBICHAUX (Petrolite Corporation, St. Louis, Missouri): Dr.
Giam, I would like to go back to the question that you proposed
after the first speaker, concerning the formation of dioxin from
pentachlorophenol.
While certainly that is a possibility under the conditions,
there are certain mitigating factors that have to be considered.
One is the concentrations that you are dealing with in using penta
as a bactericide in a drilling mud; you are dealing with concentra-
tions in the neighborhood of a hundred parts per million.
The other thing that you have to consider is the residence
time at a high temperature as the mud is circulated around; while it
may penetrate a high temperature zone, it does not stay there very
long.
And third, if by some natural forces you did cause or did form
a concentration of dioxin of concern, there are so many opportuni-
ties for that to be modified while in the mud itself—either absorb
to a surface, or i«n some way be impeded from returning to the environ-
ment where it could become a possible entrant in a problem.
MR. ROBERT B. ALLRED (Sun Oil Company, Richardson, Texas): Mr. Collins, I
won't question where you got your prices of drilling fluids. But if
257
-------
you could run one for $200 a day, I believe I can put you to work at
11:00 o'clock.
MR. COLLINS: I am going up, slightly. Costs depend on the size of the
rig and on other factors. The cost I quoted is only an average fig-
ure, and may not account for recent inflation.
CHAIRMAN 6IAM: Can I come along too?
MR. JAY B. SIMPSON (Baroid Division, N L Industries, Inc., Houston, Texas):
I would like to comment on the crude oil. A crude oil would be very
rarely used in preparation of an oil mud these days. On the use of
the produced saltwater—by far most of the water-based muds are made
from freshwater. Although many are made from produced water, per-
centagewise, the vast majority of the water-based muds would be mixed
with freshwater.
MR. COLLINS: Well, I took the statement from the literature, so I have no
firsthand knowledge.
MR. HARRY L. HARRISON (A. C. Drilling Specialties, Odessa, Texas): I
would like to ask Mr. Collins if there have been any studies in a
polluted system, in a polluted freshwater or fresh ground-water
system where the sweep is considered, the amount of the dilution
due to sweep away from the area, and the volumes that would have to
be considered.
MR. COLLINS: We have not made any studies of this type.
MR. HARRISON: I think we should look at these things carefully because it
is very easy to say you polluted that stream when you poured a barrel
of brine water into it or a freshwater sand. But as these materials
move out away from the source, they are considerably diluted and we
run into a cost thing here. I think it should be considered.
MR. COLLINS: Yes, they would be diluted.
MR. JAMES U. WINFREY (petroleum consultant, Houston, Texas): In the
interest of accuracy, Mr. Collins, I would suggest that in talking
about the number of rigs running, we would sure like to see 3,000
rigs running in the United States. But there are only about half
that many now. As you mentioned, with the changes in the depletion
258
-------
allowance, it will probably drop off. The average now is somewhere
in the order of a little over 1,500. Then in one of your slides
you really touched a nerve where you showed surface casing set
above a freshwater zone. That has been against regulations in the
States of Texas and Oklahoma, in all of the big oil-producing
States, for many, many years. And you have to get approval, of
course, for a casing setting depth to be sure that you are below a
freshwater zone.
So while you can have underground blowouts (and there have been
underground blowouts due to incompetent cement where it channelled
back up around the surface casing) you just do not set your surface
casing above a freshwater zone.
MR. COLLINS: I realize there are these laws. However, in some cases
deep, freshwater aquifers exist. The slide was just an example of
a possibility.
MR. PAUL D. FLEISCHAUER (The Aerospace Corporation, Los Angeles, Califor-
nia): I would like to ask about the question that has been in the
news. Lately there has been a lot of controversy about carcinogens
in some of the water supplies in Los Angeles and other cities. Do
you have any data on chlorination reactions that occur in the water
table, say, on the surfaces of particulates or any homogeneous
reactions?
MR. SHEW: You mean to form those chlorinated compounds?
MR. FLEISCHAUER: Right.
MR. SHEW: I am not sure what they are proposing. I believe they are
claiming that these arise from, or are a result of, chlorination of
the naturally occurring organics in ground water, for example, or
organics that get into freshwater supplies before it is chlorinated.
Now, I am just not sure if it will hold or not. I am not sure
that this has been shown absolutely to be the source of chlorinated
hydrocarbons or not. I am anxious to wait 6 months and find out if
this holds up.
259
-------
GENERAL CHAIRMAN FISHER: The chlorinated materials which are being picked
up in water supplies are, in fact, from what is properly called an
unknown source. It is not really thought that very many of these,
at least, are natural in origin. Some of them are clearly environmen-
tal contaminants in their own right, largely from pesticidal uses,
and possibly from some of the other types of disinfectants which
were discussed here yesterday. Although, as we also pointed out,
the well applications of these disinfectants are really very minor
compared to their many other applications.
However, many of the materials—and especially those which are
being found in larger quantities, like chloroform and so on—are
almost certainly artifacts from water purification procedures,
either in industrial wastewater treatment or in the actual water
purification plants themselves, where various organic compounds,
either anthropogenic or natural, are in the incoming water. When
you chlorinate the water, these materials do react with the chlorine
in various ways, and some of the reactions are very simple ones; any-
body who took elementary organic chemistry can explain how chloroform
can arise from a large number of compounds that you could find all
over the place.
And I think it will hold up pretty well; in fact, most of these
materials are arising from our water purification practices, in
combination with our rather gross pollution of the waters before
they get to water purification plants.
260
-------
MOBILITY OF WELL-DRILLING ADDITIVES
IN THE GROUND-WATER SYSTEM
Michael D. Campbell and George R. Gray, Ph.D.*
Abstract
Components of the drilling fluid may enter an aquifer through any of
the avenues available to surface water, such as the outcrop, stream runoff,
percolation, and abandoned wells. From the well bore, materials may enter
ground water as a consequence of lost circulation, seepage, filtration, or
blowout. The contaminating material may be gas, liquid, or solid, and in
the form of coarse to fine solids, colloidal suspensions, or solutions.
The subsequent behavior and characteristics of the entering substance are
determined not only by its initial properties but also, to a large extent,
by the properties of the reservoir rock and the interstitial water. Physical
separation of suspended solids depends on particle size, shape, concentration,
and density and on the pore geometry of the aquifer. The chemical compo-
sition and the microorganisms present in the ground water may cause preci-
pitation and decomposition reactions. Adsorption on surfaces and other
interfacial phenomena in the reservoir are particularly important and are
of a complexity seldom, if ever, met in the laboratory. Movement of drilling
fluid mater-Lais into the aquifer will be governed by the geohydrologic
conditions present. Flow conditions are controlled by the aquifer permea-
bility and the pressure gradient. Such flow may be modified by the introduced
substances and their effect on existing conditions in the aquifer.
INTRODUCTION
The purpose of this paper is to examine the factors involved in the
movement of drilling-fluid components in the ground-water reservoir. Com-
ponents of the drilling fluids will be considered generally and no attempt
*Michael D. Campbell is Director of Research, NWWA Research Facility, Dept
of Geology, Rice University, Houston, Texas 77001, and Managing Director,
united Resources Geological Consulting Company, Houston.
George R. Gray is a Drilling Fluids Consultant, Bellaire, Texas 77401
261
-------
will be made to deal with specific substances. Examples of the important
mechanisms involved in the movement of liquids, solids, and gases from the
borehole into the formation will be discussed.
Some definitions may aid in delineating the scope of this review. An
"aquifer" is a geologic "formation, group of formations, or part of a formation
that contains sufficient saturated permeable material to yield significant
quantities of water to wells and springs" (ref. 36). A "drilling fluid" is
a material used as an aid to tools in the excavation of earth. Accordingly,
the drilling fluid may be employed with such varied tools as augers for
foundation borings, and cable tool and rotary drills for ground water and
petroleum exploration and for mineral exploration and mine development. Com-
position of the drilling fluid may range from dry air or potable water to
diesel oil containing gellants, emulsifiers, and several types of suspended
solids. A "contaminant" is any introduced substance, or product of an intro-
duced substance, that modifies the properties of the initial ground water
to such an extent that its usefulness in the desired application is impaired.
This discussion is concerned with the movement of any substance that
enters the ground-water reservoir as a consequence of the drilling operation,
whether such a substance is a drilling-fluid additive, or fluids or earth
materials derived from the excavation.
The term "drilling fluid" embraces an extremely variable composition
of matter. Characterized according to the principal component, as "gas,"
"water," or "oil," usually two (somethimes all three) fluids are present,
along with suspended and dissolved materials. If the major component is
a liquid, the drilling fluid is called "mud" and is broadly classed as
"water mud" or "oil mud." Prior publications (refs. 2, 22, arid 23) and
other papers presented at this conference deal with the components of drilling
fluids in some detail and they need not be reviewed here.
CONTAMINATION FROM THE SURFACE
Contamination of ground water from the surface may originate in earthen
pits in which mud is placed, either for circulation or storage; from leach-
ing of cuttings; from spilled mud or ingredients; from containers for the
additives, and from mud and materials discarded on completion of drilling
262
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operations.
In drilling deep wells, practically without exception the mud is con-
tained in steel tanks. The cost of the mud, as well as possible reuse or
sale of excess mud, justifies adequate facilities for storage. Many small
rigs also use steel tanks for the mud being circulated, although surplus
mud is stored in earthen pits or discarded on the surface (figure 1). When
earthen pits are used in the active mud system, if the surface exposed in the
dug pit is not clay, the surface is sealed with bentonite or other clay be-
fore mud mixing is begun (figure 2).
Bulk handling of the principal mud constituents has greatly reduced
spillage and waste of materials. More attention should be given, however,
to the handling of water-soluble additives. Not infrequently the contents
of opened bags containing caustic soda, lignosulfonates, or the like, will
become caked and will be discarded, thus becoming a potential source of
ground-water contamination under certain geologic conditions. "Good house-
keeping," therefore, is a highly desirable practice.
The cuttings separated at the surface and the adhering drilling fluid
are regarded as waste products. A considerable quantity of earth is exca-
vated during the drilling operation. For example, in drilling a municipal
water well in Houston, Texas, to a depth of 2,500 ft., over 14,000 cubic feet
of earth weighing over 1-1/2 million pounds must be brought to the surface.
Usually cuttings are not regarded as a source of ground-water contamination,
with the exception of soluble salts, such as halite or gypsum. Disposal
of cuttings and mud in some locations is an expensive item in well drilling.
In the Los Angeles basin, for example, cuttings and excess mud must be
hauled to designated sumps for disposal. In The Netherlands, the drill
site is covered with a concrete apron surrounded by dikes. All waste water,
in addition to cuttings and mud, must be removed from the location.
Components of the drilling fluid may enter ground water through any
of the routes available to surface water, such as the outcrop of the aquifer,
streams, percolation, and abandoned wells. Shallow aquifers are often ex-
posed to contamination through construction borings; excavations for foun-
dations, sumps and mud pits, and by drilling relatively shallow holes for
seismic and mineral exploration.
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In the construction of earthen mud pits, attention is given to avoiding
the loss of whole mud. After mud has been prepared in an earthen pit, seep-
age of liquid and percolation into an aquifer is controlled by the filtration
characteristics of the mud. Chemicals spilled on the ground, however, do
not have this limitation on their mobility.
CONTAMINATION FROM THE BOREHOLE
The most obvious mechanism for the contamination of an aquifer by
drilling fluid occurs when circulation is lost. Lost circulation has been
the subject of numerous studies (refs. 9, 29, and 38). Almost every material
that could be poured, pumped, or pushed into the borehole has been proposed
as a remedy (ref. 30). Nevertheless, loss of circulation continues to be
one of the most serious and widespread problems in drilling.
For loss of circulation to occur there must be openings in the for-
mation large enough to accept the whole mud, and sufficient pressure must
be exerted to force the mud into the openings. "Lost circulation" is thus
distinguished from "loss of water," which takes place when a permeable zone
is encountered while drilling with water, and from "water loss," or filtration
of liquid through a filter cake of mud solids formed on a permeable formation.
Formations that can take whole mud can be classed broadly as: (a) cavernous,
such as limestone containing solution channels; (b) loosely consolidated,
such as coarse sands and gravels, and (c) fractured, jointed, and fissured
formations (figure 3).
To stop loss of mud, the openings must be plugged with a material con-
taining particles of such sizes, or having such consistency, that greater
resistance is offered to entry of the mud than is presented by flow up the
annulus of the borehole. Sometimes this condition cannot be realized.
Drilling may be resumed and the cuttings carried into the zone of loss by
the drilling fluid.
However, under some conditions, contaminants may enter avenues of
communication with other wells, streams, etc. These condtions are where
open channels would allow "lost circulation" materials and drilling fluids
direct communication with distant points. The possibility exists that ground-
water contamination could occur under some conditions. One case of migration
266
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of what is in fact a component of a drill ing-fluid additive was reported
by Sweet and Fetrow (ref. 43). A case of ground-water pollution was reported
involving wood-waste disposal (i.e., lignin-tannin, which is a common drilling
fluid additive in oil-well drilling operations).
While drilling with water, seepage may occur into porous,, permeable
formations exposed in the borehole. Finely-divided cuttings carried by the
water enter the openings and, as individual pores become bridged by the larger
particles, successively smaller particles are filtered out. Clay or other
material of colloidal dimensions converts seepage into filtration. The
passage of liquid into the formation then becomes dependent on the amount
and physical state of the colloidal material in the drilling fluid and not
on the permeability of the formation (ref. 10). In porous media, the thick-
ness and cha 'acter of the filter cake precondition the extent of liquid
invasion into the formation during the drilling operation. When circulation
is stopped, cake thickness continues to increase but at a decreasing rate
(figure 4). Studies of the filtration of oil-field muds have shown the per-
3 -5
meability of the filter cakes to be in the range of 10 to 10 millidarcys
(refs. 5, 11, and 46). Estimations have been made of the rate of invasion of
filtrate into sands in the course of drilling (refs. 21 and 47). A radius of
invasion of nearly 2 feet was calculated for a period of 138 hours between
penetration of a sand and cementing of casing. More than 90 percent of the
total filtrate flowed from the mud while it was circulating during about 75
percent of the elapsed time (ref. 21.)
The most spectacular method of introducing contaminants into ground
water is by means of a blowout. This uncontrolled entry of fluids into the
borehole may force gas into shallow aquifers and cause water wells to begin
flowing or even to blow out. Keech (ref. 32) cites a dramatic case history
of widespread ground-water contamination by a subsurface natural-gas well
blowout in the vicinity of a number of water wells. In another example,
the effects of a blowout in the Bammel field north of Houston, Texas, are
still evident after 30 years. Water wells drilled several miles from the
site of the blowout often require prolonged completion operations because
gas coming out of solution in the water interferes with the functioning
of the pumps.
268
-------
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hole and adjacent formation (note mud-
filtrate invasion characteristics).
269
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Contaminants can enter the ground-water reservoir as wells are drilled,
during their operational life, or following their abandonment. Possibly of
greatest potential consequence is the nearly unavoidable introduction of
biological agents into the aquifer via drilling fluids. Subsequently, the
growth of certain types of bacteria that cause corrosion and incrustation
may be an important factor in contamination of aquifers. The routes by
which contaminated water can enter the ground-water reservoir through faulty
oil or water well construction have been briefly explored by Collins (ref. M
and by Campbell and Lehr (ref. 13) and need not be treated here.
IMMOBILIZATION OF SUSPENDED SOLIDS IN THE AQUIFER
As has been shown, contaminating substances from drilling operations
may enter ground water from the surface or from the well bore. The material
may be gas, liquid, or solid. It may be in the form of coarse to fine solid
colloidal suspensions, or solutions. It may be stable or unstable; reactive
or unreactive. The subsequent behavior of the entering substance is deter-
mined not only by its properties but also, to a large extent, by the proper-
ties of the reservoir rock and the interstitial water.
Except under very unusual conditions, particles that will be retained
on 200-mesh sieve—the API designation for sand (ref. l)--can be expected to
be removed near the point of entry into the aquifer. Particles having an
effective diameter less than 74 microns (200-mesh) also will be subject to
gravitational effects that will decrease in importance as the particles
become smaller. Sedimentation is not a significant factor in the separation
of particles smaller than one micron (figure 5).
The importance of filtration in industrial processes has led to numerc
studies of the mechanism. Herzig, Leclerc, and LeGaff (ref. 26) cite 74
references in their examination of the flow of suspensions through porous
media. The authors point out that several mechanisums are involved, namely:
(a) the contacting of particles with retention sites, (b) the fixing of
particles on sites, and (c) the escape of previously retained particles.
Factors involved in the system are: (a) the flow rate, viscosity, and densi
of the carrier fluid; (b) the concentration, size, and shape of the suspends
particles, and (c) the geometry of the porous medium.
270
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271
-------
Retention sites can be classed as: (a) surface of a grain making up
the bed, (b) crevice between the surface of two grains, (c) constriction
and, (d) cavern, or sheltered area formed by several grains (see figure 6a).
Forces that hold the particle immobilized include: (a) axial pressure of
the liquid, as at a constriction; (b) friction forces, as on a particle
wedged in a crevice; (c) surface forces: Van der Waals forces of attraction,
and electrostatic or electrokinetic forces which are either attractive or
repulsive dependent on the system, and (d) chemical forces, which may
involve chemical bonding between the particle and the surface. The process
of capture may involve: (a) sedimentation; (b) inertia, i.e.., the particles
cannot follow the changing path of the liquid; (c) hydrodynamlc effects
caused by nonuniform shear field and nonsphericity of particles; (d) direct
collision with convergent pore walls; and (e) diffusion by Brownian motion
into areas not flushed by the suspension (see figure 6b).
"The flow of suspension through porous media is a very complex phe-
nomenon owing to the diversity of the mechanisms involved" (ref. 26).
MOVEMENT WITHIN THE AQUIFER
Drilling-fluid filtrate invasion in highly permeable sands often appears
from electrical logs to be less near the base of the sand than near the top.
Doll (ref. 18) concludes that filtrates rise in the sand after passing the
filter cake barrier at the hole wall. This, of course, assumes that the fil-
trate density is less than the denisty of the ground water and suggests that
if the density of the ground water is higher than the density of introduced
material, the invasion would be strictly gravity controlled. The filtrate
would then invade the lower part of the aquifer more rapidly than at the top.
In a study on deep-well waste disposal and waste surveillance, Kazmann
(ref. 31) has demonstrated that the density difference between the ground
water and the introduced carrier fluid clearly dictates the character of
the invasion front with time.
Once fluids and solids pass the filter cake and hole wall into the
formation, invasion characteristics of the carrier fluid are affected by
many physical, chemical, and biological factors. Numerous macro- and micro-
formational factors affect its path, its rate of flow, and its chemical com-
position. Information on the course of contaminants in the ground-water
system is now voluminous and hence will not be reviewed in detail at this
272
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time (ref. 12). However, some of the features pertaining to the potential
behavior of drilling fluids within the ground-water system will be explored.
Although open-channel, ground-water flow, e.g., in joints, interconnecting
solution channels, fault traces, etc., is not uncommon in the subsurface,
Dorous media flow is emphasized here because of its wide applicability to
the major aquifer type--sands, sandstone, etc. The physical aspects of
ground-water flow are of fundamental importance to a discussion of mobility
»f contaminants.
Bond (ref. 6) discusses flow patterns of variable-density ground water
nd the effects of troughs formed by permeability barriers within aquifers
nd the effects of structural troughs, saddles, anticlines, and synclines.
hilds, et al. (ref. 14) explore the concept of a "waste plume" and suggest
.hat the plume pattern may be complex and may not follow regional ground-
ater flow, as indicated by other workers (ref. 40). See figure 7.
Ground-water flow through porous media is characterized by laminar
low at low Reynolds numbers (Re), where gradient is held constant. Viscous
orces predominate and the Darcy Law is valid. As Re increases, a transi-
ion zone is encountered at the lower end; the laminar regime with viscous
orces predominating passes to another laminar regime characterized by in-
rtial forces. At the upper end of the transition zone, a gradual passage
o turbulent flow is observed. Darcy's Law is not valid in the transition
nd turbulent zones (ref. 4). Average ground-water flow rates vary widely
spending on gradient, permeability, and other geologically-controlled fac-
Drs.
It is clear that the laminar flow is of predominance in the porous
sdia under consideration here and that it simplifies the effects of the flow
igime on the chemical and biological parameters within the aquifer.
Flow paths, when encountering changes in permeability (or changes in
-ound-water density), will be refracted according to the tangent rule,
lereas light is refracted according to the sine rule (ref. 16). See figure
. This, of course, will affect the chemical and biological parameters to be
iscussed later. Suffice it here to state, however, that an abrupt change
i flow direction may affect one or more characteristics of the carrier
!uid, including any introduced contaminant.
275
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Figure 8. Refraction of streamlines (Davis and DeWiest - 1966)
Zones
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Used by permission. Figure 5, p. 584,
Underground Waste Management and
Artificial Recharge, Vol. 1, 1973, spon-
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Survey, and International Association
of Hydrologlcal Sciences.
Front
(Degradation)
Figure 9. Proposed geochemical model of waste after injection,
into subsurface. (Leenheer and Malcolm - 1973).
277
-------
The concept of dispersion of miscible fluids in porous media has re-
ceived considerable attention during the past several years, especially with
regard to ion exchange in soils, artificial recharge, liquid-waste disposal
operations, seawater intrusion into coastal aquifers and seepage from canals
and streams into and through aquifers (refs. 7, 8, 27, and 39).
Marino (ref. 37) explores the mathematical framework of simultaneous
dispersion and adsorption of a solute within a homogeneous and isotropic
porous media in steady, unidirectional flow fields. He concludes that in
such conditions the dispersion system is considered to be adsorbing the solute
at a rate proportional to its concentration. Mass transfer due to adsorp-
tion appears to play an important role in mass transport within natural flow
systems.
In general, the mobility of any contaminant introduced into the ground-
water system is largely dependent on the capacity of the matrix material
within the porous media to adsorb the dissolved substances. However, Sigmor
(ref. 42) suggests that movement into the aquifer is subject to limitations
caused by degradation of the hydraulic conductivity in the porous medium.
As previously mentioned, a reduction in hydraulic conductivity (or permea-
bility) is caused by the retention in the porous media of suspended clay
minerals, among other fine minerals, by means of (a) interstitial straining,
(b) gravitational settling, and/or (c) adhesion and adsorption.
It is apparent that sensitive flow thresholds exist that may play some
role in the chemical reactions and biological activity in an aquifer invaded
by foreign materials and carrier fluids and gases. In natural, undisturbed
ground-water systems, formation clogging by bacterial growth products occurs
when the introduced fluid contains dissolved organic materials and bacterial
growth conditions are favorable. Edwards and Monke (ref. 19) studied flow
of clay suspensions (similar to some drilling fluids) through a silica porous
medium and suggest that bacteria may provide a natural electrical link be-
tween the net negatively charged silica and bentonite clay particles.
REACTIONS WITHIN THE AQUIFER
The above discussion of flow through porous media has not. considered
the interaction between the suspended particles and substances present in
278
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solution. The chemical characteristics of ground water are strongly affected
iy the solids, liquids, and gases with which it has come in contact before
md during the ground-water phase of the Hydrologic Cycle (ref. 3). Simi-
arly, the composition of the mud filtrate depends upon the changes that take
lace as the substances added at the surface react with one another and with
he cuttings derived from the formations drilled. When mud filtrate mixes
ith ground water, reactions may occur to form precipitates which then become
ubject to the filtration mechanisms listed previously. Factors of Eh and
•), as well as ionic strength, are significant in determining the extent of
Drmation plugging and attendant mineralogical alterations (refs. 28 and 44).
Quartz is the most abundant mineral in sandstone aquifers, the most
)mmon type of aquifer. Chemical additives in the mud filtrate may react
ith the porous media; for example, sodium hydroxide reacts rapidly with
ie silica in the quartz, especially at elevated temperatures (ref. 24).
Microorganisms, such as bacteria, or enzymes produced by microorganisms,
iy be present in the ground water or be introduced by the drilling operation,
; previously mentioned. Biological activity frequently influences chemical
lactions indirectly, and vice versa, by facilitating reactions that lower
• raise the pH. Redox processes also may be mediated by bacteria.
The composition, size, and activity of a bacterial population depends
many factors, including (a) temperature, (b) pH, (c) salt content,
) concentration of nutrients available, (e) types of nutrients available,
d (f) oxygen concentration (ref. 20). Because ground water normally
ntains little dissolved oxygen, and is generally under reducing conditions,
aerobic species are expected to predominate. Bacterial travel in confined
uifers is reportedly negligible and survival time is short. Under most
iditions, the restricted travel seems to be the result of the filtering
tion of the porous medium rather than of "die-off" of organisms. Certain
cteria are generally considered to be responsible for the formation of
drogen sulfide under certain conditions.
Bacteria are commonly isolated from most oil-field brines. Ground
ter not associated with deposits of organic matter, however, does not
Dport extensive microbial growth. Hence bacteria carriers are presumed
be clays with associated organic materials.
There are sulphate-reducing bacteria, denitrifying bacteria, methane-
279
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producing bacteria, plus a host of other bacteria with uncertain affinities
(ref. 17). All may play roles in altering chemical equilibrium of the
fluid, as well as formation cement and matrix material.
Of particular importance here is that the variety of organic compounds
that can be utilized by microorganisms is almost limitless. Nearly all
naturally occurring organic compounds are subject to microbial assimilation,
although some, such as humic materials, are attacked very slowly.
In a study on liquid waste-aquifer interactions, Leenheer and Malcolm
(ref. 35) explored several of the possible geochemical and biochemical
effects of introducing an organic acid into the subsurface environment.
After injection, the organic acids were first neutralized by the carbonate
minerals in the aquifer. They found evidence for dissolution of the aluminc
silicate clay minerals by the complexing organic acids. After dilution,
conditions become favorable for microbiologic degradation of the organic
constituents. Methane is a proposed product with sulfate and iron reductioi
occurring as byproduct reactions. Figure 9 shows their proposed model
of the geobiochemical cell.
Of particular importance in considering the mobility of foreign fluids
in an aquifer is that most aquifers exhibit a natural, reducing subsurface
geochemical environment (ref. 41). Most aquifers contain extremely low
levels of dissolved oxygen. By opening the aquifer via drilling, the re-
duced condition is replaced by a progressively more oxidizing environment.
The initial response to this change is the oxidation of pyrite, or other
unoxidized minerals in equilibrium in a reduced environment, which releases
ferrous, sulfide, and hydrogen ions into solution. With time, ferric hy-
droxide precipitates, and the ferrous ion concentration decreases. Several
inorganic and microbiological agents have been observed to accelerate pyril
oxidation (ref. 45).
Within many aquifer systems, clays and shales serve as semi permeable
membranes, retarding by varying degrees the passage of the dissolved ele-
mental species with respect to water (refs. 25 and 34). The relative reta
dation by naturally occurring membranes of cations and anions generally
present in introduced fluids" has been investigated by Kharaka (ref. 33).
The conclusion was reached that the retention of these ions depends on the
constitution of the membrane and the specific ions involved. The retar-
280
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Jation sequences obtained were generally as follows: Li
-------
6. D. C. Bond, "Reduction of Flow Patterns in Variable-Density Aquifers
from Pressure and Water Level Observations," in Underground Waste
Management and Artificial Recharge, Vol. 1 (1973), published jointly
by the AAPG, USGS, and IAHS, pp. 357-378.
7. J. D. Bredehoeft and G. F. Pinder, "Mass Transport in Flowing Groundwater
Water Resources Research. Vol. 9, No. 1 (1973), p. 194-210.
8. J. D. Bredehoeft and G. F. Pinder, "Application of Transport Equations
to Ground Water Systems," in Underground Waste Management and Artificial
Recharge, Vol. 1 (1973), published jointly by the AAPG, USGS, and IAHS,
pp. 191-201.
9. 0. M. Bugbee, "Lost Circulation - A Major Problem in Exploration and
Development," API Drill, and Prod. Pract., 1953, pp. 14-27.
10. H. T. Byck, "The Effect of Formation Permeability on the Plastering
Behavior of Mud Fluids," API Drill, and Prod. Pract., 1940, pp. 40-42.
11. H. T. Byck, "Effect of Temperature on Plastering Properties and Viscosity
of Rotary Drilling Muds," Petrol. Trans. AIME, Vol. 136 (1940),
pp. 167-172.
12. M. D. Campbell, Ground-Water Pollution, (in preparation).
13. M. D. Campbell and J. H. Lehr, Water Well Technology; Subtitled: Field
Principles of Exploration Drilling and Development of Ground Water and
Other Selected Minerals. McGraw-Hill, New York, 1974, pp. 16-23.
14. K. E. Childs et al., "Sampling of Variable, Waste-Migration Patterns
in Ground Water," Ground Water, Vol. 12, No. 6 (Nov.-Dec. 1974),
pp. 369-377.
15. A. G. Collins, "Oil and Gas Wells - Potential Polluters of the Environ-
ment?" J. Water Pollution Control Federation, Vol. 43, No. 12 (December
1971), pp. 2383-2393.
16. S. N. Davis and R. J. M. DeWiest, Hydrogeology, John Wiley and Sons,
Inc., New York, 1966, p. 197.
17. A. Ditomasso and G. H. Elkan, "Role of Bacteria in Decomposition of
Injected Liquid Waste at Wilmington, North Carolina," in Underground
Waste Management and Artificial Recharge, Vol. 1 (1973), published
jointly by AAPG, USGS, and IAHS, p. 585.
18. H. G. Doll, "Filtrate Invasion in Highly Permeable Sands," J. Petrol.
Eng.. Vol. 27, No. 1 (January 1955), pp. B53-B56.
19. D. M. Edwards and E. J. Monke, "Electrokinetic Studies of Porous Media
Systems," Am. Soc. Agr. Engineers Trans., Vol. 11, No. 3 (1968), pp. 412
415.
282
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20. G. G. Ehrlich, "Role of Biota in Underground Waste Injection and Storage,"
in Underground Haste Management and Environmental Implications, AAPG
Memoir 16, pp. 298-307.
21. C. K. Ferguson and J. A. Klotz, "Filtration From Mud During Drilling,"
Petrol. Trans. AIME, Vol. 201 (1954), pp. 29-42.
22. G. R. Gray, "Chemicals in Oil-Well Drilling Fluids," paper presented at
159th National Meeting, Am. Chem. Soc., abridged as "Where the Industry's
Mud Money Goes," Oil and Gas J., April 1970, pp. 157-159.
23. G. R. Gray, "New Muds Designed to Improve Drilling Rate, Hole Stability,"
World Oil, Vol. 176, No. 6 (May 1973), pp. 84-86.
?4. G. R. Gray and W. C. Kellogg, "The Wilcox Trend - A Cross Section of
Typical Mud Problems," World Oil. August 1955, pp. 102-117.
?5. B. B. Hanshaw, "Natural-Membrane Phenomena and Subsurface Waste Em-
placement," Underground Waste Management and Environmental Implications
AAPG Memoir 16 (1972), pp. 308-317.
!6. J. P. Herzig, D. M. Leclerc, and P. LeGaff, "Flow of Suspensions
Through Porous Media - Application to Deep Filtration," in Flow Through
Porous Media, American Chemical Society, Washington, D. C., 1970, pp. 130-
157.
7. J. A. Hoopes and D. R. F. Harleman, "Waste Water Recharge and Dispersion
in Porous Media," Report 77, R. M. Parsons Lab, for Water Resources and
Hydrodynamics, M.I.T., Cambridge, 1965, p. 166.
8. W. F. Hower, et al., "Compatibility of Injection Fluids with Reservoir
Components," in Underground Waste Management and Artificial Recharge. Vol.
(1973), published jointly by AAPG, USGS, and IAHS, pp. 287-293.
9. G. C. Howard and P. P. Scott, Jr., "An Analysis and the Control of
Lost Circulation," Petrol. Trans. AIME, Vol. 192 (1951), pp. 171-182.
D. E. E. Hulbotter and G. R. Gray, "Drilling Fluids," Encyclopedia of
Chemical Technology. 2nd Ed., Vol. 7 (1965), pp. 287-307.
I. R. Kazmann, "Waste Surveillance in Subsurface Disposal Projects,"
GrounO§t§r, Vol. 12, No. 6 (Nov.-Dec. 1974), pp. 418-426.
?. D. K. Keech, "Ground Water Pollution," Principles and Applications
of Ground Water Hydraulic Conf., Kellogg Center, Michigan State Uni-
versity, December 1970, p. 20.
!. Y. K. Kharaka, "Retention of Dissolved Constitutents of Waste by Geologic
Membranes," in Underground Waste Management and Artificial Recharge, Vol.
T (1973), published jointly by AAPG, USGS, and IAHS, pp. 420-435.
283
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34. Y. K. Kharaka and F. A. F. Berry, "The Influence of Geological Membranes
on the Geochemistry of Subsurface Waters from Miocene Sediments at
Kettleman North Dome in California," Hater Resources Research, Vol. 10,
No. 2 (April 1974), pp. 313-327.
35. J. A. Leemheer and R. L. Malcolm, "Case History of Subsurface Waste
Injection of an Industrial Organic Waste," in Underground Waste Management
and Artificial Recharge. Vol. 1 (1973), published jointly by AAPG, USGS, an
IAHS, pp. 565-584.
36. S. W. Lohman et al., "Definitions of Selected Ground Water Terms—
Revisions and Conceptual Refinements," U.S.G.S. Water-Supply Paper
1988. 1972,
37. M. A. Marino, "Distribution of Contaminants in Porous Media Flow,"
Water Resource Research, Vol. 10, No. 5 (October 1974), pp. 1013-1018.
38. J. U. Messenger, "How to Combat Lost Circulation," Oil and Gas J., Vol. 66.
No's 20, 21 and 22 (May 1968), pp. 71-76, 90-97, and 94-98.
39. A. Ogata, "Theory of Dispersion in a Granular Medium," U.S.G.S. Prof.
Paper 411-1, 1970, p. 11-134.
40. R. Palmquist and L. V. A. Sendlein, "The Configuration of Contamination
Enclaves from Refuse Disposal Sites on Floodplains," Ground Water,
Vol. 13, No. 2 (March-April 1975), pp. 167-181.
41. S. E. Ragone et al., "Short-term Effect of Injection of Tertiary
Treated Sewage on Iron Concentration of Water in Magothy Aquifer, Bay
Park, New York," in Waste Management and Artificial Recharge, Vol. I
(1973), published jointly by AAPG, USGS, and IAHS, pp. 273-290.
42. D. C. Signor, "Laboratory Facility for Studies Related to Artificial
Recharge," in Waste Management and Artificial Recharge, Vol. 2 (1973),
published jointly by AAPG, USGS, and IAHS, pp. 799-822.
43. H. R. Sweet and R. H. Fetrow, "Ground-Water Pollution by Wood Waste
Disposal," Ground Water, Vol. 13, No. 2 (March-April 1975) pp. 227-231.
44. H. S. Swolfs, "Chemical Effects of Pore Fluids on Rock Properties,"
in Underground Waste Management and Environmental Implications, AAPG
Memoir 16, 1973, pp. 224-234.
45. F. Walsh and R. Mitchell, "A pH-Dependent Succession of Iron Bacteria,"
Environmental Science and Technology. Vol. 6, No. 9 (1972), pp. 809-812.
46. M. Williams and G. E. Cannon, "Evaluation of Filtration Properties
of Drilling Mud," API Drill, and Prod. Pract., 1938, pp. 20-27.
47. M. Williams, "Radial Filtration of Drilling Muds," Petrol ,. Trans.
AIME, Vol. 136 (1940), pp. 57-69.
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DISCUSSION
MR. DONALD W. SOLANAS (U.S. Geological Survey, Metairie, Louisiana): I
have a comment rather than a question.
In addition to your summation, which I think places it in its proper
perspective as to the ground-water contamination, I think it should be
remembered by those here who are not familiar with or knowledgeable of the
techniques of drilling oil wells, that the ground water and the shallow
formations are protected by casings and cemented strings as the well is
drilled to deeper depths and as the mud and mud additives are used. This
protection also is a plus effect for noncontamination of these valuable
ground-water aquifers.
MR. CAMPBELL: I would only add one thing. During the drilling process, lost
circulation is an instantaneous thing; it cannot be cased off all that
quickly.
Secondly, I think the problem of blowout is far more widespread
than we all think. It is just not as dramatic as the previously cited
Michigan case (ref. 32) and Bammel field case, and some of the other
cases. I think we may have a rather quiet blowout that we may not be
aware of--or a "mini blowout," if you will—that may present problems
that we are not even aware of with respect to the long-term transmission
of drilling fluids or production-related workover fluids that may or
may not be toxic.
1R. GEORGE H. HOLLIDAY (Shell Oil Company, Houston, Texas): I would like
clarification as to what a "mini blowout" is.
1R. CAMPBELL: You are going to take me to task on that. All right!
IR. HOLLIDAY: Well, I am just concerned, because your summation was good.
I thought the gentleman from the USGS made a good point. And I thought
that we were on a pretty good wave length and all of a sudden we have
developed a new gremlin that has come from the ground, and I would like to
hear something more about the gremlin.
R. CAMPBELL: Okay. Let us talk about the gremlin for a second.
Obviously, I am thinking about the gremlin. Can you imagine a
slow pressure release? And can you imagine a nontraumatic blowout where
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you have just a bleeding, if you will? That is what I was referring to
when I mentioned a mini blowout. So let us replace that term--I admit
blowout means something more than what I meant—and call it a bleeding
of more highly pressurized systems. Post-drilling "lost circulation"
is probably a better term.
Now, does that sound like a gremlin?
MR. HOLLIDAY: Yes, as a matter of fact, it does. The conditions which you
mentioned I am sure can be conjured. And I think through your thinking
process there a minute ago you were able to do this. You recognize that
when casing is set and the cement placed in position and let set, we
pressure test the casing, drill out below the cement, and again, pressure
test. We have done virtually everything that is conceivable and, I think
acceptable as good practice to see that there is not this bleeding
operation that you are speaking of.
MR. CAMPBELL: I would say this: I will support you in the fact that general 1
industrywide, you do go out of your way, as far as I know, to make sure
that the cement is in place and it is holding.
My worry is that with time and with production of that particular
oil well, that there may be earth shifting, for instance gravity fault-
ing--! am thinking of the Gulf Plain—which may stress that seal. You
do not monitor these wells, unless it becomes a dramatic case of failure
and then you have to go back in to rehabilitate that well. My concern
here is that, with time and without a monitoring system, there is a
significant chance of "bleeding" of "workover" fluids that are similar
in character to some drilling fluids. I am not suggesting it is a fact-
I need numbers to convince myself it is a problem--and I feel it is some
thing that should not necessarily be made a point of as we are doing
here; but let us at least consider it as an area for consideration.
If you don't look for areas of potential trouble, you—or the oil
industry—will continue to be criticized by outsiders for sweeping
potential problems under the rug.
Now, how are we going to monitor it? I do not know. But I do
think it could be a problem and deserves serious consideration by your
industry.
MR. FORD A. BANKSTON (Union Oil of California, Houston, Texas): I am primar
an operating man and have been in the business since '41. Of the two
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areas you refer to, let us take drilling first. We now get more exotic,
but we used to have a man who watched the mud pits. And when that mud pit
starts going down just a little bit or goes up a little bit, we do some-
thing drastic.
We have, of course, as the gentleman from the USGS knows, in the
more exotic drilling operations, mud tank level indicators that tell us
immediately on charts when that mud level goes up or down, and it is not
a slow bleed thing.
MR. CAMPBELL: No. You have misconstrued what I said. I am talking about
after the well is drilled and in production 5 years later.
MR. BANKSTON: Prior to talking about the production phase, I wanted it
understood that your statement about a slow bleed from one zone to
another is not likely to happen during drilling operations.
W. CAMPBELL: I am not talking about bleeding during the drilling operation.
I am talking about afterwards, i.e., during production.
W. BANKSTON: I want to get that clear.
AR. CAMPBELL: I agree with you. You may be right concerning the drilling
phase.
1R. BANKSTON: Okay. I am primarily a production man, and you know we keep
up with the production from our wells very carefully. If oil production
drops off, we check on it, and usually work these wells over. During
the workover we would determine if there is channeling in the cement
outside the casing or see if we have a hole in the casing. But mind
you, most of the fresh-water sands I have worked with have two strings
of pipe set through them. That gives quite a lot of protection to the
freshwater sands.
What I am really saying is that we have checks on these things;
it is not something where a little gremlin can do his dirty work and
we do not know that something is happening.
R. CAMPBELL: I understand your .position, but in my opinion, we do not have
sufficient data at this time to either discount the problem or call
it a gremlin as Mr. Holliday put it. I am sure, however, that your
industry will be capable of responding to potentially significant
gremlin hunts, if the potential has been defined by either your
company's inhouse environmental protection department or by other
environmentally cognizant groups. Hopefully, in the near future, both
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industrial and environmental groups will use the same measuring
techniques to assess environmental impact. I suggest that we must
work together. The future is approaching rapidly! Lost circulation
of drilling or "workover" fluids, either during the drilling stage or
during the production stage, in addition to surface housekeeping has
been suggested by us to represent a significant negative impact of well-
drilling additives on the ground-water system. We, therefore, urge
mutual cooperation in assessing the magnitude of this problem. Thank
you.
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MOVEMENT OF CHEMICAL CONTAMINANTS
IN GROUND WATER
Dean 0. Gregg and Keith G. Kennedy*
Abstract
Chemical contaminants -in ground water principally move by ground-
water flow (convection transport) and by dispersion. In a homogeneous
granular aquifer system, the ground-water flow velocities may be rea-
sonably approximated by use of a modification of the Darcy equation.
More commonly, however, ground water flows through a locally heterogen-
eous aquifer of variable permeability with variable gradients and re-
charge flux. The dispersion (including molecular diffusion) and convec-
tion further compound the uncertainties of accurately predicting rates
of movement of contaminants in ground water.
The concentration of contaminants in a ground-water system is com-
monly diluted with distance and time from the source of the contaminants.
This dilution, depending on the contaminants, may be due to convection,
dispersion, additional recharge, ion exchange, sorption, chemical preci-
pitation, biologial destruction or uptake, and radioactive decay. Some
active cations, such as calcium, cesium, sodium, and arsenic, may be
removed from solution through ion exchange on clays, silts, and organic
material or fixed through sorption. These mechanisms are not significant
for a readily dissociated anion, such as chloride or nitrate. Some iso-
topes of certain chemical species, such as strontium 90, cesium 137, and
tritium, exhibit radioactive decay with time, thus reducing their origi-
nal concentrations.
Examples of movement of chemical contaminants in the ground-water
regime are cited. Generally, there is no easy way to perform an investi-
gation of ground-water contamination. As there are so many variables,
an extensive data net is usually required.
*Dean 0. Gregg is Senior Hydrologist, and Keith G. Kennedy is
Staff Hydrologist; both are with Dames & Moore, 1550 Northwest Highway
Park Ridge, Illinois 60068.
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INTRODUCTION
The purpose of this paper is to summarize the processes of move-
ment and dilution of chemical contaminants after they have entered the
ground-water system from a "point source" and discuss selected recent
case histories as examples of these processes.
A common and dramatic example of a point-source ground-water con-
tamination is a complete or partial loss of drilling fluids during ex-
ploration or well drilling. Generally, for a partial or complete loss
of drilling fluids to occur, two conditions must exist. First, a zone
of relatively high permeability must be present. This zone, which typi-
cally may be a solution cavity, a highly fractured system, or a highly
porous granular material, allows rapid movement of drilling fluid away
from the well bore. Second, the formation head in this zone must be
significantly lower than the head produced by the column of drilling
fluid from that zone to land surface. The resulting head differential
produces the drive which forces the drilling fluid into the permeable
zone and away from the well bore. The well bore then becomes a point
source of aquifer contamination.
After introduction of a drilling fluid or other contamination into
the ground-water system, the direction of movement will most likely be
radially from the point of injection. However, the extent to which this
flow pattern is developed is dependent primarily on the physical proper-
ties of the ground-water system. With time and distance, the contamina-
tion becomes part of and subject to the dynamics of the existing ground-
water regime. The main processes which affect the movement and dilution
of chemical contaminants in a ground-water system are discussed below.
MOVEMENT OF CHEMICAL CONTAMINANTS
The two main processes which result in movement of chemical contami-
nants in ground-water are:
(1) the movement of ground-water itself (convection transport);
and
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(2) dispersion (including molecular diffusion).
There are other factors in the movement of chemical contaminants
in the ground-water regime, but they are generally of less importance
and rarely of significance except under special conditions.
Ground-water Movement
Ground-water movement is caused by differences in energy. These
differences in energy are mainly due to either differences in elevation
or to differences in head or pressure. Basically, water moves from a
position of higher elevation or head to a position of lower elevation
or head.
The Darcy equation, and modifications thereof, gives the relation-
ship between the physical properties of the system and the rate and
quantity of water movement. That is, the quantity of water, Q, moving
past a particular place, in a unit of time, is equal to the hydraulic con
ductivity, K, times the area through which the flow occurs, A, time the
difference in head, Ah, divided by the length, £, over which the head
drop occurs, or:
.
The hydraulic conductivity of the porous medium, however, depends
both upon the nature of the fluid and upon the nature of the media
through which the fluid passes. In considering the nature of the fluid,
the minor variations in the physical properties of the ground water are
commonly ignored. This is because there may be only moderate or low
concentrations of dissolved solids and because the temperature of ground
water in a particular aquifer is reasonably constant. Thus, the impor-
tance of differences in the density and the viscosity of the ground water
is negligible. For this reason, a term called intrinsic permeability,
k, which depends only on the medium, is commonly used. This term is often
shortened to "permeability." In some contamination studies, however, the
density and viscosity of the contaminated ground water is significantly
291
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different from that of natural ground water. In these instances, the
pertinent parameters may be determined and included in the evaluation
of the problem.
The rate at which ground water moves through a porous medium can
be calculated using a modification of the Darcy equation (the Dupuit-
Forchheimer assumption) as follow:
Ah
a
V = K
n
where n = effective porosity of the medium,
v = ground-water velocity.
The rationale for dividing the right side of the equation by n,
the effective porosity, is that flow is occurring through interconnected
pore spaces. Thus the actual velocity through the tortuous pathways in
the pores of the medium may be considerably greater than the apparent
flow velocity through the water-bearing zone.
In a granular porous medium, such as a sand or gravel, the direc-
tion and rate of ground-water movement may be predicted with some degree
of certainty. Commonly, however, flow takes place in heterogeneous sys-
tems such as fractured or solution-cavity-riddled rocks or in rocks of
highly variable permeability. The determination of flow velocities
through these aquifers is more difficult and prediction less; certain
than for the granular system.
Convective transport, as used here, results from the mechanical mix-
ing of the contaminant with uncontaminated ground water and the resultant
movement with the ground water. The degree to which the mixing occurs
and the overall rate of convective transport is a function of the ground-
water pathways in the porous medium.
Dispersion
Dispersion results from convection and diffusion (the random movement
of molecules caused by thermal and kinetic energy). The dispersion
292
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coefficient is a function of the velocity of ground-water movement, of
the effective porosity of the aquifer and of the molecular diffusion of
the fluid. The dispersion phenomena may account for the presence of
contaminants in locations different than that of the ground-water flow
direction.
DILUTION OF CHEMICAL CONTAMINANTS
Physical, biologic, and geochemical processes are responsible for
dilution of contaminated ground water depending on the particular hydro-
geologic environment and the nature of the contaminant(s). The term
"dilution" is used broadly to imply a lowering of concentration of any
particular chemical constituent with time and distance from the point
source and includes the mechanisms or removal and conversion of the con-
stituents.
Physical Processes
The physical processes which result in dilution of contaminated
ground water are:
(1) convective transport; and
(2) dispersion (including molecular diffusion).
These two processes, as were discussed above in conjunction with recharge
of contaminated ground water to the affected zone, represent the main
effective physical dilution phenomena. The recharge is generally most
effective in situations where contamination of a water-table aquifer has
occurred and the downward movement of uncontaminated water results in a
volumetric dilution, in dispersion, and in a potential from convective
transport.
Biological Processes
Biologic processes which result in dilution of ground-water contam-
ination are:
(1) By green plant uptake of contaminants from the shallow
ground water; and
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(2) by bacterial action.
The green plants take up, and therefore remove, contaminants from the
soil or shallow ground water. The importance of green plant-related
biological processes is generally less significant compared to the bac-
terial processes in causing dilution. Bacteria have been shown to
cause dilution by decomposing injected organic wastes (refs. 1,2) and
in other studies have been shown to ingest and remove a variety of other
potential contaminants.
Geochemical Processes
The main geochemical processes which may result in dilution of
ground-water contamination are:
(1) ion exchange;
(2) sorption (fixation);
(3) chemical precipitation; and
(4) radioactive decay.
Ion exchange is defined as "the exchange of an ion held by electri-
cal charge near the surface of an exchange mineral with an ion present
in solution in which the exchange mineral is immersed" (ref. 3). Ion
exchange is a dynamic process dependent on the nature of the source of
ionic charge sites, the chemical composition of ground-water solution,
the proportion of monovalent versus multivalent cations, and the pH.
The precise course of an exchange reaction can vary significantly as
these characteristics are altered.
Most ion exchange reactions involve cations, although examples of
anion exchange are cited in the literature and further research is being
carried on in this field. (Anion exchange capacity may be important
where kaolinite and hydroxides of iron and aluminum are present). Many
natural minerals have exchange capacity although clay minerals, particu-
larly the montmorillonite group, are the most effective. The organic
matter in soil materials can also provide significant exchange capacity.
Therefore, in instances where ground water is moving through media con-
taining clay minerals or decomposed organic matter (humus), ion exchange
mechanisms may be very effective in altering the chemical nature of the
294
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ground water. Perhaps one of the most common ion exchange examples is
the exchange of Ca++ and Mg++ in water to mineral sites for Na and K
released to the ground water. The exchange of Ca or Mg for H is an
important phenomenon where acidic conditions prevail.
Sorption (fixation) causes removal of ions from solution by fixa-
tion within the crystal lattice of a mineral. The capacity for this
type of reaction is dependent on the nature of the minerals present and
is a result of direct chemical bonding of unsatisfied charges within
the mineral structure. An example is the fixation (sorption) of potas-
sium within the lattice of illitic clays which have lost K ions through
previous weathering. Completion of the crystal lattice often results
in stabilization of the physical structure of a mineral such that this
sorption process may be viewed in part as a physical as well as a chem-
ical phenomena.
Chemical precipitates cause dilution by combining elements as the
result of the mixing of ground waters which have differing chemistry,
temperature, and in rare instances, pressure. Precipitation related to
contamination studies has been intensively studied most recently in
areas of mine surface-water drainage. In instances where the pH and temp-
erature of two mixing solutions differ, precipitation of certian consti-
tuents may also result in removal of contaminants from the ground water.
In the zone of aeration, oxidation of certain dissolved substances such
as iron may cause precipitation. Detailed studies are needed in areas
where oxidation of contaminated ground water may result in the formation
of potentially hazardous precipitates.
Radioactive decay causes dilution by the material disintegration
of iostopes. Some of this disintegration may constitute an environmen-
tal hazard. The potential effects of the accidental introduction of
radioactive materials to the ground-water system should be anticipated
and evaluated prior to the construction of any facility handling these
materials. Simulation by computer models may be used to evaluate the
potential hazard of such an accidental introduction of radioactive
materials using the physical parameters of the media and the chemical
295
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processes of contaminant movement and dilution as referred to above
(including radioactive decay). Most attention is focused upon isotopes
tritium (H-3), strontium (Sr-90), and cesium (Cs-137). The methods of
making an appraisal of the potential hazard of radioactive contamina-
tion are becoming increasingly more sophisticated as the necessity of
assuring the safety of the environment is realized.
CASE HISTORIES
Several examples are cited in the following paragraphs to illus-
trate the variability of movement and dilution of chemical contaminants
in a ground-water system.
Chloride Contamination, Brunswick and Glynn County, Georgia
Contamination of the principal artesian limestone aquifer by brack-
ish water has occurred in places in and near Brunswick, Georgia. The
U.S. Geological Survey conducted comprehensive investigations to deter-
mine the geohydrologic controls of this contamination, and concluded
(ref. 4) that man's withdrawal of freshwater from the upper and lower
water-bearing zones of the principal artesian aquifer has created a head
imbalance with brackish ground water. This head imbalance or potential
has created conditions favorable for the deep brackish water to migrate
to the shallower freshwater zones of lower hydraulic head. Joints, frac-
tures, faults, or solution openings, and, in several instances, uncased
wells, are the probable vertical conduits for the migration of this
brackish water across confining zones to the freshwater zones.
Figures 1 and 2 (ref. 5, plate 6) show the distribution of chloride
concentrations in two different aquifer zones from three known areas of
contamination in Brunswick, Georgia. The point source of contamination
evident in the southeast corner of these maps is probably related to
well no. 1. This well was drilled through the lower confining unit
separating the lowest of two water-bearing zones (fresh) from the under-
lying brackish-water zone (ref. 6). This unused well forms a vertical
296
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EYNOLDS STREET
i POLLUTED AR
PULP AND I
PAPER CO T
I -
WELL FIELD
31 10
81 30
I i i i
EX PLANATION
200 4-
, of equol chloride concentration
t\ varies, in milligrams per liter
Well and identification number
31*07'30"
IMILE
I
FROM:
' U. S. Geological Survey Study,
Gregg, Dean 0., 1971, Protective pumping to reduce
Line Of Section Aquifer pollution, Glynn Co., Georgia: Ground Water,
i, V.9, No.5.
Figure 1. Area! distribution of chloride concentrations of water in
the upper water-bearing zone, Brunswick, Georgia, June 1969.
297
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81*30'
31* 10'
31* or'so'
REYNOLDS
JPOLLUTED
BRUNSWICK
PULP
PAPER CO
WELL FIELD
81*30'
I 1 -I
i i
I MILE
EXPLANATION
FROM:
• 200
Line of equal chloride concentration
Interval varies, in milligrams per liter
i U. S. Geological Survey Study,
A Gregg, Dean 0., 1971, Protective pumping to
Line Of section Aquifer pollution, Glym Co., Georgia: Grourv
V.9, No.5.
Well ond identification number
Figure 2. Area! distribution of chloride concentrations of water in
the lower water-bearing zone, Brunswick, Georgia, June 1969.
298
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conduit allowing the higher-head brackish water to move up the well
bore and into the upper and lower water-bearing zones. A similar sit-
uation exists at both the Bay Street and the Reynolds Street contam-
inated areas. Here the vertical conduit is not identified, but it is
likely a natural joint, fracture, fault, or solution opening.
Industrial pumping controls the configuration of the potentio-
metric surface and controls the direction of movement of ground water
in Brunswick-Glynn County area. The lines of equal chloride concentra-
tion are oriented along flow paths from the point source of contamina-
tion toward the well field at the Brunswick Pulp and Paper Company (figs.
1 and 2). The ground-water movement is about 350 feet a year (ref. 5).
The width of the body of chloride contamination may have been
accentuated due to the inhomogenity of the solution-openings in the
limestone, to lateral pumping effects, to dispersion, and to convection
transport. Marian B. Counts, Hydrologist with the U.S. Geological
Survey, reports (oral communication, May 14, 1975) that the traverse
dispersion coefficient is about 30 percent of the lateral dispersion
coefficient.
The chloride contamination problem in the Brunswick-Glynn County
area illustrates the process of induced leaking, and of the movement
and distribution of contaminates within the ground-water system. The
identification of this problem has been very time-consunrng and expen-
sive but the techniques used and the concepts developed during this
study have been proved to be applicable to similar problems elsewhere.
Chloride and Arsenic Contamination, Wisconsin
Dames & Moore recently performed an extensive investigation of
chloride and arsenic contamination of ground and surface water at a
site in Wisconsin. The contamination occurred through long-term leach-
ing of stockpiles of waste salt into the ground-water system, and hence
into a nearby river. The site is underlain by about 40 feet of predomi-
nately silty sands, cohesive' clayey silts, and gravels, all of which
contain some organic material. Underlying these fluvial deposits is a
dolomite bedrock which constitutes an aquifer in the area.
299
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A plot plan of the site, showing the stockpiles of the salt waste,
the data points used in this study, and the section lines are shown in
figure 3. Cross sections for the site (figs. 4 and 5) are annotated
with the permeability values and with the chloride and arsenic concen-
trations associated with the control points. Not all of the data con-
trol points are shown on these sections, as some water quality informa-
tion is interpreted from off-section data. Figure 6 shows the horizon-
tal distribution of chloride values in the 20- to 30-foot zone.
As evidenced by figures 4 and 5, several silts and clayey silts were
present at the site. However, these units are discontinuous and do not
protect the underlying bedrock from chloride and arsenic contamination.
The head of the.ground water in the dolomite bedrock is higher than the
head of the ground water in the surficial fluvial material. This effec-
tively prevents contamination of the dolomite bedrock.
Brines containing extremely high concentrations of chloride, arsenic,
sulfate, sodium, and other constitutents are collecting beneath the main
salt-waste storage pile. With total dissolved solid levels up to 158,600
mg/1, the specific gravity is more than 1.1 mg/ml. Thus the brines, being
heavy, sink in the shallow aquifer. Because the aquifer permeability
and the hyradulic gradients are low, the brines are not being appreciably
flushed from the aquifer.
The arsenic ion, because of its attraction to the silts, clays, and
organic soil particles, moves very slowly through the ground-water sys-
tem. This was established by performing sorption and leaching tests in
the laboratory and by analysis of field data. Conversely, the chloride
ions dissociate and disperse readily. These two differing phenomena
result in an apparent decrease in arsenic ions with respect to chloride
ions with distance from the source areas. Sodium also decreases with
respect to the chloride ions with distance. In actuality, the arsenic
ion is probably in the form of an arsenate, an anion, thus the arsenic
must also be in a complex with some other cation to be so readily at-
tracted to the clays, silts, and organic material.
The discharge of contaminated ground water to the river was found
to be about 3,000 gallons per day. This low rate of discharge may be
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attributed to the configuration and gradient of the water table and to
the low permeability of the surficial material.
The results of this investigation showed that the contamination
is localized and is not a substantial environmental hazard to the area.
Cyanide and Other Buried Toxic Wastes—Illinois
A similar study involving toxic wastes was conducted in Illinois.
Our client purchased farm acreage for a right-of-way. Shortly after
purchase, three cattle owned by a tenant farmer died in an intermittent
creek bed supposedly after drinking water from puddles. The cattle and
the puddles were down gradient from about 1,500 partially buried drums
and barrels, some-of which contained toxic chemical wastes. This chemi-
cal waste, which includes cyanides, chromium, cadmium, nickel, copper,
lead, zinc, and phenols, had been disposed of in side-hill gullies in
a limestone terrain prior to the purchase of the land by the client.
Dames & Moore was retained to identify the nature and location of the
source; to determine the extent of contamination of soil, and ground
and surface water; and, most importantly, to evaluate the threat of
contamination to the ground-water users in the area.
The three cows which had died and had been buried were exhumed and
samples of blood, liver, and lung tissue analyzed for cyanide and sel-
ected heavy metals. A veterinarian toxicologist evaluated the tissues
and the laboratory analyses and indicated that, in his opinion, death
was induced by cyanide.
In the course of the investigation, soil samples at 2-foot inter-
vals to a maximum depth of 6 feet from more than 50 sites were collected
and analyzed for cyanide. These analyses showed generally that the cy-
anide concentration decreases with depth and is commonly "held" in the
silts, clays, and organic material, and is not "held" as tightly in the
granular material. Significant concentrations of cyanide were found
in soil samples from the mouth of the creek, more than a mile from the
disposal area.
The concentrations of contaminants in the ground water contained
in limestone have been found to be erratic. It varies depending in part
304
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upon precipitation, which controls the leaching and deposition of cy-
anide and selected heavy metals from the source areas to the soils and
to the ground-water regime. Shortly after the spring thaw in the soil
zone and the percolation of spring rains to the water table, a substan-
tial increase in cyanide and heavy metals was detected in the ground
water. A few weeks later, the concentrations of chemicals had decreased
to lower levels. Many domestic wells in the area have been condemned
by the State and are not being used for human consumption. The resi-
dents are hauling drinking water.
The chemical waste disposal areas in the side-hill gullies, fortun-
ately, are generally ground-water discharge areas, depending on the
time of year and the water levels. Precipitation following an extended
drought can locally and temporarily alter the ground-water flow patterns
and the side-hill areas may recharge the system for a period of time.
The intermittent flows of surface water, when present, usually
have relatively high concentrations of cyanide and heavy metals. The
concentration of chemicals in the surface-water runoff typically de-
creases with distance from the source areas. This is due to dilution
from uncontaminated ground-water inflow, oxidation and destruction of
cyanide, and precipitation of certain constituents.
RADIOCHEMICAL CONTAMINATION CALCULATIONS
Another investigation conducted by Dames & Moore was concerned
with the postulated accidental release of approximately 950 gallons of
radioactive waste to a ground-water system. The shallow ground-water
system eventually discharges to a nearby lake. Hydrodynamic dispersion,
fluid concentration, cation exchange, and radionuclide decay were con-
sidered in the evaluation of postulated radioactive contamination of
the lake.
Figure 6 shows the hydrologic setting of the site. The hypothe-
tical release point for the 950 gallons of radioactive effluent lies
partially buried on the nose of a hill 600 feet from and about 15 feet
above the lake. As expected, the natural ground-water gradient is
305
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306
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toward the lake at about 0.02 foot per foot. The lithology, porosity,
and permeability of the various units at the site are indicated on the
cross section (fig. 6).
An equation describing the dispersion and attenuation of a con-
taminating liquid introduced instantaneously as a finite cuboid volume
into the ground-water system was derived by integration of the Baetsle
and Souffriau equation (ref. 7). The result, which is similar in
form to the Lenda and Zuber analytic model (ref. 8), accounts for the
total quality of radionuclides introduced with the effluent slug,
radioactive decay, average pore-water velocity, cation exchange, and
dispersion of contaminants in the ground water.
Table 1 summarizes the conservatively developed input parameters
used in the analytic model. Only Cs-137 and Sr-90 isotopes were con-
sidered in this problem because the other possible constituents have
much shorter half-lives relative to the long ground-water travel times.
Table 1. Summary of input parameters
Input Parameter Property CS'137 Sr'90
Cation exchange capacity, (meq/gm) 0.061 0.029
Equilibrium exchange constant with Ca 29.0 0.81
Concentration of calcium in inter-
stitial fluids, CCa (meq/ml) 0.0465
Flux rate, (cm/yr) 29.148
p
Dispersion coefficient, (cm/yr) 322
Length of travel path (cm) 18,288
Porosity of unit 0.20
3
Bulk density, (g/cm ) 2.00
Cuboid size per side, (cm) 262.8
Half-life, (yr) 33 29
307
-------
The travel times for the maximum concentration front to enter the
lake were calculated, using the finite effluent slug model described
above, as 48,000 years and 800 years for Cs-137 and Sr-90, respectively.
It was concluded that radionuclides entering the lake as a result of
the postulated accident would not pose an environmental hazard to the
lake.
SUMMARY
The movement and dilution of chemical contaminants in a ground-
water system are mainly controlled by the physical processes of con-
vection transport and dispersion; by the geochemical processes of ion
exchange, sorption, precipitation, and, in some cases, radionuclide
decay; and biological processes. The discussion of several case his-
tories illustrates the effects of the variability of the ground-water
system and the properties of the fluid on the movement and dilution of
chemical contaminants. The most common feature of these cited investi-
gations was the use of appreciable amounts of data. Only with suffi-
cient amounts of the appropriate types of data can an investigation of
contamination on ground water be accurately made. Generally, there are
few, if any, easy ways to determine the vertical and lateral extent,
the rate and direction of movement, and the dilution of ground-water
contamination in many ground-water systems.
REFERENCES
A. Ditommaso, and G. H. Alkan, "Role of Bacteria in Decomposition
of Injected Liquid Waste at Wilmington, N.C.," Paper presented at .
the 2nd International Symposium on Underground Waste Management
Aritificial Recharge, New Orleans, Louisiana, September 26-30,
1973, preprint, vol. 1 pp. 585-599.
J. A. Leenheer and R. L. Malcolm, "Case History of Subsurface
Waste Injection of an Industrial Organic Waste," Paper presented
at the 2nd International Symposium on Underground Waste Management
and Artificial Recharge, New Orleans, Louisiana, September 26-30,
1973, preprint, vol. 1, pp. 565-584.
308
-------
3. B. P. Robinson, "Ion Exchange, Minerals, and Disposal of Radio-
active Wastes - A Survey of Literature," U.S. Geol. Survey Water-
Supply Paper 1616, 132 p., 1962.
4. D. 0. Gregg, "Protective Pumping to Reduce Aquifer Pollution,
Glynn County, Georgia," Ground Water, Vol. 9, No. 5.
5. D. 0. Gregg and E. A. Zimmerman, "Geologic and Hydrologic Controls
of Chloride Contamination in Aquifers at Brunswick, Glynn County,
Georgia," U.S. Geol. Survey Water-Supply Paper 2029-D, 84 p., 1974.
6. R. L. Wait, and D. 0. Gregg, "Hydrology and Chloride Contamination
of the Principal Artesian Aquifer in Glynn County, Georgia,"
Georgia Water Resources Survey Hydrol. Report 1, 93 p., 1973.
7. L. H. Baetsle and J. Souffriau, "Installation of Chemical Barriers
in Aquifers and Their Significance in Accidental Contamination, in
Disposal of Ratioactive Washes into the Ground," Paper presented
at the Symposium, International Atomic Energy Agency, Vienna,
Austria, May 2 - June 2, 1967.
8. A. Lenda and A. Zuber, "Tracer Dispersion in Ground Water Experi-
ments jji Isotope Hydrology 1970," Paper presented at the Symposium
International Atomic Energy Agency, Vienna, Austria, preprint,
pp. 619-641, 1970.
309
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TOXICITY AND ENVIRONMENTAL PROPERTIES OF
CHEMICALS USED IN WELL-DRILLING
OPERATIONS
Vladimir Zitko*
Abstract
Acute toxicity to fish and other environmental effects of drilling
mud components are discussed. The components include solids, particularly
barite, polymers, and low molecular weight organic compounds. Acute
toxicities in terms of 96hLCO (juvenile Atlantic salmon, Salmo salar)
were estimated for a number of organic components of drilling mud on the
basis of correlations with octanol-water partition coefficients and
Bammett a constants. The components include 4- and other substituted
%*e-dihydroxybenzeneSt benzoic acids, and naphthalenes. Acute toxicity
of several substituted imidazolines and sodium petroleum sulfonates is
reported.
It is concluded that the most pronounced environmental effects of
drilling mud may be due to physical action of suspended solids. Organic
additives may possibly be selected in such a way that the use of highly
toxic compounds will be eliminated.
INTRODUCTION
In comparison with studies of the environmental effects of petroleum,
very little attention was given to the toxicity and environmental prop-
erties of materials used in well-drilling operations. Simpson reviewed
the state-of-the-art in mud engineering, paying particular attention to
chromolignite, chromolignosulfonate, and surfactants (ref. 1). Collins
discussed the pollution potential of petroleum production; presented a
list of components of drilling muds, well-treatment chemicals, and brines;
and indicated the consumption of some of the chemicals (ref. 2). Falk
and Lawrence determined the acute toxicity of drilling muds and some
*Section Leader, Toxicology Section, Environment Canada Biological
Station, St. Andrews, New Brunswick, Canada, EOG 2X0.
311
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of their components, as used in the Canadian Arctic. The 96hLC50
values for fish ranged from 0.8 to 12 percent for drilling muds and
22 to 81 percent for sumps (ref. 3). 'The authors suggested establish-
ing toxicity limits for the effluents and regulating the concentration
of hydrocarbons and suspended solids, pH, BOD, and COD. Land reviewed
recently the toxicity of drilling mud components (ref.- 4).
This paper discusses the acute toxicity and some environmental
properties of drilling mud components and chemicals used in well-drilling
operations. Particular attention is given to organic additives. The
acute toxicity of some of the compounds was determined, and structure-
activity relationships were used to estimate the toxicity of others.
INORGANIC COMPONENTS
Barite and clays are the main suspended solids in drilling muds
(refs. 4,5). Barite particles are quite small (-325 mesh) and it has
been estimated that approximately 110 lb/1,000 t is lost to the atmos-
phere as a result of handling (ref. 6). No data on the amounts dis-
charged in water are available. The annual consumption of barite in the
United States probably exceeds 1.2 x 10 t/year (ref. 6).
The background concentration of barium in seawater is 0.03 mg/1
(ref. 7). As a result of barite discharges, the concentration of barium
may be significantly increased in localized areas. The solubility of
barite in seawater and freshwater, expressed as barium, is 14.8
and 3.6 mg/1, respectively. The increased levels of dissolved barium
are probably not environmentally significant since barium has a rela-
tively low toxicity in comparison with other metals.
Using the data of Baudouin and Scoppa (ref. 8), the acute
toxicity of a number of divalent cations to three species of aquatic
fauna was correlated with the cation binding constants of glycine in
equations (1) to (3).
log c = -0.627 log ^ + 1.26 (1)
log c = -0.419 log ^ + 1.13 (2)
log c = -0.381 log + 1.44 (3)
312
-------
where c = 48hLC50 in millimoles/1,
K, = cation binding constant of glycine.
Equations (1), (2), (3) apply to Daphnia hyalina, Eudiaptomus padanus
padanusj and Cyclops abyssorwn prealpinus, respectively. The values of
log K, are 0.77, 0.91, and 8.3 for barium, strontium, and copper,
respectively. It can be seen that the acutely toxic concentration of
barium, which was not determined by Baudouin and Scoppa, should be in
the neighbourhood of 500 mg/1.
Barite and other suspended components of drilling mud would affect
the environment physically. For example, the pumping rate of oysters
is depressed 50 percent in the presence of suspended matter at 100 mg/1
(ref. 9), and the uptake of calcium by clams and seaweeds is decreased
to 50 percent of the normal level in the presence of 6.5 and 0.4-0.8
percent of suspended solids (ref. 10). Suspended solids are deleterious
to bottom-dwelling organisms when the bottom is covered by a 1-cm layer
of fine solids. The plankton abundance is reduced 22 percent by sedi-
menting suspended matter at a concentration of 250 mg/1, and no plankton
can be found in the presence of 2 percent of suspended solids (ref. 10).
On the other hand, fish are apparently attracted by high concentrations
of drilling muds (ref. 11).
The physical effects of suspended solids may be minimized by a
good dispersion, and Mackin and Hopkins concluded that barite had no
effect on the survival of oysters (ref. 12).
The baseline levels of suspended solids are relatively low. A
concentration of up to 500 mg/1 may be encountered in river runoffs,
but normally the levels are approximately 30 mg/1 and the solids con-
tain about 33 percent of organic material. Near-shore levels of sus-
pended material are of the order of a few mg/1 and decrease within a
relatively short distance to 0.1 mg/1 (ref. 13). The concentration of
suspended solids in the open ocean ranges from 0.03 to 0.07 mg/1 (ref. 14),
Chromium is another important constituent of drilling muds. In
chromolignosulfonates and very likely in the presence of any appreciable
amount of organic matter, chromium is present in its trivalent form
(ref. 15), and bound quite strongly to organic matter, as it was demon-
strated in the case of chromolignosulfonates (ref. 16). The binding
313
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of chromium by organic matter may make chromium unavailable to aquatic
fauna and flora and significantly reduce its toxicity. In the
absence of organic matter, chromium is highly toxic, at least to cer-
tain species. The reported ranges of toxicity in terms of 48- or
96hl_C50 are 0.01-76, and 0.05-133 mg/1 for tri- and hexavalent chromium,
respectively (ref. 17).
Arsenite is used as a corrosion inhibitor (ref. 2). The acute
toxicity of arsenite is in the order of 1-2 mg/1 (ref. 18). Quite
high background levels of arsenic, presumably of natural origin, may be
found in shellfish.
Many aquatic and particularly marine species are very sensitive
to pH. Clam and oyster embryos survived in a pH range of 7,,00-8.75
(ref. 19). Values of pH<8 were on the other hand lethal to herring.
(ref. 20).
POLYMERS
A number of polymers—natural, modified natural, or synthetic—may
be used in drilling muds. These compounds are generally nontoxic due
to their high molecular "weight, which prevents them from entering living
cells. On the other hand, residual monomers, oligomers of relatively
low molecular weight, or residues of modifying chemicals (such as long-
chain aliphatic amines, which are used to treat some lignosulfonates)
could be appreciably toxic.
Polysaccharide-based materials are probably readily biodegraded,
but lignites, lignosulfonates, and humic acids are very stable and so
are some synthetic polymers.
In the case of lignosulfonates, the biodegradability depends on the
source of the material, and kraft-derived lignosulfonates are much more
readily biodegraded than the true lignosulfonates, originating in the
sulfite process (ref. 21). The biodegradability of wood fiber decreases
with increasing lignin content, and ground wood (mechanical pulp)
hardly undergoes any degradation (ref. 22).
An ethylene-maleic acid copolymer was not biodegraded over a period
314
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.of 30 days, whereas, in the same time, 7 and 20 percent of sodium poly-
acrylate and a methyl vinyl ether-maleic acid copolymer, respectively,
were degraded (ref. 23).
LOW MOLECULAR WEIGHT ORGANIC COMPOUNDS
The reviews mentioned earlier, an EPA list of chemicals used in
well drilling, and a search of recent patent literature indicates a
number of low molecular weight organic additives for use in drilling
muds. Toxicity data are not available for most of these compounds,
and the following attempts to estimate their acute toxicity from struc-
ture-activity relationships are derived from our studies of the general
relationships between the acute toxicity and structure of chemicals.
°CBA
2
log P
igure 1. Acute toxicity of benzene and naphthalene derivatives as a
function of partition coefficient, c = 96hLCO, mole/1; P = octanol-
water partition coefficient; A=aniline; P=phenol; BA=benzoic acid; HBA=
o-hydroxybenzoic acid; CBA=o-chlorobenzoic acid; BBA=p-£er£-butylbenzoic
acid; AN=l-aminonaphthalene; HNA=l-hydroxy-2-naphthoic acid; 1N,2N=1-,
and 2-naphthol, respectively.
315
-------
The toxicity is expressed in terms of 96NLCO and is determined in static
tests with juvenile Atlantic salmon (Salmo salar) at 9°C in soft tap-
water. The general type of structure-activity relationships and their
applications to fish toxicology were reviewed (ref. 24).
In most cases the only structural parameter used was the octanol-
water partition coefficient (P). This parameter may predict the
toxicity quite accurately in series of related compounds with identical
or similar functional groups. In some cases, Hammett a constants were
also used as structural parameters.
As a starting point for the estimation of acute toxicity of aro-
matic compounds, the toxicities of several simple benzene and naphtha-
lene derivatives are plotted against P in log-log coordinates (figure 1).
The plots are linear and can be expressed by equations (4) and (5) for
benzene and naphthalene derivatives, respectively.
log (1/c) = 0.259 log P + 3.13 (4)
log (1/c) = 0.889 log P + 2.54 (5)
Monosubsti tuted 1,2-di hydroxybenzenes. A number of these compounds
with different substituents in the 4- position were patented. The acute
toxicity of catechol was determined in our laboratory. The toxicity of
the other compounds was estimated from equation (6), which was derived
originally for nitrophenols (ref. 24) and adjusted to fit catechol, and
from equation (7), which is the equation of a line parallel to that
given by equation (4), but adjusted to the toxicity of catechol.
log (1/c) = 1.2 log P + 2.9o + 3.48 (6)
log (1/c) = 0.259 log P + 4.31 (7)
The toxicities calculated from equation (6) were almost always higher
than those obtained from equation (7); they are given in table 1. Geomet
rical means of these two estimates, also presented in table 1» are
probably closer to reality.
Pi substituted 1,2-dihydroxybenzenes. The toxicity of these compound
was estimated as above and the results are given in table 2. It should
be noted that the presence of sulfo- groups significantly decreases the
acute toxicity.
Substituted benzoic acids. The toxicity estimates are based on
316
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Table 1. Prediction of acute toxicity of 4-substituted
1,2-dihydroxybenzenes to juvenile Atlantic salmon
Substituent
in position 4
HOOC(CH2)2-
OCH-
H-
CH3-
H2C=CH2CH2-
HOOCCH=CH-
02N-
Cl-
96hLCO, mg/1
Mol. -wt.
182
138
110
124
150
180
155
145
log P
0.59
0.23
0.88
1.44
1.98
0.88
0.60
1.59
a
-0.05
0.38
-0.12
-0.10
0.52
0.75
0.30
eq.(6)
16.6
1.9
1.7
0.4
0.2
0.1
0.1
eq.(7)
6.3
5.9
2.6
2.3
5.2
5.4
2.8
geom. mean
10.2
3.4
3.2*
2.1
1.0
0.9
0.6
0.5
*Determined value.
equation (4) and the results are summarized in table 3. In general, the
introduction of a carboxyl decreases the toxicity of these compounds.
Various benzene derivatives. The toxicity of 1,3-dihydroxy-2,4-
dinitrobenzene was calculated from the equation used for nitrophenols
(ref. 24); the toxicities of the remaining two compounds were obtained
from equation (4). The results are presented in table 4.
Substituted naphthalenes. The toxicity of substituted naphthalenes
was estimated from equation (5). It is interesting to compare the
toxicity of l-hydroxy-2,4-dinitronaphthalene with that of 2,4-dinitro-
phenol. If the prediction for the former compound is correct, then
its higher toxicity is caused entirely by the increased partition co-
efficient. As in the case of benzenesulfonic acids, the toxicity of
naphthalenesulfonic acids is expected to be relatively low (table 5).
Aliphatic compounds. Compounds of this class, found in the
patent literature, are listed in table 6. Related reference compounds
are not available and the toxicities could not be estimated. It is
likely that these compounds are not very toxic.
317
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Table 2. Prediction of acute toxicity of disubstituted
1,2-dihydroxybenzenes to juvenile Atlantic salmon
96hLCO, mg/1
Substituents
4,6-disulfo-
4-methyl-5-
chloro-
3-methyl-5-
tert-butyl -
3,5-di-iso-
propyl -
Mol. wt.
270
158
180
194
log P
-8.64
2.15
3.42
3.94
a
0.14
0.18
-0.27
-0.22
eq.(6)
8X1 O11
0.04
0.03
0.01
eq.(7)
2300
2.1
1.1
0.9
geom. mean
*
0.29
0.18
0.06
^Practically nontoxic.
Table 3. Prediction of acute toxicity of substituted
benzoic acids to juvenile Atlantic salmon
Substituents
Benzoic acid
- 2,4,5-tricarboxy-
- 2,4-dihydroxy-
-3-carboxy-4-hydroxy-
-2,4-dicarboxy-
-4-ethoxy-2-hydroxy-
mol . wt.
122
255
154
182
210
182
log P
1.71
-0.55
0.37
0.72
1.07
1.42
96HLCO, mg/1
eq.(4)
24*
260
92
89
81
57
*Determined value.
318
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Table 4. Prediction of acute toxicity of various
benzene derivatives to juvenile Atlantic salmon
Compound Mol. wt. log P a 96hLCO, mg/1, eq.(4)
l,3-dihydroxy-2,4- _
dinitrobenzene 176 0.14 1.14 0.7a
4-hydroxyacetophenone 136 1.10 — >30
^,4-dihydroxyaceto-
phenone 152 0.15 — 100
2-hydroxy-5-methyl
acetophenone 150 1.57 -- 43
aLog (1/c) = 1.2 log P + 2.91a (ref. 24).
Determined value.
Table 5. Prediction of acute toxicity of substituted
naphthalenes to juvenile Atlantic salmon
Compound Mol. wt. log P 96hLCO, mg/1, eq. (4)
hydroxy-2,4-dinitro- 234 2.42 4.8*
carboxy-3,5-dihydroxy- 204 1.99 3.4
amino-2-hydroxy-4-sulfo- 239 -3.15 100
*0.06 from eq. log(l/c) = 1.2 log P + 2.91a, a = 1.27; compare
0.25 for 2,4-dinitrophenol (ref. 24).
319
-------
Table 6. All cyclic and aliphatic compounds of
low toxicity
1,2,3,4-cyclaperrtane tetracarboxylic acid
l,2,3»5-tetrahydroxycyclohexane carboxylic acid
hexahydroxycyclohexane
1,3-dihydroxy-2-propanone
1,3-dihydroxy-2-butanone
1,4-dihydroxy-2-butanone
Table 7. Acute toxicity of amines to juvenile
Atlantic salmon
Compound Mol. wt. 96hLCO, mg/1
Polyalkylene imines
-CH2CH2-NH2 103-189 20-30
x = 0-3
Long chain aliphatic amines
Dodecyl amine C,2H27N 185 1-5
Hexadecyl amine C-ieHocN 241
N-alkyl diamines
RNH-(CH9) -NH9, R = CR-C97,
c. X c o C.C.
x = 2-4
N-coco-propylene diamine 270 <1
320
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Amines and imidazolines. No structure-activity relationships
are as yet available for these compounds. The data obtained experi-
mentally in our laboratory are summarized in tables 7 and 8, and indi-
cate a relatively high toxicity. Sulfuric acid was used to control pH
in tests with polyalkylene imines. In the case of the substituted
imidazolines, quaternarization by benzyl and 2-(sodium carboxy)-ethyl
does not have much effect on the acute toxicity, except for the amphoteric
"coco" derivative, which is nontoxic at 10 mg/1. Similarly to other
surfactants, the length of R may strongly affect the toxicity.
Surfactants. A variety of surfactants may be used in well drilling
operations. Some of the typical products are listed in table 9. Partition
coefficient-based structure-activity relationships are not available
for this class of compounds. The toxicity may be correlated with the
length of the aliphatic chain of alkylbenzene sulfonates, and reaches
a maximum at about C]£~C-io- The toxicity of nonionic surfactants is
related among other things to the length of the oxyethylene chain and
decreases with increasing length of the chain. Extensive literature is
available on the toxicity of surfactants to aquatic fauna (see for ex-
ample ref. 25). The acute toxicity ranges from less than 1 to more
than 100 mg/1, but, the acute toxicity data can be particularly mislead-
ing. A delayed mortality may occur after exposure to concentrations as
low as 1/3,000 of 24hLC50 (ref. 26), and chemoreceptors of aquatic
fauna may be possible targets in sublethal exposures (ref. 27). Some
surfactants may also simulate biological activity of natural compounds
such as steroid glycosides of starfish (ref. 28). Alkyl polyglycol
ethers are taken up by fish (ref. 29), and residues of anionic sur-
factants in the mg/kg range were detected in some fish and shellfish
(ref. 30).
Quaternary ammonium salts with C-ic-C-ia alkyls are very toxic, but
their toxicity may be at least partly moderated by adsorption on suspended
solids (ref. 31). Dimethyl-dicoco-ammonium chloride, patented for use
in drilling operations, has a 96hLCO of 0.9 mg/1.
The acute toxicity (96hLCO) of petroleum sulfonates was 3.7, 1.9,
and 3.1 mg/1 for preparations with an average molecular weight of 350,
321
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Table 8. Acute toxicity of substituted
imidazolines to juvenile Atlantic salmon
*
R
C12 " C20
Coco(C13H2?)
Stearyl (C1?H35)
Coco
Stearyl
DodecyKC^)
Coco
Stearyl
i
R1
NH2 or OH
OH
OH
OH
OH
OH
OH
OH
R2
1
N ' T«fc N-CH CH -R
R
0
R* Mol. wt. 96hLCO, mg/1
—
296 2.5
352 0.6
CCHCCH0 404 1.0
0 J> C.
460 3.5
CH2C02Na 366 >35
" 394 >10
450 4
Table 9. Typical surfactants used in drilling muds
Ethylene oxide adducts of: Sulfated or sulfonated:
Castor Oil Castor Oil
Phenol ^IS^lfi a^Pnat1c hydrocarbons
Nonyl phenol Dodecyl benzene
Petroleum
322
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450, and 500, respectively. Petroleum sulfonates are quite ill-defined
products and their toxicity may be very much affected by the composition
of the parent petroleum stock.
Bactericides. These compounds are generally highly toxic to
aquatic fauna. Preference should be given to compounds with higher
solubility in water and lower P. The use of pentachlorophenol
should be eliminated because of its high toxicity, bioaccumulation
potential, and the presence of toxic impurities such as chlorinated
dibenzodioxins, dibenzofurans, and diphenyl ethers.
CONCLUSIONS
The presented data indicate that under normal circumstances the
most pronounced detrimental effects on the environment may be caused
by the physical action of suspended solids from the drilling muds.
The high molecular weight organic constituents of drilling muds are
relatively nontoxic, the molecular weight constituents have toxicities
ranging from high to relatively low, and it may be possible to select
technically satisfactory compounds that are not very toxic. The same
may be true about surfactants.
Little is known about the effects, encountered during the drilling,
of high temperatures on the organic additives. Hydrolysis of polymers
and elimination of some functional groups may take place. The products
of these reactions could have higher toxicity than the parent compounds.
Some drilling muds may contain certain petroleum fractions or tar.
An extensive literature on the effects of these materials on the aquatic
environment is available and it is obvious that the discharge of these
substances should be limited as much as possible.
An attempt was made to estimate the acute toxicity of a number of
compounds by structure-activity relationships. Time will tell how suc-
cessful this approach is. It would certainly be useful for a better
and systematized understanding of environmental properties of chemicals.
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ACKNOWLEDGMENT
I wish to thank Mr. W. 6, Carson for efficient technical assistance,
Mrs. Madelyn M. Irwin for help with literature documentation and typing
the manuscript, and Messrs. P.W.G. McMullon and F.B. Cunningham for
preparation of slides and figure.
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1. J. P. Simpson, "What's New in Mud Engineering?" World Oil > Vol. 164,
No. 5 (1967), pp. 135-139, and No. 6 (1967), pp. 118-122.
2. A. G. Collins, "Are Oil- and Gas-Well Drilling Production, and
Associated Waste Disposal Practices Potential Pollutants of the
Environment?" ACS Div. Water. Air and Waste Chem.. Vol. 10, No. .2
(1970), pp. 1-14.
3. M. R. Falk and M. J. Lawrence, "Acute Toxicity of Petrochemical
Drilling Fluids Components and Wastes to Fish," Environment Canada,
• Fish. Mar. Ser. Tech. Rep. CENT-31-1, Freshwater Institute, Winnipeg,
T973~:
4. B. Land, "The Toxicity of Drilling Fluid Components to Aquatic
Biological Systems: A Literature Review," Environment Canada,
Fish. Mar. Ser. Tech. Rep. No. 487, Freshwater Institute, Winnipeg,
1974.
5. J. W. Hosterman, "Clays," U.S. Giol. Survey. Prof. Paper 820, pp.
123-131, Washington, 1973.
6. W. E. Davis and Associates, "National Inventory of Sources and
Emissions: Section I - Barium, NTIS, PB-210 676, May 1972.
7. W. F. Mcllhenny and M. A. Zeitoun, "A Chemical Engineer's Guide to
seawater," Chem. Engng. (1969), pp. 251-256.
8. M. F. Baudouin and P. Scoppa, "Acute Toxicity of Various Metals to
Freshwater Zooplankton," Bull. Environ. Contam. Toxicol, Vol. 12
(1974), pp. 745-751.
9. C. B. Oorgensen, "Quantitative Aspects of Filter Feeding Inverte-
brates," Biol. Rev. Vol. 30 (1955), pp. 391-454.
10. M. Fujiya, "Studies on the Effects of the Tailings of Flotation
Process to the Coastal Organisms," Bull. Jap. Soc. Sci. Fish., Vol
26, (I960), pp. 955-959.
324
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11. M. Lawrence and E. Scherer, "Behavioral Responses of Whitefish
and Rainbow Trout to Drilling Fluids," Environment Canada, Fish.
Mar. Ser. Tech. Rep. 502, Freshwater Institute, Winnipeg, 1974.
12. J. G. Mackin and S. H. Hopkins, "Studies on Oyster Mortality in
Relation to Natural Environments and to Oil Fields in Louisiana"
Publ. Inst. Mar. Sci., Vol. 7 (1962), pp. 1-131.
13. F. T. Manheim, R. H. Meade, and G. C. Bond, "Suspended Matter in
Surface Waters of the Atlantic Continental Margin from Cape Cod
to the Florida Keys," Science. Vol. 167, No. 3917 (1970), pp. 371-376.
14. M. B. Jacobs and M. Ewing, "Suspended Particulate Matter: Con-
centration in the Major Oceans," Science. Vol. 163, No. 3865 (1969),
pp. 380-383.
15. W. G. Skelly and D. E. Dieball, "Behavior of Chromate in Drilling
Fluids Containing Chrome Lignosulfonate," Soc. Petrol.__ Eng. J.,
Vol. 10, No. 2 (1970), pp. 140-144.
16. J. L. McAtee, Jr., and N. R. Smith, "Ferrochrome Lignosulfonates.
1. X-ray Absorption Edge Fine Structure Spectroscopy. 2. Inter-
action with Ion Exchange Resin and Clays," J. Colloid Interface
Sci.. Vol. 29, No. 3 (1969), pp. 389-398.
17. R. McV. Clarke, "A Summary of Toxicity Information for Major Ef-
fluent Components from Inorganic Chemical Industries," Environment
Canada, Fish. Mar. Ser. Tech. Rep. CENT-74-9^ Winnipeg, 1974.
18. C. D. Becker and T. 0. Thatcher, "Toxicity of Power Plant Chemicals
to Aquatic Life," U. S. Atomic Energy Comm.. Wash-1249, UC-11,
Washington, 1973.
i9. A. Calabrese, "Effects of Some Pollutants on Embryos and Larvae of
the American Oyster and Hard Shell Clam," ACS Div. Water, Air and
Waste Chem.. Vol. 11, No. 2 (1971), pp. 64-75.
!0. V. Zitko, J. M. Anderson, and S. N. Tibbo, "Toxicity of the Phos-
phorus-Production Wastes to Fish," Fish. Res. Board Can. MS. Rep.
1050, St. Andrews, 1969.
:1. H. 0. Bouveng and P. Solyom, '"Long-term Stability of Waste Lignins
in Aquatic Systems," Sv. Papperstidn. Vol. 76, No. 1 (1973), pp. 26-29.
2. B. V. Hofsten and N. Edberg, "Estimating the Rate of Degradation of
Cellulose Fibers in Water," Oikos. Vol. 23, No. 1 (1972), pp. 29-34.
3. W. K. Fischer, "Prufung der Biologischen Abbaubarkeit von Synthet-
ischen Verbindungen, z. B. fietergentien," Vom Wasser, Vol. 40, (1973),
pp. 305-334.
325
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24. V. Zitko, "Structure-Activity Relationships in Fish Toxicology,"
Great Lakes Research Advisory Board. International Joint Commission
Symposium on Structure-Activity Correlations in Studies""*)? Toxicity
and Bioconcentration with Aquatic Organisms,G. D. Veith and D. E.
Konasewich, Editors, Windsor, 1975, pp. 7-24.
25. M. Swedmark, B. Braaten, E. Emanuelsson, and A. Granmo, "Biological
Effects of Surface Active Agents on Marine Animals," Marine Biol..
Vol. 9 (1971), pp. 183-201.
26. E. J. Perkins, "Some Effects of Detergents in the Marine Environment,"
Chem. & Industry. No. 1 (1970), pp. 14-22.
27. J. E. Bardach, M. Fujiya, and A. Holl, "Detergents: Effects on the
Chemical Senses of the Fish lotalurus natal-Ls (le Sueur)," Science,
Vol. 148, No. 3677 (1965), pp. 1605-1607.
28. A. M. Mackie, "Avoidance Reactions of Marine Invertebrates to
Either Steroid Glycosides of Starfish or Synthetic Surface-Active
Agents," J. Exp. Mar. Biol. Ecol. Vol. 5, No. 1 (1970), pp. 63-69.
29. C. Gloxhuber and W. K. Fischer, "Action of High Concentrations of
Alkyl Polyglycol Ethers on Fish," Food Cosmet. Food Cosmet. Toxicol.,
Vol. 6, No. 4 (1968), pp. 469-477.
30. S. Bellassai, and S. Sciacca, "Presence of Anionic Detergent Residues
in Specimens of Fish and Shellfish Purchased on the Open Market,"
Iqiene Moderna, Vol. 66, No. 4 (1973), pp. 348-361.
31. S. F. Krzeminski, 0. J. Martin, and C. K. Brackett, "Environmental
Impact of a Quaternary Ammonium Bactericide," Household Pers. Prod.lnd
Vol. 10, No. 3 (1973), pp. 22-24.
DISCUSSION
MR. JACK W. ANDERSON (Texas A&M University, College Station, Texas): Dr.
Zitko, I think the method of evaluation of the different toxicants
was very interesting. I think the problem was in the evaluation of
the effects of sediments. You got your data or your data is pro-
duced from, what, the northwest or northeast? I think there is a
little bit of difference between those waters and the estuarine and
near-shore waters of the Gulf of Mexico, where our sediment loads
are much greater. And I think that you were talking in low milli-
grams per liter, I believe. I think that would be unusual. Of
326
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course, it is expected that the drilling operations will be ex-
tended in the clearer waters, but I think for a lot of the waters
of the Gulf of Mexico the organisms are accustomed to rather high
turbidities and high sediment loads.
DR. ZITKO: Yes. I agree completely with you. It depends, really, on
the area. And I am sure the conditions are different in the Gulf
of Mexico.
MR. WAYNE H. McKENZIE (Milchem, Inc., Houston, Texas): So far we have
heard the word toxicity, but from the various papers we have heard
how toxicity is measured as 96-hour LC™, 96-hour TLcn, 96-hour
bU oU
LDj-g, 96-hour LT50. I wonder if you might go into some of these
differences in terminology for comparison purposes; exactly what
they mean?
DR. ZITKO: Ninety-six-hour LC5Q and 96-hour TLgg are synonymous and re-
fer to a concentration (mg/1) that kills 50 percent of the test
animals in 96-hours. LD5Q is a dose in mg/kg body weight that
kills 50 percent of the test animals. IT™ is time to 50 percent
mortality. I think somebody yesterday had a graph of LT5Q plotted
against concentration. Reading from the curve at 96 hours he de-
termines the 96-hour LCcn. This approach is fine as long as you
have mortalities within that time.
In our experience, what usually happens is that there is a
breakoff point in the curve before you reach 96 hours.
We talk in terms of the 96-hour lethal threshold (LCO), which
is the geometric mean of the highest concentration where we do not
get mortality and the lowest concentration, where we still get an
LT50 value. On the other hand you have to keep in mind that the
variety of aquatic fauna is tremendous, and the sensitivity of dif-
ferent species varies appreciably, not only between the species, but
even the same species may have different sensitivities depending on
the season. One has to be very careful in talking in terms of acute
toxicity. It more or less ranks the compounds, but really it is
very difficult to translate acute toxicity data into environmental
effects.
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MR. PAT M. WENNEKENS (Alaska Department of Fish & Game, Anchorage,
Alaska): I have two questions. One is that the information you
have gathered pertains to freshwater systems, from what you
showed. Once those things are being introduced into the marine
environment, they get into a complex ionic solution. My first
question is, what kind of prediction do you have in terms of
changing the chemical composition or phase that would provide
differences in toxicity, as you are getting into pretty complex
ion solutions?
My second question relates to your test program. Did you
make those measurements on the early embryonics and juvenile
stages of some of the forums rather than the adults, at which
stage they are much more sensitive to different types of compounds?
DR^ ZITKO: To the first question, the answer is complex. It depends on
the type of compound. Some compounds may be more toxic in sea-
water than they are in freshwater, and for some compounds it
would be the other way around. It depends on the character of the
compound. So ionic compounds may be less toxic in seawater than
they are in freshwater; on the other hand, highly lipoplinlic com-
pounds may be more toxic in seawater than they are in the fresh-
water. An example of this is an exotic compound, the yellow
phosphorus. Yellow phosphorus is more toxic in seawater than in
freshwater. And it depends on the basic physiology of the fish,
because in the seawater they really have to drink water and in
freshwater it is the other way around. So it is a complex situation
I would say that ionic compounds, such as phenols, may be
less toxic in seawater than they are in freshwater.
We are doing our tests mostly on juvenile Atlantic salmon, but
I agree with you that once you have several life stages of a certain
animal, the embryonic forms are not necessarily the most sensitive
ones. It depends. There is no general rule what to do.
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MR. DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba, Canada):
Dr. Zitko, I would like to thank you for the plug for the two
Environment Canada papers, those being the Falk and Lawrence re-
port, and also the Bernard Land literature review. These papers
are available from our Winnepeg office, Environment Canada. And
if you would like, I can get copies for any of you who are in-
terested, if you would just care to give me your name and address
I can have them sent out.
I would also like to say that Environment Canada and the Arctic
Petroleum Operators Association have been engaged in a 2-year study
program, as Bob Weir mentioned yesterday, looking at the environmental
effects of drilling fluids. And we are going to be producing three
rather large volumes of papers sometime this summer as a result of these
studies; hopefully these will be available to the U.S. people as well.
Again, if you would like these papers, as well, could you leave
your name and address with either Bob Weir or myself.
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22 May 1975
Session II: (con.)
ENVIRONMENTAL IMPACT OF CHEMICALS
USED IN WELL DRILLING
C. S. Giam, Ph.D.
Chairman
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POTENTIAL EFFECTS OF OIL DRILLING AND
DUMPING ACTIVITIES ON MARINE BIOTA
Robert Y. George, Ph.D.*
?s tract
The objective of this paper is to provide a base for discussing the
issible perturbations of oil drilling activities on the biota inhabiting
\e inner and outer continental shelf regimes. A perusal of literature on
'is subject points out clearly our inadequate knowledge on the impact of
Billing mud components on marine biota and our meager understanding of the
•ronic effects of spillage of oil on both plants and animals in the marine
vironment.
On the basis of results obtained in recent offshore ecological inves -
gations in the Louisiana Continental Shelf3 efforts are made to evaluate
e extent of effects of drilling activities on the biota and the physical
vironment adjacent to oil platforms. In recognition of the need for
riving at models depicting the impact of drilling activity on the marine
osystem, inferences are drawn here to consider biological implications of
tential effects of drilling discharges under the following four aspects:
(1) Impact of drilling materials causing "burial effect" on the sea-
floor benthos.
(2) Discharge of drilling mud components and their possible accumula-
tion or magnification in the food chain.
(3) Influence of turbidity-plumes of drilling mud on the filter-
feeding fouling organisms.
(4) Acute and chronic effects of spillage of crude oil on marine
biota.
INTRODUCTION
The fundamental question posed in this paper can be simply asked as
lows: What are the acute and chronic effects of the addition of various
*Associate Professor and Chairman, Experimental Oceanology Program,
ititute of Marine Biomedical Research, University of North Carolina at
mington, Wilmington, North Carolina 28401.
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inert and toxic substances used in the oil drilling process on the marine
biota? It is realized that the compounds of oil-base or bririe-water-base
drilling mud enter the marine environment as adherent particles of the
drill cuttings that are generally dumped in the site of drilling. This
drilling operation evidently promotes a localized alteration in the enviror
ment, both in the water column by way of resuspension and redistribution o1
particulate matter, and in the benthic regime by the deposition over the
bottom sediments of material containing cuttings and drilling mud. It is
known that in the Louisiana inner and outer continental shelf environment
drilling mud was introduced into the ecosystem during the process of
drilling oil wells since the inception of the first well in 1947. The
typical ingredients of the drilling mud include materials such as barium
sulphate, bentonite clay, hydrated lime, caustic-sodium hydroxide as well
as the most common additive, Ferrochrome Lignosulfonate, which is a waste
byproduct of the paper industry (ref. 1). Different compounds are used to
obtain various properties such as weight (barite), viscosity (density
materials), suspension (clay), bacteriocide (paraformaldehyde), and lubri-
cating agents (diesel oil). The precise effect of these different compo-
nents of the drilling mud on the survival and physiological performance of
marine animals has not been critically examined thus far in any long-term
experiments in the laboratory or in the natural environment. However,
experimental studies have been performed to test the toxicity of the com-
posite drilling mud for establishing 50 percent lethal dose levels (LD 50
or also known as tolerance limits - TL50) with a standard exposure period
of 96 hours. These acute studies give clues as to the critical concentra-
tion levels, generally exceeding 1,000 ppm, that induce deleterious effed
in the marine biota. In most cases such high levels reach near-saturatior
limits and in fact, the dynamic process of dilution caused by water move-
ment in the marine environment leads to drastic reduction of these concen-
trations. The effect of certain components of the water-base drilling
mud on marine biota was first investigated by Daugherty in the early fift
in Louisiana coastal environment (ref. 2). He essentially reported on ths
nontoxic nature of such components as bentonite and barite on marine life
Nevertheless, to date we do not possess data on the sublethal or chronic
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effects of such drilling mud components which are usually used in small
quantities and can cause concern if accumulation takes place in marine
biota.
Field observations provide information concerning the quantities of
drilling fluid and drill cuttings discharged during drilling operations.
The drill cuttings appear to contain primarily sand and shales, which tend
to descend to settle on the bottom rather rapidly due to gravity. Drill
cuttings are not commonly encountered at the base of the producing plat-
forms in the Louisiana shelf, and the shales offer a new substratum for the
settlement of larvae of sessile fouling organisms such as the acorn barna-
cles. On the contrary, the drilling mud when discharged does not sink
rapidly but produces a plume of turbidity in the upper layer of the water
through the water column down to the bottom. The concentration of this
plume depends on the density stratification of the water column. Its pro-
longed existence can cause effects of biological consequence on the
plankton in the surface, the nekton in the midwater, and the benthos on
the sea floor. The influence on the biota can be considered as acute
effects in short-term conditions. Furthermore, the effect on biota should
be treated with reference both to physical interference of biological pro-
cesses, such as photosynthesis and respiration due to the turbidity-pro-
jucing mud compounds, and to the chemical aspects of toxicity-causing mud
:ompounds. Generally, the mud additives of clay-type emulsions have a
"elatively low level of toxicity. As pointed out earlier, laboratory
experimental data are lacking on chronic effects of drilling mud compounds
)n the marine animals. In the marine environment, the effect is apparently
localized since the drill cuttings are generally found to occur within 100
:eet from the nucleus of the oil platforms in Louisiana shelf. However, the
;uspended drilling mud can get carried by currents to distant locations from
:he point of origin. In the drilling operation, effort is made to recover
.he drilling mud for reuse and the' major portion of mud components enter
.he marine environment as adherent particles of the drill cuttings that are
enerally dumped into the sea.
In my opinion, the concern on effects of the inert mud components on
he marine ecosystem should be examined in the perspective that mud is not
n alien material to the ocean. It turns out that over 70 percent of the
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ocean floor is made up of a mud-type substratum that is known to support a
variety of marine life. The floor of the abyssal plain has a continuous
bed of red clay sediment with occurrence of manganese nodules. The conti-
nental slope and rise include vast stretches of brown or green mud with a
mixture of globigerina ooze. Mud flats along the shore are not uncommon. IT
the continental shelf environment with mud bottom conditions such as in the
areas off Louisiana, the presence of mud-laden layers dominate the near
bottom depths in the water column. It is estimated that the daily dumping
of mud by the Mississippi River into this shelf region exceeds; over a
million tons. The influence of the Mississippi mud or the drilling mud is
primarily a physical phenomenon due to the production of turbidity plumes.
The point for consideration is the potential effect of seepage into biolog-
ical systems of small quantities of substances which can cause disruptions.
Although our knowledge on the impact of the drilling mud additives on
marine biota is meager today, it is important to focus on potential effects
and delineate specific investigations in conjunction with the current OCS
oil and gas development. I have chosen to deal with potential effects
under four distinct categories as follows:
(1) "Burial Effect" of Drilling Mud On Sea-Floor Benthos,
(2) Entry and Transport of Drilling Mud Components In Marine Food
Chain,
(3) Influence of Turbidity Plumes of Drilling Mud on Organisms, and
(4) Acute and Chronic Effects of Oil On Marine Biota.
"BURIAL EFFECTS" OF DRILLING MUD ON SEA-FLOOR BENTHOS"
In the offshore environment, the rate of deposition of sediment is
gradually reduced as the distance increases from the shore. In the nereti(
zone, mostly within 20 miles from the coastline, the sea floor is subject
to active sedimentation. In general, the sediment input from land runoff
is significantly higher in the sea floor environment adjacent to riverjnouth
and inlets. Such a benthic regime is usually characterized by a soft-botti
substratum that is largely inhabited by burrowing infaunal organisms. The
animals tend to occupy the upper portion of the sediment-water interface a
336
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readjust their relative positions during the active process of sedimentation.
[n the offshore oceanic zone, beyond 50 miles from the shore line, sediment
ieposition on the sea floor is declined to very low levels. The sea floor
;n such offshore environment receives primarily biogenic sediments of plank-
.onic origin. Coral reef communities prevail in deepwater zones of
•educed sedimentation. In other words, the mud bottom communities are not
ulnerable to active sedimentation and deposition of mud, but communities
.n hard substrata are evidently disturbed in the event of active mud depo-
ition. The accumulation of drilling mud and drill cuttings on a given
ubstratum is referred to here as the "burial effect."
During the offshore ecology investigations in the Louisiana continen-
al shelf (1973-74) a photo-survey was made on the sea floor in the vicinity
f several oil platforms to examine drill cuttings and their impact on the
ivironment. This study was performed as part of an investigation of the
fpes of sessile and motile organisms that flourish on the hard substratum
: the platform legs. Generally drill cuttings were not found at the base
: platform legs or in the adjacent regions. Most of these platforms have
ien in production for more than 10 years. Perhaps the deposited drill mud
id cuttings were completely covered by the process of active sedimentation
om the vast inflow of Mississippi River Plume. Observations on infrared
d color satellite photographs show the extended plume boundaries reaching
r beyond 30 or 40 miles from the shoreline. In figure 1, the undulating
ume boundary and plume directions are illustrated to show the vast impact
the Mississippi River mud on the sea floor environment and biotope
rrounding the numerous oil producing platforms and drilling rigs in this
gion of intense activity.
It is estimated that approximately 250 tons of drilling mud and about
3 tons of drill cuttings are deposited near a typical 10,000 foot Gulf
ast well (ref. 1). In recent years, a vast quantity (90 percent) of the
illing mud is recovered for reuse and only drill cuttings are dumped to
3 sea floor. It has been pointed out in earlier studies that drill
;tings accumulate as 20-foot piles beneath oil platforms in the California
>lf and the cuttings are found within 100 feet from the platform struc-
-es. This observation (ref. 3) suggests that the "burial effect" of drill
:tings is an extremely localized phenomenon and the impact on marine
337
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Figure 1. Map of the study area showing the location of oil
platforms in the Louisiana Shelf region with emphasis on
the direction and magnitude of Mississippi River plume.
338
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:igure 2. Underwater photograph showing the presence of drill cuttings
at a depth of 54 ft in the vicinity of the Exxon Oil Platform 221,
located about 10 miles from shore in the Louisiana inner shelf (south
of Grand Isle). Note the pile of drill cuttings and shales with
settlement of the barnacles. (Photo taken by P.J. Thomas during the
Offshore Ecology Investigations.)
immunities is insignificant. Furthermore, the underwater photographs of
'rill cuttings seen in our studies of offshore ecology investigations in
.he Louisiana shelf reveal the presence of acorn barnacles Balanus eburneus
figure 2). The fouling organisms settle on drill cuttings, and perhaps
he introduction of a hard substratum over the soft mud or sand bottom
nvironment induces a "reef effect" to promote proliferation of sessile
rganisms and associated motile consumers.
ENTRY AND TRANSPORT OF DRILLING MUD COMPONENTS IN MARINE FOOD CHAIN
The major concern about dumping drilling mud into the marine environ-
ent is the possible injection of small quantities of some toxic mud
dditives into the food chain. The composition of typical drilling mud is
iven in table 1. Barium sulfate constitutes the major ingredient of the
339
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Table 1. Primary components of drilling mud in order of quantitative
composition—data based on Shinn's typical example (ref. 1)
with a total of 506,300 Ib (253 tons) used in drilling a
10,000-foot oil well
A.
B.
C.
D.
E.
F.
Quantity
More than 300,000 Ib
More than 70,000 Ib
More than 20,000 Ib
More than 6,000 Ib
More than 2,000 Ib
Less than 400 Ib
Mud material
Barium sulfate
Bentonite clay
Ferrochrome
Lignosulfonate
Sodium hydroxide
Hydrated lime
Organic polymer
(Baroid Dextrid)
Lignitic material
(Baroid Carbonox)
Pregelatinized starch
(Baroid Impermex)
Defoamer
(Aluminum Strearate)
Defoamer
(Baroid Surflo W300)
Order of abundance
#1
#2
#3
#4
#5
#6
#7
#8
#9
#10
drilling mud, representing more than 90 percent of the weighting agents.
Barite used in drilling fluid contains such compounds as silica and iron
oxide. Benthonite clay is essentially an inert component. In addition to
the compounds given in table 1, certain other chemicals are used in the
well-completion process; these include calcium chloride and lignin. In th<
oil-based mud, preferably used in drilling deep wells, the lubricating oil
serves as a potential hydrocarbon carrier.
The focus here is an empirical elucidation of potential routes of
transfer of small quantities of possible toxic substances in a typical
marine food chain. These compounds can occur in the ambient medium, both
water and sediment, in the form of particulate or dissolved compounds.
These elements or compounds may find their routes through the food chain
directly into the various trophic levels by means of ingestion by the orga
nisms, or they can pass from one trophic level to a higher level in the fo
chain as illustrated in a diagramatic fashion in figure 3. We do not poss
340
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data to show whether any accumulation of a specific compound of drilling
nud can occur in any plant or animal in the food chain. We do not possess
my data to show magnification of the substances in higher trophic spectra.
lost of the compounds, including barium, are naturally found in minute
quantities (ppb) in biota, particularly in skeletons. Silica is encountered
is a building material of the exoskeleton in marine organisms, including
;ilicoeous diatoms. Calcium carbonate constitutes a major compound in
hell-bearing mollusks and corals. In the blood pigment hemoglobin iron
ecomes an integral part. These elements occur in trace quantities in the
arine organisms. Furthermore, marine animals show selective absorption of
lements and compounds by appropriate physiological mechanisms of ionic
egulation. An organism maintains an equilibrium with the bioavailable
lements of its environment. In conditions of stress due to increased levels
f these elements, the organisms accumulate the compounds in specific organs
nd also eliminate the same as metabolites or excreta to the external
nvironment.
As illustrated in figure 3, the potential impact should be considered
ider three distinct categories. First, it should be borne in mind that in
given community, different populations and even different individuals
ithin a population can respond differently to the presence of certain levels
• a substance. As a result of various responses by the different species
i a community, consequent alteration in the community structure and function
n come about in response to the effects of the introduction of new com-
lunds. The loss of certain susceptible species and the survival of resis-
:nt species induces a change in the population dynamics and food chain in
ie biotic community.
The second type of potential impact is not necessarily related to mor-
lity or survival. In conditions of altered chemical environment, certain
ocesses related to growth, reproduction, or larval development can exhibit
ther retardation or acceleration.
Thirdly, the potential impact is such that the organisms in the com-
nity either do not exhibit any modification or else they adjust effectively
rough physiological processes. This condition does not represent any
sruptive change and therefore is regarded as a "negative impact." The
341
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POTENTIAL EFFECTS OF TOXIC SUBSTANCES FROM DRILLING MUD
ENTRY INTO MARINE FOOD CHAIN
POSSIBLE IMPACT
D. LARGE CARNIVORES
INTO HUMM
COMMERCIAL SPECIES
1.
INFLUENCE ON SUSCEPTIBLE
SPECIES AND CONSEQUENT
ALTERATION IN POPULATION
DYNAMICS OF COMKUNITY.
2.
ACCLERATION OR TOTARDATION
OF PROCESSES RELATED TO
LARVAL DEVELOPMENT, JUVENILE
GROWTH AND REPRODUCTION.
3.
NEGATIVE STRESS THROUGH MAIN-
TENANCE OF BIOLOGICAL EQUILI-
BRIUM BY RELEASE OF METABOLITES
AND BY PHYSIOLOGICAL ACCLIMATI01
Figure 3. Diagramatic representation of environmental
impact of drilling mud additives.
342
-------
ddition of inert materials, such as the main components of drilling mud,
Iso possibly imposes a negative impact.
On the basis of feeding habits we can infer that mud-eating or detrito-
lagous animals are more susceptible to the impact of drilling mud than are
irnivorous animals. In the structure of a benthic community, the loss of
id-eating populations can bring about changes in species diversity and
immunity organization. The impact of any foreign substance to a biotope
uses changes not only at the community or population level but also at
e individual and cellular level in promoting or retarding processes related
growth and reproduction. When stress is applied to a system in ecological
d physiological equilibrium, reactions occur at the cellular level and
nsequently at the individual, population, community, and ecosystem level
til the system recovers equilibrium. This stress and reaction phenomena
e diagramatically illustrated in figure 4.
The marine environment is a receptacle for a variety of materials both
a result of natural events and as a consequence of man's activities.
e approximate quantities of input of some selected heavy metals, nutrients,
d synthetic organic chemicals have been tabulated, with approximate amounts
drilling mud components that possibly entered the marine environment
n'ng the establishment of about 100 oil wells (table 2). This comparison
fers overwhelming evidence as to the relatively small quantity
drilling mud compounds dumped in specific locations, particularly in the
illing sites. Nonetheless, it is essential that special efforts be made
monitor this flux of chemicals into the marine habitats and the subsequent
>w through the food chain.
INFLUENCE OF THE TURBIDITY PLUMES OF DRILLING MUD ON ORGANISMS
The dumping of drilling mud generates turbidity plumes in the vicinity
drilling sites. In the estuarine and coastal environment, turbid condi-
ns are normally encountered and several animals are adapted to cope with
h turbid conditions. Turbid water can interfere with vision in animals
can disturb behavioral patterns of migratory fish or shrimp populations.
ky water is often attributed to the suspended sediment. However, algae
343
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SYSTEM IK EQUILIBRIUM
CELLULAR/BIOCHEMICAL
CHANGES
RECOVERY OF
ECOSYSTEM
Short-term Acclimation
Long-term Adaptation
eorgani zation
n The Food C
--.««caB<«
WHOLE ORGANISMS -
COMMUNITY CIIAT'IGSS
Death & Decay
In Resistant G
eak Ponulatioi
POPULATIONS - CHANGES
Figure 4. Potential responses of ecosystem to stress.
344
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Table 2. Approximate estimates of total input into the marine
environment of materials or substances of potential
biological concern
No.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
Material
Oil (petroleum
hydrocarbons)
Nutrients (N) discharge
through rivers
Nutrients (P) discharge
through rivers
Heavy metal: lead
Heavy metal : copper
Heavy metal : zinc
Synthetic organic
chemical /DDT
Polychlorinated
biphenyls (PCB)
Barium sulphate
Bentonite clay
Hydrated lime
Caustic - sodium
hydroxide"
Ferrochrome ^
lignosulfonate
Quantity
2.6 million tons/yr
7-78.5 million tons/yr
2.00 million tons/yr
0.74 million tons/yr
0.25 million tons/yr
0.70 million tons/yr
0.25 million tons/yr
0.25 million tons/yr
0.0013 million
tons/100 oil wells
0.0004 million
tons/100 oil wells
0.0002 million
tons/100 oil wells
0.0002 million
tons/100 oil wells
0.0003 million
tons/ 100 oil wells
Source
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
4
5
6
7
8
8
4
4
1
1
1
1
1
Exclusive of atmospheric input.
Components of drilling mud, input quantity representing rough
estimate based on available figures from Louisiana Shelf.
345
-------
or diatom blooms also cause turbid conditions that are comparable to sedi-
ment turbidity. Furthermore, in the near-bottom depths* settling particles
accumulate to form clouds of extremely fine particles. This layer was
recognized by Ewing and Thorndike as a "nepheloid" (ref. 9) layer caused
by suspended matter in thedeepwater. The question here is addressed to
the influence of such turbid conditions on the biota. Midwater animals,
which are good swimmers like fishes, squids, and motile crustaceans, can
escape from turbid conditions to nearby clear-water zones. On the contrary
sessile or fixed animals such as the fouling organisms (barnacles, hydroids
bryzoans, sea anemones, and corals) cannot dislodge themselves from their
substrata to avoid the ambient turbid conditions. If the occurrence of the
turbid layer is an intermittent phenomenon, the sessile animals tend to
reduce or cease their activities and then resume their normal activities
in favorable conditions. A special effort was made to study the responses
of fouling organisms on platform structures in the Louisiana shelf and
Timbalier Bay with reference to the presence of a "turbid layer" (ref. 10).
The growth of fouling communities was investigated by suspending test
panels in the Timbalier Bay, where drilling activity persisted during the
summer of 1973. The baywaters remained murky, with peak turbidity at
near-bottom depths. The fouling biomass reached peak levels as high as
p
3,800 g/m in the surface and upper layers. Significant reduction in
biomass and diversity of fouling was encountered in the turbid zone at
near-bottom depths (figure 5). The occurrence of juvenile arid empty bar-
nacles in the turbid layer suggests that the growth of these cirripped
crustaceans was hindered by the turbid conditions.
Turbidity variations were seen through the year with obvious seasonal
peaks in the Louisiana shelf. During the post-flood period in spring and
summer, 1973, a near-bottom turbid layer was detected on the Louisiana
shelf. In the summer the dissolved oxygen level in the turbid zone reache*
unusual minimum conditions of less than 15 percent saturation level (ref.
Evidently, prolonged existence of such a situation can cause stressful con
ditions to such sessile biota as the fouling community on the platform
legs. In situ underwater photographs reveal the presence of cloudy condi-
tions caused by the accumulation of suspended particles at near-bottom
depths (figure 6). The filter-feeding fouling animals are adversely
346
-------
gure 5. Photographs of submerged test panels (15cm x 5cm x 0.6cm) with
fouling growth which occurred over a period of the summer 1973 (May 4 -
August 4). These panels were exposed in the Timbalier Bay where drilling
activity persisted in the Gulf Drilling Field. Note the occurrence of
dense fouling in the surface panel and the reduction of fouling only to
few barnacles in the zone of turbidity-plume at the bottom.
347
-------
B
i F
Figure 6. An assemblage of in situ photographs of fouling growth on Exxon
Platform 54A from the surface (A) to increasing depths (B-E) down
to the bottom (F) at 50 feet. Note the turbidity plume over prevail-
ing fouling mat of hydroids at the near bottom depths (F). This plat-
form is located in the Louisiana Shelf south of Timbalier Bay.
348
-------
affected by the turbidity, and continuous stress can lead to mortality.
Our observations suggest that the influence of turbidity plumes caused by
the "nepheloid layer" or drilling mud is basically a physical phenomenon
that interferes with normal feeding and reproductive activity of sessile
organisms. However, this adverse effect is highly localized and this impact
is an intermittent event.
ACUTE AND CHRONIC EFFECTS OF OIL ON MARINE BIOTA
In the recent years, petroleum hydrocarbons have received considerable
ittention with reference to their levels in water, sediment, and important
larine animals in the food chain (ref. 12 and 13). Petroleum hydrocarbon
inters the marine environment through industrial or municipal effluents, and
y means of accidental spills during transportation or oil-well blowout,
atural seepage, transport of particles through atmosphere and in relatively
ery small quantities through the lubricating oil of the drilling mud.
The petroleum hydrocarbon level is extremely high in oil-polluted habi-
ats, as shown in the West Falmouth sediment samples (ref. 14). The hydro-
jrbon level in the Louisiana coastal waters tends to remain two or three
"ders of magnitude higher than in open gulf waters. The hydrocarbon levels
we been reported for marine plants and animals in recent studies (table 3).
le question is: What are the biological implications of hydrocarbon levels
i marine environment and biota? It is realized that the acute effects have
ire visibility and the chronic effects are often neglected and not clearly
iderstood. The need for developing studies to emphasize chronic (long-term)
fects of crude oil on marine biota was the substance of a recent confer-
ee (ref. 18).
The sublethal effects of oil require added investigations. Some petro-
jum fractions tend to block organs of chemoreception in certain marine
ustaceans (ref. 19). Petroleum hydrocarbons can influence reproductive
tivity of marine animals by masking the chemical activity of pheramones
at aid in the mating behavior: The physiological implications of petro-
um contamination deserve an increased research effort since our knowledge
limited as to the influence of buildup of hydrocarbons on essential bio-
jmical cycles involving complex enzymatic systems (ref. 20).
349
-------
Table 3. Petroleum hydrocarbon levels in water, sediment, plants,
and animals in marine environment (selected examples)
No.
1.
2.
3.
4.
5.
6.
7.
8.
Material
Sediment, West Falmouth Massachusetts
Sediment, Chedabueta Bay, Canada
Sediment, Narragansett Bay, Rhode Island
Water, Louisiana coast
Water, Gulf of Mexico
Plankton, Louisiana coast
Sargassum plant & animals, Sargasso Sea
Fish liver, Georges Bank, New England
Quantity
12,400 ppm
(dry wt.)
0-6.8 ppm
(dry wt.)
50-3560 ppm
(dry wt.)
0.63 mg/1
0.33 mg/1
100 ppm
(wet wt.)
1-34 ppm
(wet wt.)
519 ppm
(wet wt.)
Source
ref .
ref .
ref.
ref.
ref.
ref.
ref.
ref.
14
12
15
16
16
16
17
15
Chronic contamination by petroleum can occur not only in areas of
spills but also in the vicinity of refineries, ports, and drilling sites.
In the recent years, laboratory studies have been performed to monitor the
accumulation and release of petroleum hydrocarbons by marine clams, oysters
shrimps, and fishes. It has been shown that hydrocarbon is usually incor-
porated with lipids in gallbladder and nervous tissue which contain lipid-
rich membranes (ref. 21).
The effect of Louisiana crude oil in a dosage level as high, as 2,500
ppm on the respiration of oyster Crassostrea virginica was investigated in
the Offshore Ecology Investigations (ref. 22). The rate of respiration wa:
not altered to any significant level in the oysters exposed to prolonged
crude oil contamination (figure 7). This animal is a filter-feeding organ
and is known to accumulate hydrocarbon when exposed to low concentrations
fuel oil (ref. 23). These experimental oysters attained total hydrocarbon
levels as high as 335 ppm.
350
-------
' 50-r
40-|
o
o
o
, , , r
habitat filtered instant crude-oil
water water ocean treated
A. maximum
x: minimum
9 mean
O closed
jre 7. The oxygen uptake of oyster-biocoenoses in different experi-
lental media including habitat water, filtered seawater, synthetic sea-
/ater and crude-oil treated seawater (2,500 ppm). Salinity of all
ledia maintained at 32.8 parts per thousand (0/00) and temperature at
.7.5° +_ 0.5°C. Note the low respiration level when the oysters remain
n closed conditions.
351
-------
It must be emphasized that these organisms have the inherent ability
to release the accumulated hydrocarbons in favorable ambient conditions.
Recent research reveals that these contaminated animals can release 90 per-
cent of the accumulated hydrocarbons (ref. 24). Petroleum derived hydro-
carbons are seen in various marine animals at levels such as 100-200 ppm
for mollusks, 75-250 ppm for crustaceans, 75-250 ppm for fishes (ref. 25).
It is still not understood whether this level will be retained or magnified
in the food chain when transferred from one trophic level to another. It
is now necessary to ask the question: What physiological or metabolic
effects does the accumulated hydrocarbon or the chronic exposure of hydro-
carbon impose on the organism?
In the studies on oysters, metabolic inhibition was not encountered.
On the contrary, it was found that water soluble extracts of #2 fuel oil
lead to reduction in oxygen consumption of Mytil us edulis (ref. 26). In a
different study on mussels, increase in oxygen uptake after exposure to
certain concentration of oil was reported (ref. 27). These results do not
provide any definite answer on the effects of hydrocarbon on the physiologi
cal activities of these test animals. The most important aspect revolves
on the understanding of not only metabolic behavior, but the ability of
these test animals to grow, reproduce, and produce a progeny of normal or
altered physiological traits. This aspect requires long-term studies of
organisms from F, to F? generation under controlled conditions. There are
suggestions that the effect is essentially physical in nature because of
the apparent association of hydrocarbons with different biological membrane
(ref. 19). No doubt, standardized chronic studies should be conducted to
obtain answers to several unanswered questions on the effect of hydrocarbot
on the marine biota.
ACKNOWLEDGMENT
Research reported here was sponsored by the Gulf Universities Researc
Consortium.
352
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REFERENCES
E. A. Shinn, "Effects of Oil Field Brine, Drilling Mud, Cuttings and
Oil Platforms on the Offshore Environment," Marine Environmental
Implications of Offshore Oil and Gas Development in the Baltimore
Canyon Region, the Mid Atlantic Coast, (Proc. PCS Conference and
Workshop) 1974, pp. 243-255.
F. M. Daugherty, Jr., "Effects of Some Chemicals Used in Oil Well
Drilling On Marine Animals," Sewage and Industrial Wastes, Vol. 23
(1951), pp. 1282-1287.
C. H. Turner, J. G. Carlisle, and E. E. Ebert, "Offshore Oil Drilling,
Its Effects Upon the Marine Environment," in Environmental Impact
Statement PB-198979-F. Geological Survey, Washington, D. C.. California
Department of Fish and Game, Marine Resources Operations, 1971,
pp. 108-145.
National Academy of Sciences, Marine Environmental Quality, Suggested
Research Programs for Understanding Man's Effect on the Oceans, a, re-
port by Ocean Science Committee of NAS-NRC Ocean Affairs Board, 1971,
107 p.
H. J. M. Bowen, Trace Elements in Biochemistry, Academic Press, New
York, 1966, 241 p.
i
K. 0. Emery, W. L. Orr, and S. C. Rittenberg, "Nutrient Budget In The
Ocean," in Natural Sciences in Honor of Captain Allan Hancock, Univer-
sity of California Press, Los Angeles, 1955.
N. Murozumi, T. J. Chow, and C. Patterson, "Chemical Concentrations of
Pollutant Lead Aerosols, Terrestrial Dusts and Sea Salts in Greenland
and Antarctic Snow Strata," Geochim et Cosmochim. Acta, Vol. 33
(1969), pp. 1247-1294.
K. K. Bertine and E. D. Goldberg, "Fossil Fuel Combustion and the
Major Sedimentary Cycle," Science. Vol. 173 (1971), pp. 233-235.
M. Ewing and E. M. Thorndike, "Suspended Matter In Deep Ocean Water,"
Science, Vol. 147 (1965), pp. 1291-1294.
R. Y. George and P. J. Thomas, "Aspects of Fouling on Offshore Oil
Platforms In Louisiana Shelf In Relation To Environmental Impact,"
6.U.R.C. Offshore Ecology Investigations (unpublished MSS), 1975.
G. M. Griffin and B. J. Ripy, "Turbidity, Suspended Sediment Concen-
trations, Clay Minerology and the Origin of the Turbid Near-Bottom
Layer-Louisiana Shelf South of Timbalier Bay," 6.U.R.C. Offshore
Ecology Investigations, (unpublished reoort), 1974.
353
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12. V. Zitko and W. V. Carson, "The Characterization of Petroleum Oils
and Their Determination in the.Aquatic Environment," Tech. Rept. No. 217,
Fisheries Res. Board Canada, 1970.
13. M. Blumer, H. S. Sanders, J. F. Grassle, and 6. R. Hampson, "A Small Oil
Spill," Environment. Vol. 13, pp. 2-12.
14. M. Blumer, G. Souza, and J. Sas, "Hydrocarbon Pollution of Edible Shell-
fish By An Oil Spill," Marine Biol., Vol. 5 (1970), pp. 195-202.
15. J. Farrington, Ph.D. thesis, University of Rhode Island, Kingston
(unpublished), 1971.
16. E. D. Goldberg, "Baseline Studies of Pollutants in the Marine Environ-
ment and Research Recommendations," presented at the IDOE Baseline Con-
ference, May 24-26, New York, 1972.
17. K. Burns and J. Teal, "Hydrocarbon Incorporation Into the Salt Marsh
Ecosystem From the West Falmouth Oil Spill," Tech. Rept. Woods Hole
Oceanogr. Inst.. 1971, pp. 69-71.
18. Exxon Workshop Proceedings, "Research Needed To Determine Chronic
Effects of Oil On The Marine Environment," deliberation and recommen-
dations of a work-shop sponsored by Exxon Production Research Company,
Houston, Texas, November 4-6, 1974.
19. R. F. Lee, R. Sauerheber, and A. A. Benson, "Petroleum Hydrocarbons:
Uptake and Discharge By The Marine Mussel Mytilus edulis," Science,
Vol. 177, pp. 344-356.
20. G. M. Woodwell, "Effects of Pollution On The Structure and Physiology
of Ecosystems," Science, Vol. 168 (1970), pp. 429-433.
21. 0. 0. Stegeman, "Hydrocarbons In Shellfish Chronically Exposed To Low
Levels of Fuel Oil," in Pollution and Physiology of Marine Organisms.
J. F. Vernberg, ed., Academic Press, (in press), 1975.
22. R. Y. George, "Experimental Oil Spill Studies On Structure and Function
of Oyster Reef Communities In The Vicinity of Oil Platforms In Louisian
Coast," G.U.R.C. Offshore Ecology Investigations, (unpublished MSS),
1975.
23. J. J. Stegeman and J. M. Teal, "Accumulation, Release and Retention of
Hydrocarbons by the Oyster Crassostrea virginica," Mar. Biol.. Vol. 22
(1973), pp. 37-44.
24. J. W. Anderson and J. M. Neff, "Accumulation and Release of Petroleum
Hydrocarbons By Edible Marine Animals," Proc. of Inter. Mat. Symposium
on Recent Advances In The Assessment of the Health Effects of Environ-
mental Pollution, Paris, (in press), June 1975.
,354
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25. J. J. Stegeman and D. J. Sabo, "Uptake and Release of Petroleum Hydro-
carbons By Marine Organisms and Some Metabolic Implications," Proc.
DCS Conference and Workshop, Marine Environmental Implications of Off-
shore Oil and Gas Development In The Baltimore Canyon Region.of the
Mid-Atlantic Coast, 1974, pp. 339-350.
>6. A. Dunning and C. W. Major, "The Effect of Cold-Sea-Water Extracts of
Oil Fractions Upon the Blue Mussel, Mytilus edulis," in Pollution and
the Physiology of Marine Organisms, J. F. Vernberg, ed., Academic
Press, (in press), 1975.
7. E. S. Gilfillan, "Effect of Sea Water Extracts of Crude Oil On Carbon
Budget In Two Species of Mussels," Proc. Joint Conf. on Prevent, of Oil
Spills, American Petroleum Institute, Washington, D.C., 1973, pp. 691-
695.
DISCUSSION
1R. DONALD W. SOLANAS (U.S. Geological Survey, Metairie, Louisiana):
This is a comment, again, not a question.
Oil-base muds are not allowed to be used in the Gulf of Mexico
on the Federal leases. Oil-base muds can be used in isolated problem
conditions inside of a well. For instance, when a drill pipe is
stuck and they are trying to free it, they are permitted in that in-
stance to change their system into an oil-base system in order to
free the pipe.
No oil is allowed to be dropped into the Gulf of Mexico on drill
currings. Any drill cuttings that have any contaminants on them that
are harmful to marine life or to human life must be treated, to rid
them of oil or contaminants before they are allowed to be disposed of
off of the platforms.
R. JAMES B. JOHNSTON (Bureau of Land Management, New Orleans, Louisiana):
Dr. George, did you reoccupy your stations after drilling was completed
to see if there way any fouling growth or reoccurrence of fouling growth?
R._ GEORGE: Are you asking about reoccurrence of fouling growth?
R. JOHNSTON: Yes. What I mean is, when you removed the plates during the
drilling operation and the organisms had been destroyed, did you go
back after drilling had been completed and put the plates back down to
see if normal growth occurred? If so, how long did it take for normal
growth to occur?
355
-------
DR. GEORGE: This kind of inquiry we have not conducted yet, although we
have gone four times within a year to,do a survey of the fouling.
And, in fact, the fouling growth of certain organisms can indeed
occur even under turbid conditions.
MR. PAT H. WENNEKENS (Alaska Department of Fish & Game, Anchorage,
Alaska): I would like to get a perspective. What do you call oil?
How do you define it in your experiments? What do you define as
oil? I mean, total oils, solution, suspension?
DR. GEORGE: You know that oil--crude or diesel or fuel oil--is such a
complex mixture of various hydrocarbons with low molecular weight
and high molecular weight. In fact, there are a number of things I
have deliberately not touched upon with reference to the oil
definition because that is not my specialty. I have also not gone
into the various components of the drilling mud. So in my studies
and what I am reporting today, I am referring to the composite
effect of oil, as such, and not components of the oil or selected
hydrocarbons of the oil.
356
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ENVIRONMENTAL IMPLICATIONS OF SEDIMENT BULK ANALYSIS TECHNIQUES FOR TRACE
METALS IN OFFSHORE WELL-DRILLING OPERATIONS
J.G. Montalvo, Jr., Ph.D., and M.M. McKown*
Abstract
The pollution potent-Lai of trace metals in chemicals used in offshore
well-drilling operations can be monitored by measuring the trace metal
levels in bulk sedbottom sediment samples underlying well-drilling opera-
tions. Elevated trace metal levels in the surficial sediments during well-
drilling operations may indicate a pollution problem. However, in the
determination of trace metal levels in the sediments, the type of analysis
(partial or total) must be selected. A partial (differential) analysis
ietermines < 100 percent of a trace element in the sediment; a total anal-
ysis determines 100 percent. Trace elements are present in various
jhemical forms and locations in sediments. The chemically unstable forms
lay become bioavailable as a result of various physical, chemical., and
Biological interactions. Stable forms, such as that fraction of trace
letal in the inner layer positions of clay materials, are essentially un-
•vailable to biota. Total digestion might therefore "overestimate" the
-------
INTRODUCTION
One of the existing techniques for monitoring the pollution potential
of trace metals in chemicals used in offshore well-drilling operations is
to measure the metal levels in underlying seabottom sediments before and
during well-drilling operations. The trace metal levels in the surficial
sediments before drilling commences are indicative of background or base
line levels. Trace metal concentrations in the sediments obtained at
drilling sites should reflect base line metal levels plus the contributions,
if any, of trace metals derived from the well-drilling operations. Various
mechanisms may contribute to the transfer of a trace metal fraction from a
well-drilling operation to the receiving bottom sediment. Solid particu-
lates in drill cuttings and well-drilling fluids may be washed from the
derrick floor and walkways during rainfall and maintenance operations, and
consequently may migrate to the sediment under and around the rig site.
Spillages of drilling muds may occur while the mud is being pumped into
chemical containers aboard the offshore drilling rig or while the mud is
being pumped into a barge tied up alongside the rig. Discharges of drill
cuttings contaminated with oil well-drilling fluids may also contribute
to elevated trace metal levels in the surficial sediments around a rig
site.
If the trace metal levels in the sediments obtained during well
drilling operations are elevated above base line levels, further chemical
analyses of samples of oil well-drilling fluids, drill cuttings, paint
chips from the rigs, oil wipe samples, etc., are necessary before it can
be stated with any degree of accuracy that the increased metal levels
originated from chemical use in well-drilling operations.
In obtaining surficial sediment samples for trace metal analysis,
usually the volume or mass of sample obtained is quite large (i.e., bulk
analysis) and may contain up to one cubic foot of sample (ref. 1). In
the laboratory, a subsample of several hundred grams is taken from the
bulk sample and mixed well. The actual chemical analysis is performed on
1 to 4 grams of sample.
358
-------
The identification of trace metals that have in the past or are
currently being added to chemicals used in well-drilling operations
is no easy task due to the proprietary nature of the formulations.
Chemicals are used in drilling muds for various purposes: to control
pH, bacteria, corrosion, emulsion floes, foams, drilling-fluid circula-
tion, and reservoir-rock permeability. Although drilling fluids contain
primarily clays and weighting agents such as barium sulfate, a search of
the readily available patent literature through 1963 has revealed that
many different inorganic salts and compounds have been added to chemicals
used in well-drilling operations, as shown in the shaded areas of figure
1 (ref. 2). Furthermore, consideration only of the "heavy metal" suite
implies that the primary concern is with "trace metal" analysis and that
the alkali and alkaline earth metals are excluded (ref. 3). Several of
the latter are important from the pollution standpoint (beryllium, for
example). Therefore, the term "trace metal" as used here will refer to
low concentrations in the hydrosphere in the yg/1 range (ppb) of the
heavy metals such as Cr, Ni, Cu, Cd, Hg, Pb, As, etc., and alkaline
earth metals such as Be, etc.
Scientists charged with assessing the environmental impact of trace
metals in sediments in conjunction with well-drilling operations should
understand fully the environmental implications of such bulk analysis data
based on the merits and limitations of the analytical procedures. The
uere presence of a trace element constituent in the sediment during well-
irilling operations neither indicates nor predicts the nature and signifi-
:ance of adverse effects to the aquatic organism. A literature search on
this subject clearly demonstrates a lack of knowledge of the impact
lacute and chronic) of drilling fluid components on marine biota. There-
'ore, the trace metal data supplied should differentiate that fraction of
i given trace metal that is potentially bioavaiTable from that which is
lot in order to properly estimate environmental impact. An examination of
;he basic analytical procedures used for sediment bulk analysis for trace
etals in offshore well-drilling operations is reviewed here pertinent to
359
-------
environmental considerations. Since there are gaps in the basic
analytical procedures, and since the procedures are nonetheless current-
ly being applied, there appears to be justification for extensive
research.
THEORY OF BULK SEDIMENT ANALYSIS*
Before the control mechanisms for trace metals in surficial sedi-
ments associated with well-drilling operations are considered, chemical
parameters important in sediment bulk analysis for trace metals need to
be introduced. Table 1 shows several important parameters to be consider-
ed in developing the sampling program. Under socioeconomic considerations,
variables such as cost, rapidity, and simplicity are important. The cost
must not be prohibitive, otherwise an insufficient number of samples will
be included in the sampling program. Rapidity refers here to the sample
turnaround time. Simplicity implies a minimum number of step:; in the
analytical procedures since each sample manipulation increases the prob-
ability of contamination of the original sample. Consequently, trends in
trace metal analysis in sediments have been towards methods requiring
smaller sample sizes and minimum concentration procedures while retaining
Table 1. Parameters important in sediment bulk analysis
Socioeconomic
Cost
Rapidity
Simplicity
Chemical
Sensitivity
Precision
Accuracy
Environmental
Validity
*This paper is concerned with bulk sediment analysis in conjunction
with chemical use in offshore well-drilling operations; many of the
principles presented can be applied per se to other environmental applica-
tions of sediment bulk analysis of trace metals.
360
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high sensitivities (refs. 4,5). Pertinent chemical parameters are
sensitivity, precision, and accuracy. Background concentrations of
total trace metal levels in sediments and soils may vary from 0.03
to 100 ppm (refs. 6-8). The technique must adequately detect back-
ground levels of trace metals and must concurrently obtain a minimally
acceptable signal-to-noise ratio. The precision and accuracy of the
analytical method cannot be overemphasized and must also be optimized
since the number of samples required decreases with increase in pre-
cision and accuracy. Validity of the procedure refers to the proposed
definition of the fraction of trace metals in the sediment that is
bioavaiTable.
The processes of transport, distribution, and removal of marine
sediments are part of the biogeochemical cycle. Trace metals enter
natural water systems by normal weathering cf rocks or are added as a
result of man's activities. Whenever the rate of input of trace ele-
ments into offshore waters or surficial sediments exceeds the natural
rate of cycling, contamination with adverse ecological effects may re-
sult (ref. 9).
Potential perturbation of the biogeochemical cycle (of Rubin,
ref. 9) at specific points due to well-drilling operation is shown in
figure 2. A more detailed schematic of well-drilling operations in re-
lation to surficial bottom sediments is shown in figure 3. The water
column contains dissolved trace metals and other nonmetallic constituents,
suspended solids, and aquatic organisms. Particulate matter and dissolved
constituents from well-drilling operations may enter the hydrosphere,
inducing several complex reactions. A large number of phenomena will
2xert varying effects on the transfer of trace metals from the well-
Jrilling operations to the bottom sediments. The solid particles (drill
:uttings and oil well-drilling fluids) may drift downward through the
^ater column to the seabottom. During this transport of solid particles
n the hydrosphere, rapid ion-exchange processes may take place, effect-
ng movement of dissolved constituents from the water column to the
361
-------
Figure 1. Trace elements known to have been added to chemicals used in
well-drilling operations.
particles or vice versa. The interstitial water may also undergo rapid
exchange of chemical constituents with the surrounding hydrosphere. In
addition, suspended solids in the water column might be adsorbed onto
the solid particles from the well-drilling operations. The nature of
the solid particles could induce adsorption of dissolved constituents
from the surrounding environment.
362
-------
1_
IV
a.
Volcanic Emanations
V- ?
ID O
4-J 4)
•W Q
^ATMOSPHERE
Biological I
activity I
Evaporat ion
Well »
Drilling
Operations
I MAN H BIOSPHERE!
u
fD
Q.
Biological
activity
Condensat ion
Hydrothermal processes
Decay
HYDROSPHERE
Extrac-
tion
Enri chment
in
Hydrolyzates
Weathering
1 SEDIMENTSH-?
Volcanic
actLvi ty
Palingeni c
processes
Hetamorphism
and
Li thi f5 cation
Hydrothermal
enri chj
MOLTEN ROCK
nt
ure 2. Biogeochemical cycle of trace metals in nature with major in-
put points of man's activities during offshore well drilling operations
(from Rubin, ref. 7).
363
-------
364
-------
The solid particles may be adsorbed onto the surface of aquatic
organisms or be ingested as a source of food. The dissolved constit-
uents from the well-drilling operations will primarily be diluted to
seawater background levels.
Ultimately, the solid particles that have undergone variable
chemical, physical, and biological modifications will settle on the
surficial sediments around the rig site.
It is generally accepted that sediments are scavengers of trace
metals; suspended solids and aquatic organisms can also concentrate
trace metals (refs. 10-12). Therefore, trace metal "sinks" in the
marine environment include sediments, suspended solids, and aquatic
organisms. Trace metal levels in seawater are low due to the large
dilution factor and transfer of metal to the "sinks". Bottom sedi-
ments may be a sink for trace metals originating from chemicals used
in well-drilling operations. Sediments are relatively nontransitory
ia nature and are also known to serve as a habitat for a large and com-
plex community of biological organisms collectively known as the
benthic community. Therefore, sediment sampling and analysis should
be included in comprehensive plans to study environmental aspects as-
sociated with well-drilling operations.*t
In order to determine the effect of exposing surficial sediments
to chemicals associated with well-drilling operations, the chemical
form and location of the contaminants within the sediments must be known.
*E]rrfcnmem; of certain trace metals in surficial sediments may also
)ccur due to deposition of suspended matter from the water column not
issociated with drilling operations, by diffusion from deeper layers of
;he sediments, or by redistribution through hydrodynamic processes. It
s assumed in sediment studies during well-drilling operations, that
;hrough the use of control samples, any significant naturally occurring
inrichments will be negated.
tThere may also be variations in metal levels with depth of sedi-
lents; for this reason, sediment surficial samples are always taken at
he same depth.
365
-------
A trace metal contaminant or constituent associated with well-drilling
operations can exist in the natural environment, and these species may
vary from chemically unstable to extremely stable compounds or com-
plexes. The chemically unstable forms in the sediment layer, from the
sediment itself and from well-drilling contaminants mixed with the
natural sediment, are subject to active migration into the biological
food web and may range from highly ionizable species to soluble, readily
available organic complexes. On the other hand, the stable chemical
forms may range from highly insoluble inorganic precipitates, complexes,
compounds, and minerals to very nonreactive organic complexes. The
chemically stable and usually nonreactive forms constitute the major
fraction of most natural sediments and rarely enter into the biological
cycle. The chemical form of the trace metal contaminant can affect both
its relative toxicity and its availability to influence biological com-
munities.
The location of chemical constituents within the sediments also
determines the availability of these constituents to biological communi-
ties. The chemical constituents are located within the sediment in a
variety of positions. Physically, sediments are comprised primarily of
soil materials such as clays, silts, sands, etc., and interstitial water
(IW) (ref. 13). Chemically, sediment contains a majority of the chemical
elements.
Table 2 shows the more important chemical constituent locations in
sediments (refs. 13-23), trace metal forms, and bioavailability of the
trace metal forms in the various sediment locations. Chemically, con-
stituents in Phase (I)* and its associated trace metal forms have the
most immediate effect on changes in the water column; trace metal frac-
tions in Phase (II) may have a longer term effect on water quality by
*The assumption is made that chemically unstable forms in sediments
are potentially bioavailable. A sediment phase consists of a location
and the chemical forms in the location.
366
-------
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367
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acting as a reservoir for constituents that are removed from the IW.
Phase (III) trace metals may be released to the water phase during
reducing conditions. Phase IV trace metal materials
may be incorporated into the food web or migrate to the aqueous phase
with potential for long-term effects depending on the nature and
degree of microbial degradation. Phase IV materials might also act
as scavengers of some trace metals. Phase V materials are considered
biologically inert.
Various mechanisms have been suggested whereby trace metals in
sediments may interact with biota: (a) particulate ingestion of sedi-
ment matter suspended above the seabottom, (b) particulate ingestion in
the sediment layer, (c) ingestion of food material in and above the sedi-
ment layer, (d) complexation by biological chelating agents,, (e) incor-
poration into physiological systems, and (f) ion exchange and sorption
on tissues or membrane surfaces (refs. 24-26). All of these mechanisms
imply a degree of bioavailability of the various trace metal forms in a
sediment. Clearly, an inert trace metal form in a sediment might be
expected to pass unchanged through the digestive tracts of biota; for
example, trace metals within insoluble mineral crystalline lattices.
The analytical chemist performing the trace metal analysis of sur-
ficial sediments in conjunction with the environmental aspects of
chemical use in well-drilling operations must determine whether a total
analysis for specific trace metals is desirable. A partial (differentia'
analysis is intended to determine < 100 percent of a trace element in th<
sediment; a total analysis determines 100 percent of a trace element in
a sediment.
It is necessary to explore the environmental significance of
partial vs. total analysis data given to biologists. Assume that only
the five phases of trace metals in a sediment, as shown in table 2, are
present in significant concentrations. Let the total concentration of
a given trace metal (M) in Phase I be represented as,
368
-------
11
£ (Phase I)r = (Phase I)1 + (Phase I)2 ... (Phase I)n (1)
where each (Phase I) term represents the concentration of a particular
form of trace metal M in Phase I location. The equation representing
the total concentration of trace metal M in all five phases of the
sediment is given by MT,
n1 n"
MT = T (Phase IL + £ (Phase II) + £ (Phase III
' r = i r r = 1 r = 1
)r (2)
n 111 n ''''
+ £ (Phase IVL + £ (Phase V)
r = 1 r r = 1
Let the concentration of chemically unstable trace metal (M) in
'hase I be represented as,
n
£ (Phase I)'. = (Phase I)j + (Phase I)' + ... (Phase I)1 (3)
s _ 1 a i £. n
here each (Phase I)1 term represents the concentration of a particular
orm of trace metal M in Phase I that is bioavailable. The total concen-
ration of bioavailable trace metal M in all five phases of the sediment
s therefore given by MB,
n n'V
MB = £( (Phase I)' + ... £ (Phase V)' (4)
s = 1 s = 1
369
-------
The fractional limits of bioavailable trace metal Mn in the sediment in
D
relation to My can be given by:
0< , < < 1 (5
My
or
MR
0« — < 1, (I
MT
depending upon the identity of M, etc.
If MB/My approaches 1, then the analyst is justified in performing
a total analysis. On the other hand, if MB/My is significantly less than
one, then the analyst will "overestimate" the value of an element that is
bioactive if a total analysis is performed. Values obtained for MB/MT wil
depend on the extraction media employed for partial analysis. For example
values of Mg/My of < 0.5 were generally obtained using dilute HN03-HC1;
HJ3,,; and HOAc with NHJDH • HC1/H202 for partial analysis of sediment from
three geographical areas (table 3).
The environmental implications of sediment bulk analysis techniques
for trace metals in offshore well-drilling operations are schematically
represented in table 4. Clearly, if the total metal level increases re-
lative to the control values (the metal levels of interest), the unstable
forms which may become bioavailable as a result, of various physical,
chemical, and biological interactions, might be "overestimated." A pol-
lution problem would thus be falsely predicted. In such a case the true
interpretation of the data is possible only with partial analysis. Con-
versely, the total metal level might remain essentially the same but the
fraction of an unstable form could significantly increase, in which case
environmental impact will not be revealed. Currently some environmental-
ists tend to request "total" values for an element on the assumption that
all the trace metal in the sediment sample is bioavailable.
370
-------
Table 3. Reported values for MB/MT in sediments
Partial digestion Trace Mo/My
Sediment source technique metal (%)
Offshore
southwest Florida
Puget Sound
Saanich Inlet,
British Columbia
Leach with hot
HN03-HCL, 0.1 4M
and 1.09 M,
respectively
H2°2
Oxalate
Citrate-dithionite-
bi carbonate
25% HOAc plus
0.25M NH2OH'HC1;
separate residue,
leach with 30%
Mo
2 2
Cu
Cr
Fe
As
Sb
As
Sb
As
Sb
Co
Mo
Li
Sr
Fe
Mn
Ni
Cu
Zn
12
42
75
<10
<10
66
48
34
31
15
44
18
29
11
22
21
58
40
Ref.
27
28
29
The total trace metal content in sediment samples, 100 percent,
in be determined using emission spectrography, X-ray fluorescence, or
utron activation analysis; it can also be determined after complete
gestion or fusion.
In partial or differential analysis, the sediment sample digestion
extraction technique is designed in such a manner as to remove Phase
- Phase IV elements from the sediment residue. Many different proce-
res have been employed in partial analysis (refs. 26,30,31,32), as
own in table 5. Certain experiments, described in the following sec-
an, were conducted in this laboratory to show that the sediment trace
tal results obtained from different types of partial digestion attack
/e valuable information about the nature of the unstable chemical forms
371
-------
Table 4. Environmental implications of sediment bulk analysis
techniques for trace metals in offshore well-drilling
operations based on partial vs. total analysis
Total analysis,
metal levels
relative to con-
trol values (CV):
Most probable
interpretation
Partial analysis,
metal levels
relative to con-
trol values (CV):
>cv
=cv
Insufficient sediment bioassay studies have been completed to date
to indicate unequivocally all of the chemically unstable forms of trace
metals in sediments which are bioavaiTable and which hence may act as
potential pollutants (ref. 14). A major problem in conducting and inter-
preting long-term bioassay tests of offshore sediments is caused by the
differences in the hydrodynamics of the test conditions as compared to
the hydrodynamics in deep or offshore waters (ref. 33). A controlling
factor influencing the availability of trace metals to biota in deep
372
-------
Table 5. Partial digestion techniques reported in the literature
Technique
Composition of digestion mixture
Cold extraction
Hot extractions
Fusions
Others
Buffers; variety of dilute acids (e.g.,
nitric, hydrochloric, acetic, EDTA, etc.);
mixtures of weak acids plus reducing agents.
An individual acid (e.g., HN03) or a mixture
of acids (e.g., aqua regia, nitric-perchloric,
etc.); hydrogen peroxide.
Acid (K2$207 or KHS04, etc.); alkaline (Na2C03>
KN03, Na202, and NaOH, K C03> and
Dry ashing.
, etc.)
waters is the hydrodynamics of the mixing of the sediments and the
interstitial water associated with the sediments and the overlying
waters.
Thus, bulk analysis of the sediments for trace metals should
supplement greatly the bioassay test results. But the chemist per-
forming the analysis must realize that bottom sediments are not
simply a wet sample of soil, since soil and bottom sediments are formed
under different, conditions (ref. 23). Bottom sediments are normally
subject to reducing conditions except at the zone of contact with
the aqueous phase, whereas soils are usually formed under aerobic
conditions. Further, sediments contain higher amounts of organic
matter than soils and also are not subject to the leaching processes
as are soils. Finally, techniques for trace metals in terrestrial
soils were developed for geochemical exploration and studying avail-
ability of the metals by plants. Extrapolation of these soil tech-
niques to sediments for environmental purposes may not be entirely
i/alid.
373
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EXAMPLE OF A PARTIAL ANALYSIS TECHNIQUE
Table 6 shows the current EPA (region IV) recommended procedure
for partial digestion of trace metals in sediments. The procedure is
simplification of a previously recommended multistep bulk sediment
analysis procedure (ref. 1). The final concentrations of HN03 and HC1
after addition of the water are 0.14M and 1.09M, respectively. This
acid mixture is mildly acidic and also could be considered a mild
oxidant depending on the temperature. That fraction of a trace metal
in a sediment which might be expected to be leached from the sample in
this solution would include trace metal in the following forms: solu-
ble salts, absorbed, an iron-manganese phase, sulfides, and organics
(ref. 30).
No experiments have been reported in the environmental literature
where a partial digestion technique employing a given HC1-HN03 mixture
to leach trace elements from sediments has been studied as
-------
in Gulf South Research Institute laboratories. Separate portions of
sediment samples obtained from a well-mixed bulk sediment sample* were
digested at 35°, 65°, or 95°, for periods ranging from 15 to 180 minutes
and analyzed for Cu and Ba (figures 4 and 5) and Cd, Pb, Cr, Fe, and V.
A reflux condenser was used at 95°C to prevent loss of water or acid.
The digestion process was quenched by immediate filtration, and extracts
were analyzed by atomic absorption spectrometry.
The general shape of the kinetic curves in figures 4 and 5 illus-
trates the variables involved in partial analytical techniques for
trace metals in sediments. The recommended 15-min digestion period is
apparently sufficient for extracting some of the metals but not all.
The shapes of both curves are similar; the plateaus indicate when a
given chemically unstable form(s) is removed from the sediment. The
digestion temperatures were varied in increments of 30°C (i.e., 35°->-
65°+ 95°). Striking differences are apparent in the dependence of
the level of metal recovered as a function of temperature; for Cu, at
least three different chemically unstable trace metal forms in the
sediment are suggested (ref. 25). On the other hand, Ba does not show
a dependence of metal recovered as a function of temperature in the
range 33° to 95°C; therefore, at least one unstable form of metal is
suggested (ref. 27). The data is summarized in table 7.
A full interpretation of the kinetic data is beyond the scope of
this paper, but comments directed towards a generalized explanation
will be given for Cu and Ba. The Cu recovered at 35eC could represent
the Cu in the interstitial water and the loosely absorbed Cu (hence total
af two different forms); the Cu recovered at 65°C may represent the sul-
fide Cu whereas at 95°C probably the organic Cu is being obtained. The
Collected from a drainage ditch (NASA/NSTL, Bay St. Louis, Missis-
sippi).
375
-------
(uidd) u
376
-------
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C9
1
1
1
1
1
1
1
1
J U O
o o
n m in
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00
o
VD
O
-j
r-4
O
CM
I |_
CM CM
CM
CM
O
CM
00
O)
O
00
I—
IO
CD
o
o
o
o
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C
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3 •!-
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10 CD
S- CO
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E
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5
2!
3
377
-------
Table 7. Relative recoveries of trace metals and number of trace
metal "forms" detected after 3 hours of partial diges-
tion as a function of digestion at three different
temperatures
Recoveries relative to 35°C
Postulated
minimum number of
Trace element
Cu
Cd
Pb
Cr
Fe
Ba
V
35°C
1
1
1
1
1
1
1
.00
.00
.00
.00
.00
.00
.00
65°C
1
1
1
2
1
0
0
.60
.00
.14
.48
.51
.97
.90
95°C
3.
0.
1.
2.
2.
0.
2.
52
98
16
96
24
89
42
trace metal forms
in the sediment
3
1
2
3
3
1
2
Table 8. Dependent variables in partial analytical
techniques for trace metals in sediments
Digestion:
Temperature
Time
Solvent composition
Sediment mesh size
Sediment lithology
lack of further recovery of Ba at 65° and 95°C is not surprising in
view of the common association of Ba with chemically unstable car-
bonates (ref. 27).
Other experiments have been performed in this laboratory to
identify the variables involved in partial analytical techniques and
their dependence on several trace metal levels recovered and, there-
fore, the forms of metal recovered. The variables which have been
identified to date which affect the metal recovered are summarized in
table 8. The need to standardize partial analysis techniques should
be apparent.
378
-------
SUMMARY
The rationale for sediment bulk analysis techniques to monitor
trace metal pollution from the chemicals used in well-drilling opera-
tions was presented for offshore or deep-water drilling. Many of the
principles developed can be applied to other environmental applica-
tions requiring sediment bulk analysis for trace metals.
Trace metal contaminants from the chemicals used in the well-drill-
ing operations may perturb the marine sediments in the biogeochemical
cycle, which can be revealed by chemical analysis for trace metal levels.
However, in the determination of trace metal levels in the sediments,
the type of analysis (partial or total) must be carefully considered.
The results of a kinetic study of a recently recommended EPA partial
digestion technique for trace metals in sediments is presented,for Cu and
Ba analysis. By simple variation of the sediment digestion temperature
in the partial analysis procedure, up to three different chemically un-
stable trace metal forms that are potentially bioavaiTable were postulated
for various metals. Important variables in the partial analytical tech-
niques for trace metals in sediments were also identified: composition
of digestion mixture, temperature and time of digestion, sediment mesh
size, and sediment lithology.
The total concentration of chemically unstable forms of a trace
letal in the sediment was assumed potentially bioavailable (Mp) and is
•elated to the total concentration of the metal in the sediment (My) by
MR
0 < —< 1 .
MT
alues for Mg/Mj, while dependent on a specific partial analysis tech-
ique, appear in general to be <0.5. The environmental implications of
ediment partial vs. total analysis in conjunction with chemical use in
ell-drilling operations suggests that the partial and not total analysis
schnique be utilized in the environmental survey (ref.35).
There are obvious needs to identify the trace elements present in
le modern chemicals used in well-drilling operations, to standardize
379
-------
Table 9. Need for improved sediment bulk analysis methodology for
environmental monitoring and control in offshore well-
drilling operations
Needs
Suggested approach
Comments
3.
Identify trace
metals in chemi-
cal use in modern
well-drill ing
operations
Standardize par-
tial analysis tech-
niques from exist-
ing technology
Develop more op-
timized partial
analysis procedure
leading to im-
proved specificity
in quantitating
various forms of
trace metals in
sediments for fu-
ture standardi-
zation
Qualitative multi-
element analysis
of commercial chem-
icals followed by
quantitative
analysis
Should look to EPA
for recommendations
since this regula-
tory agency has most
experience in the
field
Solvent extraction
techniques; differ-
ential thermal analy-
sis; separate mag-
netic and nonmagnetic
fractions; mineralogy
studies; electron
microprobe
This may necessitate
ongoing studies
Immediate need for
standardization in
offshore areas cur-
rently undergoing
well-drilling oper-
ations; standardi-
zation efforts al-
ready underway
Direct application
in sediment bioas-
says and in modeling
biopathways
partial analysis techniques to cope with current offshore studies, and •
develop better partial techniques for future standardization. Reasonab
specific partial analysis techniques for identifying and quantitating
the various chemically unstable forms of trace elements In sediments co
have direct impact on sediment bioassay studies. Table 9 summarizes, f
ease of referral, suggested areas of research to improve sediment bulk
analysis methodology for environmental control and monitoring of offshe
well-drilling operations.
380
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REFERENCES
1. Chemistry Laboratory Manual, Bottom Sediments, compiled by Great
Lakes Region Committee on Analytical Methods, EPA, FWQA, pp. 18-20,
December 1969.
2. W. F. Rogers, Composition and Properties of Oil Well-Drilling
Fluids, Gulf Publishing Co., Houston, Texas, 3rd Edition, ppT 334,
679-806, 1963.
3. D. C. Burrell, Atomic Spectrpmetric Analysis of Heavy-Metal Pollu-
tants in Water, Ann Arbor Science, Ann Arbor, Michigan, p. 20, 1974.
4. M. M. McKown, J. G. Montalvo, Jr., and D. V. Brady, "Progress Report I
Trace Metal Program in Support of BLM MAFLA Investigation1', Gulf
South Research Institute, Prepared for BLM, Contract No. 08550-CT4-15,
January 1975.
5. M. M. McKown and J. G. Montalvo, Jr., "Progress Report II: Trace
Metal Program in Support of BLMpjAFLA Investigation", Gulf South
Research Institute, Prepared for BLM, Contract No. 08550-CT4-15,
April 1975.
6. P. C. Singer, Trace Metals and Metal Organic Interactions in Natural
Waters, Ann Arbor Science, Ann Arbor, Mich., pp. 98-100, 1974.
7. A. A. Levinson, Introduction to Exploration Geochemistry, Applied
Publishing Ltd., Calgary, pp. 43-44, 1974.
3. A. J. Rubin, Aqueous-Environmental Chemistry of Metals, Ann Arbor
Science, Ann Arbor, Mich., p. 82, 1974.
). A. J. Rubin, ref. 8, p. 130.
0. A. J. Rubin, ref. 8, pp. 109,, 137.
1. J. F. Kopp and R. C. Kroner, Trace Metals in Waters of the United
States, FWPCA, Cincinnati, Ohio, 1970.
2. D. Z. Piper and G. G. Goles, "Determination of Trace Elements in
Sea Water by Neutron Activation Analysis," Anal. Chim. Acta, Vol.
47 (1969), p. 560.
3. B. H. Byrnes, D. R. Keeney, and D. A. Graetz, "Release of Ammonium-N
from Sediments to Waters," Proceedings, 15th Conference, Great Lakes
Res.. Vol. 15 (1972), p. 249.
381
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14. 0. W. Keeley and R. M. Engler, "Discussion of Regulatory Criteria
for Ocean Disposal of Dredged Materials: Elutriate Test Rationale
and Implication Guidelines," U.S. Army Waterways Experiment Sta-
tion, Misc. Paper D-74-14, Vicksburg, Miss., 1974.
15. C. E. Boyd, "Influence of Organic Matter on Some Characteristics
of Aquatic Soils," Hydrobiologia. Vol. 36 (1970), pp. 17-21.
16. R. R. Books, B. J. Presley, and I. R. Kaplan, "Trace Elements in
the Interstitial Waters of Marine Sediments," Geochem et Cosmochim
Acta, Vol. 32, (1968), pp. 397-414.
17. C. H. Mortimer, "Chemical Exchanges Between Sediments and Water in
the Great Lakes - Specifications on Probable Regulatory Mechanisms,"
Limnology and Oceanography , Vol. 16 (1971), pp. 387-404.
18. C. H. Mortimer, "The Exchange of Dissolved Substances Between Mud
and Water in Lakes," Ecology, Vol. 29 (1941), pp. 280-329.
19. C. H. Mortimer, ref. 18, Vol. 30 (1942), pp. 147-201.
20. P. Duchart, S. E. Calvert, and N. B. Price, "Distribution of Trace
Metals in the Pore Waters of Shallow Water Marine Sediments,"
Limnology and Oceanography, Vol. 18 (1972), pp. 605-610.
21. E. Gorham and D. 0. Swaine, "The Influence of Oxidating and Reducing
Conditions upon the Distribution of Some Elements in Lake Sediments,"
Limnology and Oceanography, Vol. 10 (1975), pp. 268-269.
22. E. A. Oenne, "Controls on Mn, Fr, Co, Ni , Cu, and Zn Concentrations
in Soils and Water: The Significant Role of Hydrous Mn and Fe Oxides,'
Trace Inorganics in Water, American Chemical Society Advances in Chem-
istry Series 73 rTJasFTT^.C., pp. 337-387, 1968.
23. S. J. Toth and A. N. Ott, "Characterization of Bottom Sediments:
Cation Exchange Capacity and Exchangeable Cation Status," Environ-
mental Science and Technology. Vol. 4 (1970), pp. 935-939.
24. D. F. Martin, Marine Chemistry. Vol. 2, Marcel Dekker, New York, 1970.
25. A. 0. Rubin, ref. 8, p. 67.
-26. D. M. Hirst, "The Geochemistry of Modern Sediments from the Gulf of
Paria-II, the Location and Distribution of Trace Elements," Geochem.
Cosmochi Acta, Vol. 26 (1962), pp. 1147-87.
27. 0. G. Montalvo, Jr., and M, M. McKown, unpublished data.
382
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28. E. A. Crecelius, M. H. Bother, and R. Carpenter, "Geochemistries of
Arsenic, Antimony, Mercury, and Related Elements in Sediments of
Pudget Sound," Environmental Science and Technology, Vol. 9
(1975), pp. 325-33.
29. B. J. Presley, Y. Kolodny, A. Nissenbaum, and I. K. Kaplan, "Early
Diagnosis in a Reducing Fjord, Saanich Inlet, British Columbia-II.
Trace Element Distribution in Interstitial Water and Sediment",
Geochimica et Cosmochimica Acta, Vol. 36 (1972), pp. 1073-90.
30. A. A. Levinson, ref, 7, pp. 245-252.
31. P. M. D. Bradshaw, D. R. Clews, and J. L. Walker, A Series of
Seven Articles Reprinted from Mining in Canada and Canadian Mining
Journal, Exploration Geochemistry, 1972.
32. A. J. Rubin, ref. 8, p. 84.
33. G. Fred Lee, "Chemical Aspects of Bioassay Techniques for Estab-
lishing Water Quality Criteria," Water Research, Vol. 7 (1973),
pp. 1525-46.
W. M. M. McKown and J. G. Montalvo, Jr., "Final Report: Trace Metal
Program in Support of BLM MAFLA Investigation," Gulf South Research
Institute, Prepared for BLM, Contract No. 08550-CT4-15, August 1975.
35. A. Preston, D. F. Jefferies, J. W. R. Dutton, B. R. Harvey, and
A. K. Steele, Environ. Poll.. Vol. 3 (1972), p. 69.
HSCUSSION
IR. JACK W. ANDERSON (Texas A&M University, College Station, Texas):
You may be aware that the Corps of Engineers is concerned with this
problem, also, with their dredge material disposal, and that they
recently funded a contract that we are working on to look at the
availability of heavy metals to benthic organisms. Now, this exact
type of scheme of separation, and so foith, will be used.
R. ARTHUR J. HOROWITZ (Texas A&M University, College Station, Texas):
I have got a question. First of all, you mentioned that you feel
that lattice supplemental are not likely to be taken up by an
organism once it has been eaten: you expect it to be excretable.
And my question is, how sure are you of this? What are you using
to check it?
..MONTALVO: Could you rephrase your question?
. HOROWITZ: Let us assume that you have got a polychaete living in1 the
383
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mud and it is chewing it up; essentially, it is going in one end
and out the other. How sure are you that there is nothing being
taken out?
DR. MONTALVO: Okay. We have done some experiments whereby a certain
fraction of a metal in the sediment will not be removed by re-
flexing that sediment with concentrated nitric acid. Now, if that
certain fraction of metal is not removed from the sediment with
concentrated nitric acid, I hardly think that the pH in the dig-
estive tract of an organism, or the enzymes, is capable of break-
ing that sediment apart and actually removing these inner layer
trace metal ions. I just cannot visualize that.
If we flux our sample for, say, 3 hours with concentrated
nitric acid and the metal is not removed, it is hard to convince
me that the biota, which will have undoubtedly a mild acidity in
the animal's digestive tract, can do this.
MR. HARWOOD: Oust out of curiosity, have you tried to reproduce those
results? In other words, have you taken the sediment and reflux-
ed it once and taken another aliquat and refluxed it again? How
reproducible were the results?
DR. MONTALVO: If we get into a discussion of the experimental procedure
of trying to extract trace metals from sediments, one has to remem-
ber that whenever we are doing this, one of the dependent parameters
in the study is time. That is to say that one has to perform a
kinetic study and plot the metal level recovered versus the time.
And in doing so, you will, in every instance, obtain a plateau. And
all you have to do is to increase or to do your digestions or ex-
tractions for a sufficiently long enough period of time until you
are on the plateau of your curve. If you do that, you will get
repeatable results. If you do not do that and you stop your diges-
tion while you are in the rising part of the curve, you will get da
of very poor precision and accuracy.
DR. ELLIOT S. HARRIS (NIOSH-Cincinnati, Ohio): I think it is all well
and good to look at the metals in the sediment. But what we are
interested in there is the effect on the food chain and how these
metals are going to move through that food chain.
384
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Have you looked at any of the fixed biota and seen whether
they contain that which you are concerned with?
DR. MONTALVO: We are also involved in a study of this nature, but
I hesitate to speculate on the results of that data since it is
an ongoing study and it has not reached that stage yet.
385
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The Offshore Ecology Investigation
Slide Presentation
Joe W. Tyson*
Public awareness of the conflict existing between energy production
and environmental protection has resulted in a need for the public to know
and understand the impact of man's activity on his environment. The Off-
shore Ecology Investigation came about as a consequence of this serious
need and asks this simple question: "What is the measurable impact of
drilling for oil, and later producing 1t, on the estuarine and marine
snvironment in our Nation's greatest offshore oil production region, the
Louisiana Shelf?" (See figure 1.) To answer the deceptively simple
question, the Gulf Universities Research Consortium has coordinated a
5-year Offshore Ecology Investigation.
A Project Planning Council was named and a diverse group of
miversity, government, and industrial scientists agreed on the major
iutlines of a scientific program to provide an answer to the question
see figures 2 and 3). After the general guidelines were formulated,
he Gulf Universities Research Consortium selected 23 principal investi-
ator scientists to participate. They represented 13 of the educational
nd nonprofit institutions in the Gulf States (see figure 4). The
cientists and their institutions who provided the several parts of the
omplete program are acknowledged, as are the members of the Agency Advisory
ommittee named to consider the sampling methodologies and analytical
rocedures (see figure 5).
Biological, chemical, and physical experiments were defined and sites
2re selected in Timbalier Bay, Louisiana, and offshore to about 100 feet
F water (shaded in darker gray). (See figure 6.) Sampling stations
ijacent to drilling or production and control sample stations (where there
*Senior Scientist for Ecology, Gulf Universities Research Consortium,
tlveston, Texas.
387
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had never been oil drilling) are within the same region, thus making it
possible to do valid comparative studies. All sampling stations are
located far enough from the Mississippi River mouth to uniformly
minimize, but not eliminate, its impact. As is seen in figure 7, a
very-high-altitude National Aeronautics and Space Administration view,
tremendous quantities of sediments and other materials leave this river
to flow in a general westward direction with the Western Loop Current
during most of the year.
A low-elevation aerial oblique view of the region, in this artist's
illustration (see figure 8), indicates the variable water depth and the
changing geography found as one moves from the outer shelf onto the
beach and into the bay. Platforms, both for drilling and production,
are quite dense in this region between Timbalier Island and Casse-Tete
Island (see figure 9).
Figure 10 shows a platform just west of Philo Brice Island in Timba-
lier Bay, which was one of the intensive sampling sites with sample
stations being located in a radial pattern outward from the platform.
The density of platforms and wells offshore is somewhat less, al-
though recent figures indicate there are 2,650 platforms in the entire
northern Gulf of Mexico (see figure 11). All of which is to say, there
are hydrocarbons in this environment—whether from natural seeps, acciden-
tal spills, or as a result of overboard discharge of brine containing
a few parts per million of petroleum hydrocarbons, or from other sources
such as city wastes, seagoing ships, sports boats, or decay of plants and
animals.
A working platform makes many contributions to the environment in
addition to its physical presence (see figure 14). You will note that
among the potential contributions it makes are nutrient (food) materials
from treated sewage, brine containing small amounts of petroleum hydro-
carbons, trace elements from corrosion protection devices, and other
kinds of compounds, as well as a place for plants and animals to attach
themselves. The sampling program was designed to determine which of them
were present and, if so, their locations and concentrations.
388
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The scientists therefore visited the platform and control stations,
as indicated by the sample station map in figure 15. Timbalier Bay had
224 stations, and there were 115 stations offshore as well as along
transects or lines drawn from the platform and control sites to shore-
based stations, enough to allow gradients to be established if they
existed. All field equipment was regularly calibrated against available
appropriate standards (both external and internal) to allow comparative
correlations to be made from one field trip to the next. Investigators
made four, seasonal, 8- to 10-day trips each year for the 2 years. There
were many other shorter trips by individual scientists. All of the
sampling stations were occupied on each seasonal trip, as well as at
other times by either the 23 scientists or some of the more than 30
graduate students involved in the program—many of whom were diving
scientists.
The major components of the Gulf of Mexico ecosystem are the phyto-
plankton, the mainly microscopic floating plants. (See figure 16.)
These are the primary producers of the sea; they convert carbon dioxide,
minerals, and water to starches and sugars, protoplasm, and other chemical
compounds by photosynthesis. They are eaten by the next level in the
food web, the zooplankton, which include numerous types of mainly micro-
scopic animals. The nekton are all of those free-swimming animals found
in the environment, such as fishes and squid. We will see the importance
of bacteria later. The benthos are the bottom dwellers, some attached,
some capable of burrowing in the sediments.
Nearly all aspects of the food cycle and ecosystem were studied in
the Offshore Ecology Investigation. Certainly, all of the major groups
3f plants and animals were studied, but not in the same detail. Some
jf the aspects studied were the total mass and diversity of living
laterlal present. This was studied because it seems generally true that
ihe greater the number of different organisms in the environment, the
ireater ecological health it enjoys and the more stable the environment.
"he distributions of living plants and animals were carefully measured
n terms of where they were found. The results of these investigations
389
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showed that there were no differences that could be soley attributed
to geographical location except for populations living on platform legs.
Because all life forms are sensitive to their environment, the seasonal
changes in both temperature and chemical nature wer-e studied in detail.
By the end of the study, the project biologists were able to show that
these seasonal variations were far more significant than any other
variations.
The largest numbers and volumes of samples collected were water
samples taken at the surface, at mid-depths and very near bottom to
determine oceanographic information such as salinity, temperature, and
nutrient and trace element chemistry. Fractions were analyzed for total
carbon and organic carbon. For these kinds of analyses, relatively small
volumes of water are required; allowing utilization of the Sampling
Bottle shown.
Large volume samples were required for the determination of the
specific classes of hydrocarbons in the water mass. Therefore, this
large volume sampler shown in figure 19 was used to obtain sufficient
water to permit the detection and characterization of hydrocarbons.
Plankton nets were towed in order that the mainly microscopic
floating plant and animal life could be caught and studied (see figure
20). The scientists needed to know, as a function of carefully measured
volume, the nature of the living things floating in the water, their
diversity, their effective weight by species, and their hydrocarbon type
and amounts. Figure 21 shows a typical concentrated plankton catch,
including both plants and animals trapped by the net.
The bottom grab sampler shown in figure 22 takes approximately 1/3
of a cubic yard of sediment each time it is lowered. These sediment
samples were required for sediment analysis and to catch the bottom
dwelling plants and animals (benthos) living there. The sample is
brought back aboard the research vessel where the material is divided ar
used for study by the biologists and chemists and by geologists determir
ing the nature of the sediments. Some bottom grab samples as well as
short sediment cores were collected by divers (see figure 23). Evidence
of drill cuttings and muds were sought at all sampling stations but wen
390
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difficult to differentiate from the normal muds, silts, and sands of
the bay and shelf (see figure 24). Where they were identified near
a platform by divers, they could not be associated with an adverse
impact.
It was mentioned earlier that water samples were taken to allow
for the determination of dissolved mineral nutrients (see figure 25).
Nutrients enter the living processes in plants and animals and are,
therefore, often early affected by materials introduced into the
environment. Here, onboard scientists at the sampling station are
splitting the water samples for chemical analysis.
Crude oil will float for a while at the surface, forming a
filmy sheen. To determine the quantities and fate of these petroleum
hydrocarbons, it was necessary to sample the thin floating film. Project
scientists developed the sampler shown in figure 26, which would allow
them to take a reproducible standard sample and relate the results of
chemical analyses to the volume and area that had been sampled. Facing
downward is a Teflon disc to whidi the surface film naturally adhered.
The sampler is lifted aboard the research vessel, where the ad-
sorbed oil and other materials were carefully washed into previously
cleaned containers (see figure 27). Scrupulous care is taken to insure
that no contamination (such as lubricating oils) gets into the sample
during the transfer process. These samples, as well as the large-volume
samples, were frozen or otherwise preserved and returned to laborator-
ies—along with samples of fuels and lubricants used aboard the boats—for
subsequent comparative studies.
In university laboratories, the biological samples were positively
identified, counted, and weighed so that comparisons were possible from
place to place on a seasonal basis (see figure 28). Some of the lab-
oratory activities required highly sophisticated and massive equipment,
such as the view of a hydrocarbon chemistry laboratory and gas chro-
matograph and mass spectrometer equipment linked to computers (see figure
29). Such a link makes comparisons possible between samples collected
during the project and calibrated standards, and permits identification
of separate compounds present. Furthermore, selected animals and some
391
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uppermost sediment samples were analyzed to determine their hydro-
carbon content.
The typical mass spectrometer tracing in figure 30 shows the
hexanesoluble fractions, which are chemical compounds not only found in
crude oils but also naturally produced by plants and animals. The peaks
in the tracing represent increasingly complex compounds. There have
always been petroleum hydrocarbons in this environment due to living
processes and natural seeps.
That active oil drilling and production operations do sometimes
result in escape of oil to the environment is demonstrated by the in-
frared image of drilling platforms and the temporary sheen resulting
from their activities, shown in figure 31. In the center of the view,
a molecule-thick layer of crude oil shows as a lighter blue area stretch-
ing between the two rigs. The darker areas that you see below are
marsh grasses onshore nearby as they appear on infrared film.
The occurrence of this fresh crude oil on the surface of the water
gave the scientists an opportunity to conduct field studies on its
behavior and fate. The small floating patch shown in figure 32 was
observed for several days.
Twenty-four hours later, the appearance of the oil had changed.
Evaporation of some less complex hydrocarbons and microbial and chemical
degradation of the oil was relatively advanced. It will be noted in
figure 33 that the oil has begun to emulsify and clump.
In order to follow the process and rate of breakdown of the oil
under more controlled conditions, experiments were conducted in the
laboratory. Flasks were inoculated with both locally produced oil and
bacteria found in the area. Here on the left, you note that, the bacteria-
free oil is still floating on the surface of the seawater with very few
globubes and very little clumping. On the right, 24 hours later,
bacterial and chemical action has substantially degraded the crude oil;
clumping is very far advanced; and much of the material has been con-
verted by bacteria into foodstuffs and byproducts.
In order to better identify and count these bacteria, seawater
was placed on suitable materials in shallow plastic dishes using stand-
ard microbiological techniques. Here, particularly under the number 14,
392
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you see several small, white, glistening colonies of individual kinds
of hydrocarbon-degrading bacteria isolated from the study area. These
colonies occur in the same numbers in other control areas in the Gulf
of Mexico.
As the degradation activities of these bacteria are followed
chemically, we go to a microscope view and see large numbers of dark
appearing, rod-shaped, living bacteria inside an oil droplet, where they
are chemically converting the oil to their own use (see figure 36).
An early stage in the conversion is the change of crude oil to fatty
compounds identical to those that naturally occur. The fats then enter
the food web as an energy source. These experiments indicate that physical
and bacterial processes rapidly degrade oil films with the result that
there are extremely low amounts of hydrocarbons (average: 5 parts per
billion) found in Gulf waters—nor is there evidence of a concentration
or buildup of any specific molecule.
One sensitive measure of the gross productivity of the phytoplank-
ton community is the presence and amount of chlorophyll, the green
substance in plants that allows conversion of simple compounds into
:omplex food materials. It can be seen in figure 37 that there were
jignificant seasonal changes in chlorophyll content, reflecting the total
>opulations of floating microscopic plants.
Associated with changes in this floating plant community were
easonal changes in the floating animal community, the zooplankton (see
igure 38). It can be seen that these seasonal changes follow the
easonal change in chlorophyll. The importance of corroborative studies
s clear since, if the seasonal change in zooplankton had not followed
he seasonal change in phytoplankton chlorophyll, it would have been
ecessary to search for other possible explanations of the source of
heir foods.
The bottom-dwelling community is of great import in the ecosystem.
ley receive the "rain" of food that sinks down from above. (See figure
?.) Many of the benthos are filter feeders, taking surrounding water
irough their bodies and digesting out of that water whatever they can.,
;hers eat the muds where they live. It will be noted that the seasonal
tanges in this community greatly exceeded the differences between a
393
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site of man's activity and a control site where there was no such activity.
The bottom community offshore from Timbalier Bay is somewhat unusual
for the Gulf of Mexico in that a dense layer of very muddy water (the
turbid layer) extends for thousands of square miles, effectively pre-
venting light from reaching the bottom. Project geologists traced
this turbid layer to its source in the Mississippi River (but it may
enter the Gulf through the Atchafalaya River during flood stages) and
then laterally along the Continental Shelf. (See figure 40.)
Because the reef effect of platforms is so important, the study
of the living things found on their legs deserves further attention.
(See figure 41.) Every solid surface is colonized and becomes a reef.
Platform legs supported about 6-1/2 pounds of living things per square
yard of surface area, more than anywhere else in the study area. (See
figure 42.) The net effect of all this growth on platform legs is to
increase the available food supply for animals higher in the food chain,
since these plant materials are grazed by fish, snails, and other animals
which are fed upon, in turn, by the species sought by man.
The simplest of green plants, the algae, who are also near the
bottom of the food web, grow on platform legs only in shallower depths
where light can penetrate (see figure 43). Where the climatic conditions
are favorable, more tropical forms of life will migrate onto the new
surface. The white patch (at the bottom) is a tropical coral growing on
a platform leg some 15 miles off the Louisiana Coast. It is the first re
port of this coral growing so far north.
To investigate growth rates, the left side of the leg had been
scraped to the bare metal some 45 days before the photograph was made
(see figure 44). On the left, it is easily seen that recolonization is
rapid. Under clean environmental conditions, it occurs this quickly
when a new surface or a recently clean surface is available. On the
right, the large white patch is a Bryzoan, a colonial animal form.
In figure 45, barnacles are being overgrown by hydroids (other
animal forms). As colonization develops with time, there is both an
increase in and a complexity of living things as well as an increasing
competition for the available space.
Because the major objective of the entire study was to determine
the impact of oil production and drilling on the total environment,
394
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beaches separating Timbalier Bay from the adjacent shelf were sampled
to see what effects could be measured there. Figure 46, a photograph
of oil-saturated sand, was taken on the beach at Timbalier Island.
Laboratory analysis of this specific material indicated the hydrocarbon
source to be fuel oil, but it demonstrates that oil does get on the
beach. Obviously, local concentrations of many hydrocarbons are det-
rimental to growing organisms; however, the impact of any particular
concentration will be determined by how rapidly wave erosion and tidal
currents rework the oil into Gulf waters, where bacterial degradation
processes are more rapid and effective. (See figure 47.) Field tests
here showed that the beach-dwelling animal communities were not harmed.
From the fish-catch, shrimp-catch, and oyster-harvest data shown
plotted here with oil production through the years in this region of
Louisiana, it can be seen that these catches of commercial importance
have not decreased as oil production has increased; indeed they have
increased! This is not to say that increase in catch is a result of
industrial activity; however, it is still found that catches have not
suffered while oil drilling and production have increased greatly dur-
ing the same years.
The deceptively simple question asked in the beginning of the pro-
ject did not turn out to have a simple answer.
Based upon the data analyses thus far, several general conclusions
can be reached from this comprehensive Offshore Ecology Investigation:
1. It questions the universal necessity for conducting a "before-
the-fact" baseline study to subsequently determine the environ-
mental impact of this type of man's activity.
2. Natural phenomena such as seasonality, floods, upwellings, and
turbid layers have much greater impact upon the ecosystem than do
petroleum drilling and production activities.
3. Concentrations of all compounds of OEI interest that are in any way
related to drilling or production are sufficiently low to present no
known persistent biological hazards.
4. Every indication of good ecological health is present. The region
395
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of the sampling sites is a highly productive one from the biological
standpoint, more so than other regions thus far studied in the
Eastern and open Gulf of Mexico.
Timbalier Bay has not undergone significant ecological change as
a result of petroleum drilling and production since just prior
to 1952, when other, more limited, baseline data were generated.
FIGURES
BBS!
The Impact of Oil Drilling and Production in
Timbaiier Bay, La. and Southward in the
Northcentral Gulf of Mexico
1972-1974
Conducted by
GULF UNIVERSITIES RESEARCH CONSORTIUM
Figure I
396
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Figure 4.
Figure 5.
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398
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Figure 6.
399
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Figure 8.
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Figure 9.
400
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Figure 10.
Figure 11.
401
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Figure 12.
Figure 13.
402
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403
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Figure 16.
404
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Figure 17.
Figure 18.
405
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406
-------
Figure 21
Figure 22.
407
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Figure 23.
408
-------
Figure 24.
Figure 25.
409
-------
Figure 26.
410
-------
Figure 27.
411
-------
Figure 28.
412
-------
Figure 29.
413
-------
OFFSHORE SURFACE SAMPLE
IHEXANE FRACTION
COMPOUND
Figure 30.
Figure 31.
414
-------
Figure 32.
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Figure 33.
415
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Figure 34.
Figure 35.
416
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Figure 36.
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Figure 37.
417
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SEASONAL VARIATION OF
Figure 38.
418
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Figure 39.
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420
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Figure 42.
Figure 43.
421
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Figure 44.
Figure 45.
422
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Figure 46.
Figure 47.
423
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100
Commercial Fisheries:
Millions of Pounds
Louisiana Offshore
Productions In Millions
Of Barrels Crude Oil
And Condensate
»34384246SeS458«286?0?2
Figure 48.
424
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Figure 49.
425
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DISCUSSION
MR. DONALD MOORE (National Marine Fishery Service, Galveston, Texas): Mr.
Tyson, I want to make some observations on what is shown in one of your
graphs.
One of the major components of the commercial fishery in Louisana
today—the poundage which I believe your graph included—is the men-
haden fishery, which primarily did not exist at the time v/hen the
commercial catches on your graph started. The menhaden fishery
developed as the commercial market developed; the resource was there
all the time. It was a case of the economic and technical situation
becoming such that a new fishery was developed.
What I am leading to is that this dramatic increase does not
show that the oil development had an impact; neither does it indicate
that it did not have an impact on the resources available. It is
just that the fishery, through the economic incentives and the
technical development, developed new capabilities, to tap additional
fishery resources that were there all along during that period.
MR. TYSON: I tried to make that point in the text, that the two were
not necessarily associated; it has been said by some that fewer fish
are being caught but the total poundage just does not indicate that
at all. More fish are being caught today than have ever been caught
before, for all the reasons you have named and others.
MR. PAT M. WENNEKENS (Alaska Department of Fish & Game, Anchorage, Alaska):
I am a little puzzled about some of the conclusions you arrived at.
This has not shown that damage has been done or not been done.
You go back to what year—1934, 1937?
MR. TYSON: The first well was drilled in Timbalier Bay in 1937.
MR. WENNEKENS: But the question is, what is baseline? What do you com-
pare against, in terms of the basic environment? Do you compare
with what you have now, more or less?
MR. TYSON: In our case, we are comparing controlled areas, which are
adjacent to our study sites: so therefore you are within the
same physical variable regime and have the same ecosystem but
have never experienced any drilling or production activity.
426
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MR. WENNEKENS: No, I am not saying what the base line was before
you had a lot of human impact on the area.
MR. TYSON: A base line did not exist before.
MR. WENNEKENS: Okay. So, just for the sake of argument—
MR. TYSON: Let me continue this just a little bit further where a
base line does exist, which is prior to our study. For example,
the 1952 study that I mentioned dealt primarily with the
crustacean populations in Timbalier Bay. And so you are looking
at over a 20-year period without seeing any change in those
populations.
MR. WENNEKENS: Well, for the sake of argument, I just have to draw
some kind of a parallel to the situation.
Let us say that you are dealing with an environment which
has been essentially in use for a long time, and to assess a given
level of impact, you make a study and find out that a .number of
primary forms of life, such as various plants, are quite abundant,
that you also have a certain abundance and diversity of insects,
that certain species of birds are also very abundant in the area,
and that several different types of mammals are actively feeding.
However, what I describe are the conditions for a garbage dump,
which is a very productive type of environment. And the question
is, unless you have something to compare before such a condition
develops, what do you have in the area, prior to large impact, to
compare against in terms of the baseline environment?
What you might have right now is a condition in which you
have a population that is adapted to pollution; and you are trying
to measure pollution effect on pollution-resistant forms.
MR. TYSON: Thank you. I do not have any reply.
MR. DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba,
Canada): Although the crustacean population has increased in
Timbalier Bay in the last--
MR. TYSON: I did not say it had increased. I said it had not changed.
v\R. WRIGHT: Had not changed. Has not the species composition
shifted somewhat?
1R. TYSON: No.
427
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MR. WRIGHT: Has not there been a change from, say, the white shrimp
to the brown shrimp?
MR. TYSON: No. That part of the crustacean population is not the
part I am talking about. The part that I am talking about has
not been changed at all.
MR. WRIGHT: I see. Your graph on the benthos shows an extreme seasonal
cycling. What was the one axis on your graph showing? The weight
of the organisms, or the quantities, or what?
MR. TYSON: It was biomas.
MR. WRIGHT: Did you subject that data to any information analysis,
species diversity, or other?
MR. TYSON: Yes.
MR. WRIGHT: Was there any change there?
MR. TYSON: No, no significant change.
MR. CHARLES F. JELINEK (Food & Drug Administration, Washington, D.C.):
In the analyses you carried out, did you analyze for heavy metals
at all or for any identified organic chemicals?
MR. TYSON: We did look for the so-called heavy metals. We did not
look for the so-called pesticide types of compounds.
MR. JELINEK: Do you remember which metals you did analyze for among
the heavy ones, like mercury, lead, or so on?
MR. TYSON: Would you care to speak to that, Dr. Montalvo?
DR. MONTALVO: We looked at the heavy elements in the water column late
on and not in biota or sediments. That is the first point I want
to make.
Secondly, the heavy metals that were looked at in the water
column were lead, mercury, cadmium, zinc, and I think arsenic;
five of them. As we went further away from the rig, we found
a decrease in concentration of lead, cadmium, and zinc.
However, the differences between the concentration of metals
at the rig and at the control samples, I think, was in the
same order of magnitude as the seasonal variations of the
metals that were obtained.
428
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MR. TYSON: In addition to the analyses that Dr. Montalvo con-
ducted, there were some 13 other elements for which analyses
were made.
MR. JELINEK: But did you carry them out on any living organisms?
MR. TYSON: Yes, they were carried out on some of the body tissues
by another investigator for some of the elements, zinc
particularly.
MR. GEORGE H. HOLLIDAY (Shell Oil Company, Houston, Texas): Would
you classify Timbalier Bay as a wasteland or a garbage dump now?
MR. TYSON; One can go to Timbalier Bay any time of the day or
night and find sports fishermen and commercial fishermen
working the bay. If you fly over the area, as we have done,
you can see a motorboat at the end of a plume of mud that it
has stirred up. When you fly back over it 7 or 8 hours later,
you can still see that plume of mud that has been stirred up.
It is not a wasteland, at all. In fact, some of you may
be from Cajun country, and would get the Chamber of Commerce
pitch pretty quickly, I suspect.
MR. WRIGHT: Sir, have you been able to identify any layers of
bentonite on the bottom around drilling sites.
MR. TYSON: We have not been able to identify any layers of ben-
tonite.
What you are dealing with is a kind of material that is
dumped into that part of the Gulf of Mexico in such quantities
that man's addition to it—assuming the largest size borehole
in the deepest well, over a period of 45 years, and making some
simple arithmetic calculations—will give you a layer something
like an eighth of an inch thick if it were uniformly distributed.
You cannot find any heaps or piles of it; it is dispersed very
rapidly.
MR. WRIGHT: A lot of clay materials have been dumped in. What is the
primary type of clay that is flowing into the area?
MR. TYSON: It is a bentonite.
429
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MR. WRIGHT: Bentonite or montmorillonite?
MR. TYSON: It has large percentages of the montmorillonite also. You
see, it comes from places like St. Louis and northward.
MR. WRIGHT: I see. It has been my experience—working in the lakes
in Northern Canada—that we have examined a couple of lakes where
bentonite has been spilled as a result of a breach in a drilling
sump, and we have been able to see accumulations of bentonite on
the bottom. In these areas, the bottom fauna has been severely
reduced.
MR. TYSON: I can see where in a lake one might easily see that. As
you know, bentonite is often used by lake owners to seal the bottom.
MR. WRIGHT: Right.
MR. DONALD MOORE: I want to make an observation that I made at another
conference where you gave this paper, since we have brought up the
condition of the Timbalier Bay and the environs. One aspect you
did not go into in your study was the lacing of the marsh with
access channels, pipeline channels, etc. A recent examination of
sequences of aerial photos has shown that the marsh deterioration
in those areas is much accelerated to other areas.
MR. TYSON: This certainly has happened. One other thing, in all fair-
ness, should be said about Timbalier Bay: its bottom is nearly
paved with iron pipe, so it is very difficult to use a magnetic
compass in the area.
MR. GORDON W. LAWSON (Swaco, Houston, Texas): I would like to ask our
fishery friends here if they have any data going back to the World
War II period when so many tankers were sunk off the Gulf and
Atlantic coasts to indicate how this affected the fishery and
what not, and how long it took the fishery to recover. Have you
all studied that?
MR. MOORE: I do not believe the data during that period was all that
good. I am just speculating now, but our sampling agents were
probably somewhat decimated by the conscription at the time.
Also, with the shrimp for instance, our excellent sampling data
has only been occurring since 1962, when we started to collect
the detailed shrimp statistics. We had more generalized
statistics prior to that; what the quality was back in the
forties, I would not care to speculate.
430
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CHAIRMAN GIAM: Joe, who funded this project of yours?
MR. TYSON: The program was funded by 82 corporations, which included
the offshore operators, the service companies, banks, private
foundations, the universities. In some cases even the principal
investigators funded a part of their activity, but the funds
came from a very diverse source. The stipulation placed on the
program by our board of trustees, and by the sponsors, was that
all of the data would be freely published and available to all
who desired it, immediately, but that there would be no special
reports. I am happy to say that there have been none.
MR. MICHAEL J. HARDIN (Environment Canada, Yellowknife, N.W. Territory,
Canada): Mr. Tyson, even though your activities were restricted
to Timbalier Bay, it is likely that people will try to extrapolate
them to other areas where offshore drilling is either contemplated
or will be increased. Now, the ecosystems that you studied were
highly productive and diverse, and therefore were likely to be more
resistant to disruption and change.
However, I am wondering if you would like to speculate on
whether or not less productive ecosystems could adapt equally
well to the sort of impacts that you have observed in Timbalier
Bay?
MR. TYSON: I am unwilling to speculate, as you might surmise.
However, we are just completing a series of data collection
exercises in the Laguna de Terminos in the Bay of Campeche which
has, thus far, throughout its history, experienced only native
agricultural practice. And it is a less diverse environment.
So we will see how much extension we can make of this OEI
data to that kind of a situation.
Now, admittedly, the temperature regime and the seasonality
are very similar in those two locations.
When you go to an environment in which the temperature ranges
are much greater, and in which the biota have already responded
to substantial physical stress or environmental stress, then it
remains to be seen how resilient they will be. But to live in
certain parts of the Arctic or the Antarctic zones takes a
mighty flexible organism.
431
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EFFECTS OF DRILLING OPERATIONS ON THE
MARINE ENVIRONMENT
R. P. Zingula*
?8'tract
Studies by Exxon scientists and others show that offshore drilling
Derations aye not as harmful to the marine environment as some people have
ther proposed or feared. In the Louisiana offshore and many other areas,
vers contribute so much sediment that any resulting from drilling is
gligible. Water samples taken while drilling show a very rapid drop,
a low level, of suspended solids in a short distance downstream from
e rig.
Cuttings accumulating on the sea bottom do not create deserts. Studies
ie using scuba show that mobile organisms are active on the surface of
? pile even while drilling is going on; and in a few months' time these
lanisms turn it into "normal" sea bottom.
Analyses have been made of seawater samples downstream from drilling
'.rations. The common chemicals normally used in drilling—caustic,
n.te, chrome lignosulfonate, etc.—are present in such small quantities
t chemical interaction and dilution make their effect negligible.
Introduction
A number of people have expressed concern over the possibility that
tings and drilling fluids released into the water during offshore drill-
operations are harmful to the marine environment. Specifically, they
2 been concerned with (1) solid drill cuttings, (2) finely divided parti -
; or mud, and (3) drilling mud additives. It has even been suggested
; such operations leave behind permanent graveyards. Studies by scien-
;s from Gulf Universities Research Consortium, and by Exxon, Shell, and
>a divers from other sources have reinforced the conclusions reached by
r investigators that the effects of these discharges are both negli-
e and short-lived.
*Senior Professional Geologist, Exxon Company, USA, Houston, Texas
1.
433
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diver surveys and side scan sonar records that we have seen have shown
accumulations in the Gulf of Mexico to typically be approximately 150 feet
in diameter, with the outline being circular, elongate, or star burst, de-
pending on currents (figure 1). Maximum elevation of these piles immedi-
ately after drilling a well appears to be less than 3 feet, thinning rapidl
toward the edges. Side-scan records of well sites in the Gulf of Mexico
and Santa Barbara Channel several months after drilling has been completed
present no definite "shadows," thus indicating that the height of the
cuttings pile is less than 6 inches. This means that some combination
of compaction, redistribution by currents, settling into the bottom, and
disaggregation of the chips destroys the pile fairly rapidly.
Mobile benthic and planktonic and nektonic organisms are little
affected by the drilling operations and the accumulation of cuttings on
the bottom. It should be remembered that cuttings drift down as indivi-
dual small chips and not as a solid blanket. In October 19711 a team of
Exxon (then Humble) scuba diving geologists and paleontologists studied
and photographed the cuttings accumulating under a rig that was currently
drilling. The jack-up rig Dixielyn 10 was at the time drilling in 80 feet
of water in South Timbalier Block 111 (figure 2). The rig had been drill-
ing for 14 days and at that time had reached a well depth of,11,000 feet.
During the time the rig had been on location, the current had been mainly
in one direction, and the cuttings pile was well delineated on the up-
stream side.
The diving team followed the cuttings from where they first hit the
water at the downpipe to where they came to rest on the sea bottom. A
number of individual fish swam through the area of descending cuttings,
and during the time the divers were in the water several schools of moon-
fish or lookdowns were seen to pass through the area of cuttings and mudd
water. None of these fish showed any signs of distress from either the
cuttings or the associated mud. Indeed, several times spadefish took inc
vidual cuttings into their mouths thinking they were food, only to spit
them out with no sign of distress after finding that they were not edibli
434
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Drill Cuttings
There is no question that the accumulation of cuttings under the
ownpipe .11] be harmful or possibly lethal to many of the sessile ben-
th,c organisms in that small area. The amount of biologic d^IgTis
dependent upon the areal extent and thickness of accumulation of cuttings
which „ in turn dependent on many factors such as the depth of the well-'
hole s,a; type, thickness and hardness of sediments penetrated; strength-
ura ,on and direction of the various currents; water depth; storm action;
depth of bottom of downspout; etc. There is no hard and fast rule as to
what the shape, thickness or extent of accumulation will be. However,
burst pattern is the area! extent of thl™
denser than the surrounding sedimenL
is 50 meters from the borehole "
cuttings indicates that there is
tlon. The light area 1n the
caused by the depression left
the mudline and pulled Sut
The dark
Wh1ch are
°f Cuttin9s
Shad°WS from the
0" the accumula"
th .starburst is the shadow
CdS1ng Was cut off
435
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CM
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436
-------
We were fortunate in that this was a time of low discharge of the
-ivers, that there had been no major storms in the Gulf, and the typical
'muddy layer" was absent, so that the water was remarkably clear all the
ray to the bottom and good photographs could be taken. Figure 3, taken
nder the rig, approximately 70 feet from the upcurrent edge of cuttings,
hows "normal" sea bottom for this area. As can be seen from the photograph
his is an area of sandy mud which has been extensively burrowed by marine
Figure 3. "Normal" sea bottom, as seen under the Dixielyn 10
rig while drilling in 80 feet of water in South Timbalier Block
111. The sandy mud bottom is highly burrowed, and has some
small mollusk fragments (white in the photograph). The hole
in the mound in the center of the photograph is approximately
3 inches across.
ianisms. The photograph in figure 4 was taken approximately 25 feet
m that in figure 3, and 50 feet from the cuttings. It shows indurated
cks of very fine sandstone of Pleistocene (?) age which have been ex-
ed by normal scour activity of the sea in this area. These are similar
composition and hardness to much of the cuttings, but are a naturally
urring phenomenon.
437
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Figure .4. "Normal" sea bottom, taken approximately 25 feet from
figure 3. The angular blocks are indurated, very fine sandstone
of Pleistocene (?) age which have been exposed by natural scour
activity of the sea in this area.
While the well was drilling and the cuttings coming down through t
water, mobile organisms were moving around on top of the fresh cuttings
pile. Small groupers and red snappers (figures 5 and 6) as well as oth
unidentified fish seemed quite at home on the new sea bottom. Several
types and sizes of crabs were wandering about or were dug in (figure 7)
on the pile. Even one small, slow-moving gastropod was observed. All
seemed to be going about their business as they would had the rig not
been there.
438
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Figure 5. Surface at the center of the area of cuttings accumula-
tion. Note the small fish at rest on the cuttings in the center of
the photo, and other fish swimming in the background. Taken with a
15-inch closeup lense, thus the horizontal field of view is about
12 inches at the distance of the small fish. Individual cuttings
or rock chips are readily discernible.
Figure 6. A red snapper is investigating a hole dug in the top of
the pile of cuttings by the photographer. Most of the animals ob-
served were engaged in their usual activities, and seemed unaffected
by the drilling operations.
439
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Figure 7. A small crab is using a large lump of hard clay for pro-
tection as he stirs up a cloud of mud while burrowing into the accu-
mulating cuttings. Photo was taken with a 15-inch closeup lense.
Some people, with no firsthand knowledge of the sea bottom environ-
ment, have hypothesized that the surface of a pile of cuttings would be
sterile for many years. Our experience and study indicates that that is
absolutely not true. Both organisms and the sea itself begin to rework
the cuttings as soon as they are deposited on the bottom. Shale chips,
upon contact with the sea water, begin to disaggregate in a slow but con-
tinuing manner, eventually to become unconsolidated mud like that brought
in by the rivers. Mobile benthonic organisms from the surrounding sea
floor move up onto the cuttings and build homes as they would anywhere
else, as do the larvae of sessile organisms. We had expected such from
our knowledge of the faunas and of the physical effects of the sea; how-
ever, we have only recently obtained photographic proof.
The question had often been asked of us, what did the surface of a
pile of well cuttings look like after the cuttings had been there for som
time. In order to get a definite answer, we recently undertook a study o
same at some of our platforms. It was our intention to use scuba gear to
440
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visit the site of a well that had been drilled within the last 1 to 1-1/2
years, measure the extent and thickness of the pile, observe the fauna or
lack of fauna on the pile, and take sufficient photographs and bottom
samples to demonstrate what was actually there, and to make comparisons
to adjacent "undisturbed" areas. The time lapse noted above from drill-
ing to observation was chosen as a period of time in which marine or-
ganisms could react to the presence of the cuttings, and yet be before the
)ile was redistributed or sank into the sea bottom. We chose South Tim-
elier Block 54 field since a well had been drilled at the desired time
!n the past, the water was of a convenient depth for diving (60-65 feet),
ind living quarters were available for support work.
Unfortunately, because of proximity to the Mississippi and Atchafalaya
'ivers, each about 80 miles away, this area receives a large amount of
lays, which are continually reworked by normal currents and swell, and by
torm waves. As noted by Griffin and Ripy, Oetking et al., and Shinn
refs. 1,2, and 3), this is an area that often has a well developed
spheloid layer, a layer of highly turbid water near and at the sea bot-
Dm. The nepheloid layer, also called the muddy layer or flocculent zone,
>ntains a high percentage of clays and organic detritus in suspension.
len we arrived in the area on January 8, 1975, the waves were only 3
» 5 feet high, but the entire area was somewhat murky near the surface
id visibility was zero on bottom without a diver's light. In addition,
,ere was a noticeable surge on bottom at a depth of 65 feet. Obviously,
ttle examination of cuttings would be possible, if the pile could even
found.
A decision was made to move 20 miles further offshore into 110 feet
water in the South Timbalier 172 field. It was hoped that the increased
ter depth and the greater distance from shore would give us better visa-
lity on bottom. Gulf had drilled one well from a platform in block 172,
th actual drilling completed by April 30, 1974, or approximately 8-1/2
iths before we dove in the area. Here too, the bottom 20 feet of the
;er column was filled with suspended sediment. It must be remembered
it this turbidity was due entirely to natural conditions, and not-to
441
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any drilling activity in the area. The nearest well then drilling was
in block 54, approximately 20 miles to the north, and had no effect on
any but its own immediate area. Bottom water near that platform in block
172 was so murky that both the diver's face and his 100,000 candlepower
light had to be within 6 to 10 inches of the bottom to be able to dis-
tinguish any features there.
The first dive near this platform was outside the area of any cut-
tings accumulation, and the bottom was typical of that of the Gulf--a
thin surface layer of very soft and unconsolidated mud, underlain by
sticky clay with some sand. The bottom was highly burrowed, and there
were numerous whole and broken mollusk shells.
The second dive near the platform was on the pile of cuttings as
was immediately evident by poking one's fingers in to the bottom and
feeling the chips. However, that surface was also highly burrowed, and
had whole and broken mollusk shells; indicating that numerous benthonic
organisms have found this habitat quite suitable to their needs. It
should be noted here that there was a thin accumulation of very soft and
unconsolidated mud there (figures 8 and 9) as was true of the "normal"
sea bottom, indicating that marine sediments are already covering the
cuttings. Although the water was very murky, several photographs were
obtained using a 4-3/4 inch Hydrophoto closeup lense on a Nikonos camera
with a Honeywell Strobonar 770 strobe for a light source. These photos
(figures 8 and 9) show evidence of burrowing, small mollusk fragments,
and some cutting chips that have either not been covered over, or have
been reexcavated by fauna! activity.
A sample was taken of the top 2 inches of sediment cuttings at
that spot. The cuttings have been somewhat rounded by partial disaggre
gation of the clays from the swelling due to seawater adsorption and
possibly from abrasive current action. These clay chips also show a
brownish oxidation on the exterior, further evidence that the chips are
undergoing weathering arxd will not remain as entities. Fossil foramini
fers protruding from these chips are proof absolute that these are defi
nitely cuttings from the well, and not from any possible local rock out
crop.
442
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Figure 8. Surface of cuttings that had been on the sea bottom for
8-1/2 months, in 110 feet of water in South Timbalier Block 172.
A number of chips are visible, but most of the surface is covered
with mud accumulation from normal sedimentation processes. Dark,
conical object in upper right is a live snail whose shell is
covered with a fuzzy growth of algae and/or hydrozoans. Apparent
slope of the bottom is due to the angle at which the camera was
held. Photo was taken with a 4-3/4 inch closeup, and lateral field
of view across the center of the photo is approximately 3-1/4 inches,
Figure 9. Photo taken approximately 3 feet from figure 8, and with
the same lense. Light-colored objects are mollusk fragments.
443
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,"'. .-c"i>r'rt> ;:ou n\ Uv:' included RPC ent fauna in i.hat sompie with that
of <• sample Uke?i ,nn: '-h.'.'-^ -.hid, both contain essentially the same fauna, and in essentially
{•ji,> -,:»)!£, abundant!-. Present in both are nearly 30 species of foremi infers,
mo!^ iiun : •") species of rnollusks and micromollusks, several sped PS of
bryv.i^M, (both frre specimens and coating mollusk shells), echinoid
spines, oi'?r'u>"oid ossicles, crab fragments, etc. This is clear and imde-
n;nSi"o p'oof that; a number of types of benthonic organisms find the area
•-•I' f'stt iiiijs accumulation just as environmentally acceptable as the ?ur~
Or r,l_i_rsa.. Fluids
A'lothe.' area of tonrern is the finely parti dilated and dissolved
niaU-ria i \-";I ••>*••• a '-tii-'na ciri!! u,tj oi)f?'"3t i-ur.. primarily material
wf^'i'-h ';oat:«, th« vv'.'i"•'!«!!);«,l chips and is washed off by the ^e.iwater,
I"5'-, wu-.i';-.' in» ki-'.e t"u<^!y divided inud, whether from the drilled formations
or •>.<>?;'U'>->c -in.-) y;vr-'a-c-i cneinicr' 1 s wUr.h micjht. or- nfided 'f1 the tr.M^ sys-
t,^-,,. '"M».-i, •;;"!<.,-": U , •-,.•,'''in h,ic. been '-r-presse'; over the ^feci. ol muddy
v.^'cr ,.'/. filtrv foti'in. - ^nd the (>oss sMo r.oxifvu.y of additives such as
•'i'1'ii,(,•, :->.ii,i,e. 'U)M >-.h:'M!iK» rigr«;sulfonate
;'s;vi-Hi f.rio ' •!.>' ••"•' wf'51'! i»'. i.iv? ..-r'sa, a wnl! wa^ bf^!t,(•)11 -.\ '- lojurj" spavwter 100 yards upstream from the platforn as a si;:»n
d^>-<, •,- •,>: \ as tiif dr'Miin?! mud in mud tanks below the shoie shaker,
; n-- -,:•;•'"••} t.,-*.f>r '* thf bottom end of the dov^apipe, and HIP water \\\ Ihf
t'.i,'.;*-> ,-f rj»f-! fiiuddy wate*' plM!,;e (a*, hi*1 sea surface and at minus 30 feet
a: ch'•;,t,:",!t -^' "S both 100 yards and 1/8 mile downstream ?rfm l.he downpipe),
y,- v/fiiibi h3-.'*"5 t^K^ri vamp^HN further downstream hut could ivt define any
fms \d\' '''us.n-' hir'Jier th?>!i ^nat. All samples we»T- collected in c1p'>;-!,
1 i'-t-i .;-!<'>, which were ' tinned lately sealed,
,\ fif.'i ::t-jvi> test fo-'- c.aoc-i.ic in the seav^ter can b^ tisde by we?,-
sin-Miii t;\j- f-ii t'f.-r all vj'spies, pH measurements were made by nieasuring
wi'.h •• ''.<>. «• • s m.'i'iri H >>(! rno'^r that" v/ds calibrated aqain^t solutions of
44/i
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known pH both before and after running the samples. The pH was deter-
mined again 4 days later at the Exxon Production Research Co. laboratory
in Houston, Texas. As can be seen from table 1 and figure 10, discharge
from the drilling operation had virtually no effect on the pH of the sea-
water. Greater variations in pH occurred naturally, due to water depth,
than occurred from drilling fluids.
A comment should be made here concerning the pH of the drilling mud.
Caustic was continually being added to the mud system so that the pH of
the mud was 10.4 both going in and coming out of the hole. However, sea-
water was also being added to the mud system at the shale shaker, and
magnesium ions in that water combined with the caustic to effectively
neutralize it and bring the pH down to essentially that of normal sea-
water. Thus, the mud tank sample pH of 8.5 (sample no. 1 of table 1 and
figure 10) reflects the action of the relatively small amount of added
seawater on the caustic in the mud. The pH of the system was built up
to 10.8 between where that sample was taken and where the mud was pumped
jack down the well.
Geochemists at EPRCo also determined the amount of suspended solids
in each sample. Ascertained values as shown in table 1 and figure 10
ndicate that although finely divided suspended solids do enter the sea,
hey are so diluted by the seawater as to be of no significance. It is
f interest to note that the "clean" seawater upstream from drilling
perations had essentially the same amount of suspended solids as did
eawater 1/8 mile downstream. Unfortunately, the very murky water near
he sea bottom, in the nepheloid layer, was not sampled. However, according
•> GURC studies (refs. 1 and 2), that water can have at least as much
Jturally occurring solids as does the water at the end of the downpipe.
The last few Environmental Impact Statements have directed some
miments to the addition of chrome lignosulfonate, with the idea that it
ght contribute toxic amounts of soluble chromium to the sea. Spersene,
le such chemical, had already been added to the E-54 well mud system in
andard amounts. All samples collected were analyzed for chromium by
445
-------
Table 1. Analyses of samples collected January 9, 1975, by R. P. Zingula
et al., at and around a well being drilled at Exxon's South
Timbalier Block 54-E platform
Sample
No.
1
Description
Drilling mud from
mud tanks under the
shale shaker
Measured pHa
on-
site lab
8.48 8.5
Suspended
solids,
mg/1
350,000
Solubleb
Bar-
ium
<0.5
ppm
Chrom-
ium
<0.2
ppm
2 Mud at downpipe at
water surface 8.42 8.5
3 Water at center of
muddy stream at sea
surface, 100 yd
downstream from
downpipe 8.42 8.6
4 Surface water at
center of muddy
stream 1/8 mi down-
stream from downpipe 8.43 8.6
5 30 ft below sea sur-
face at location of
sample 3 8.20 8.4
6 30 ft below sea
surface at location
of sample 4 8.18 8.4
7 "Clean" seawater
at sea surface, 100
yd upstream from
downpipe 8.45
Spersene solution0 —
(lab.)
278
8.6
3.1
40.7
5.5
1.5
1.1
5.2 "
231 —- 11,400
ppm
aSamples taken at 8-8:30 a.m., January 9. Onsite pH measurements made
at 10-10:30 p.m., January 9. Lab measurements made January 13 & 14.
bMeasurements of soluble chromium and barium were by atomic absorption,
calibrated against a standard. Concentrations were below the limits of
measurements of the system, i.e., 0.5 ppm barium and 0.2 ppm chromium.
cSpersene solution was made by mixing two parts water with one part sper-
sene by weight and letting stand for 24 hours.
446
-------
SOUTH TIMBAUER
54-E PLATFORM
SEA LEVEL
(5.2)
C8.4KI
CURRENT
>
-soft
SEA BOTTOM
(35O.OOO)
ce.«3 cs.423
C8^»33
(N) Sample number
from table I.
(N) Suspended solids
in mg/liter
CND pH measured on
site
(,.5,
C8.2O3
C8.IS3
MS'
SCALE
Figure 10. Diagrammatic presentation of pH and suspended solids
in samples described in table 1.
ie atomic absorption method calibrated against a standard. As noted in
ible 1, any chromium that was present in the mud systems and in the
iddy seawater was less than 0.2 ppm and too minute to be detectable.
though the atomic absorption technique is not accurate enough to
tect amounts of chromium as small as would typically be present in
awater, it does indicate that there is no large amount of chromium
•
tering the sea from such drilling operations. As also noted in the
nal Mafia EIS, there are no known hazards to the environment from
romium in the very diluted form in drilling mud.
Tests for soluble barium were also run, even though the barite added
the drilling mud is considered insoluble. As can be seen from table 1,
detectable amounts of soluble barium were present in any of the samples,
the same time, it should be noted that barium sulfate is the twelfth
;t common mineral compound found in seawater.
447
-------
Conclusions
Offshore drilling operations are not as harmful to the marine environ-
ment as some people have either proposed or feared. In the Louisiana off-
shore and many other areas, rivers contribute so much sediment that any
resulting from drilling operations is negligible. The Mississippi River
alone dumps as much weight (and many times the volume) of sediments into
the Gulf of Mexico every 51 seconds as is produced by the average 10,000-
foot offshore well. Additionally, trawling and dredging activities cou-
pled with the naturally occurring nepheloid layer keep far more solids
in suspension than those supplied by all the drilling wells.
Cuttings accumulating on the sea bottom do not create deserts, as
suggested by some. Mobile organisms are active on the surface of the
pile even while drilling is going on; and in a few months' time they turn
it into a "normal" sea bottom.
The common chemicals normally used in drilling—caustic, barite,
chrome lignosulfonate, etc.—are present in such small quantities that
chemical interaction and dilution should make their effect negligible
(table 1).
REFERENCES
1. G. M. Griffin and B. J. Ripy, "Turbidity, Suspended Sediment Con-
centrations, Clay Mineralogy of Suspended Sediments, and the
Origin of the Turbid Near-Bottom Water Layer - Louisiana Shelf
South of Timbalier Bay—August, 1972 - January, 1974— with Com-
ments on a Process Model for Turbid Layer Transport," unpublished
report of results obtained from a project supported by the Gulf
Universities Research Consortium as part of its Offshore Ecology
Investigation.
2. M. P. Oetking, R. Back, R. Watson, and C. Merks, "Surface and Shallov
Subsurface Sediments of the Nearshore Continental Shelf of South
Central Louisiana," Gulf Universities Research Consortium Contract
GU853-8 (in press).
3. E. A. Shinn, "Effects of Oil Field Brine, Drilling Mud, Cuttings
and Oil Platforms on the Offshore Environment," in Marine Environ-
mental Implications of Offshore Oil and Gas Development in the
Baltimore Canyon Region of the Mid-Atlantic Coast, proceedings of
Estuarine Research Federation Outer Continental Shelf Conference
and Workshop, College Park, Maryland, December 2-4, 1974, ERF 75-1,
1975.
448
-------
DISCUSSION
MR. DENNIS G. JJRIGHT (Environment Canada, Winnipeg, Manitoba, Canada):
I have just a comment.
In the past 2 days we have been discussing drilling wastes.
Nobody has really come out with a statement of just how much waste
we are talking about. My question is, has anybody in the industry
taken a look at just how much drilling fluid you are wasting to the
environment?
DR. ZINGULA: Yes and no. I would like to say not that we are wasting
to the environment but that we are putting over a given amount.
I think Jim Ray, who will be speaking tomorrow, has some fig-
ures on that in his paper.
I would like to throw in one little comment. I know your
rivers, and so forth, up there in Canada are a little colder, because
I am used to scuba diving up there, too, and they are not carrying
as much sediment as the Mississppi River. But out here the river
puts in to the environment every 51 seconds the amount of sediment
in weight (not volume, because our volume is smaller) that we would
put in from a 10,000-foot well. But Jim Ray will have figures to-
morrow on what is typical for a 10,000-foot well in volume and
weight of the sediments and the various mud components.
449
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TREATMENT AND DISPOSAL OF WASTE FLUIDS FROM ONSHORE DRILLING SITES
G. A. Specken*
Abstract
The accumulation and storage of waste mater-Lais -in open, earthen pits
(sumps) during the drilling of onshore oil and/or gas wells leads to an
appreciable volume—up to about 100,000 barrels per site—of waste fluids
rf varied composition. Disposal of these sump fluids has become a prob-
lem in those parts of the country where regulatory bodies no longer allow
simple dumping of the fluids to the environment. For instance, in Western
Canada the clarified water from drilling site sumps must meet certain
luality standards, primarily the passing of a trout bioassay before it can
ie pumped off-lease. A process has been developed whereby the sump con-
sents are treated in situ such that a major portion of the total fluid vol-
me is generated as clarified, detoxified water acceptable for off-lease
Disposal to the land. A minor portion of the total fluid volume is left
>et, flocculated solids or sludge in the bottom of the sump pit for burial
here or disposal to the lease area. The various aspects of this treatment
nd disposal process are discussed, and cost data for 2 years of commercial
Deration in Western Canada are presented. In some selected cases, the
ost data are related to the types of drilling fluid systems used to drill
he holes.
INTRODUCTION
In order to appreciate various aspects of the treatment and disposal
; waste fluids from onshore drilling sites, a brief examination of past
id present practices in Alberta in this regard is helpful.
During the drilling of an onshore oil and/or gas well, an open earth-
pit or sump is used as a collecting basin for waste drilling fluid,
*Chemical Engineer, Wilson Mud Service, Ltd., Edmonton, Alberta.
451
-------
solid cuttings from the hole, and wash water from the drilling rig deck.
Because the pit is open to the atmosphere, the sump contents are increased
or decreased by whatever net precipitation happens to occur. By the end
of a drilling operation, an appreciable volume (typically 5,000 to 50,000
barrels, and occasionally as much as 100,000 barrels) of waste fluids has
thus accumulated in the sump. Generally, sump contents consists of three
distinct phases—a thin layer of oil scum on the surface, a large aqueous
phase with dissolved components and suspended solids, and a bottom layer
of sludge containing most of the solids which have settled.
Until recent years, it was normal practice in Alberta to dispose of
the contents of drilling site sumps directly to the environment, that is,
to the lease arid surrounding area, without any prior treatment .whatsoever.
If the oil scum was inflammable, it was not uncommon to concentrate it at
one end of the sump and burn it. The so-called "clear water" layer was
pumped out of the pit and distributed over the lease or adjacent area to
dry to atmosphere or soak into the ground. The partly empty pit was then
filled by bulldozing brush and earth into it. In doing so, the sludge
layer was either buried, or "squeezed" out of the pit arid spread on the lea;
surface to dry or be worked into the topsoil.
In recent years, public and governmental concern over environmental
pollution led to more stringent requirements than those outlined above for
the disposal of these waste fluids. By the early 1970's, there was a sig-
nificant number of cases in Alberta where the sump fluid in question was
considered environmentally hazardous and it had to be hauled away and dis-
posed of in some designated location, such as a gravel pit or a disposal
well. The high haulage costs and the long time delays for the total lease
cleanups pointed to the need for a better disposal method for these "prob-
lem" sumps. Consequently, in mid-1971, Wilson Mud Service Ltd. initiated
a research project to achieve this end.
DEVELOPMENT OF THE TREATMENT PROCESS
The ultimate objective of the research project was to develop a pro-
cess by which drilling-site sump fluids could be altered so that they coul<
-------
e disposed of directly and safely to the environment. Under the project,
t was proposed to evaluate various water and wastewater treatment methods
nd apply them to drilling-site sump fluids in the context of remote dril-
ing locations.
For the project evaluation, the total process was divided into three
-eas of investigation, namely oil-water separation, solids-liquid separa-
'on, and purification of the clarified water phase to render it sufficient-
' innocuous to the environment. Consideration of the various constraints
iposed by the drilling-site context led to a specific list of known treat-
nt methods to be evaluated in each area of investigation. Although these
oposed methods were part of existing technology, the various aspects of
e drilling site context—remote location of leases, seasonal weather con-
tions, complex and variable sump composition, and diversity in water
ality required by regulatory bodies—suggested that existing treatment
thods would require some adaptation and innovation.
The various candidate processing steps were first screened for techni-
I and economic feasibility by conducting paper engineering studies supported
experimentation, where necessary, on actual problem sump fluids. At the
;set, it was evident that only batch-type processes or treatment steps
t could be effected right in the sump were the most promising candidates.
o, a relatively small scale of testwork—batch charges of a quart to a
Ion each—was found satisfactory for evaluation of certain steps (such as
gulation-flocculation, adsorption, precipitation, and oxidation). This
because the efficacy of these techniques is usually predictable, pro-
ed that adequate mixing and/or contacting with the test fluid is achieved.
importance of this small-scale development work is emphasized, because
led to full-scale field tests without intermediate scaleup.
The experimental program involved as large a variety of actual prob-
sump fluids as possible, so that the resultant process would be versa-
; enough to cover the majority of problem sumps, if not all, when com-
nalized. It was anticipated that one water treatment method would be
ifficient to cover the range of pollutants known to exist in sump fluids,
it was intended to engineer all the chosen techniques into one equipment
mbly. This was borne in mind when selecting the various treatment
453
-------
methods, most of which can be effected by pumping and mixing some ingre-
dient into the sump contents.
On the basis of the engineering studies and the bench scale experi-
mentation program, the most promising candidate processing steps were
translated into a prototype field equipment assembly, which was then
used to conduct a field test program. After five successful field tests,
a followup evaluation of the process and the prototype unit was carried
out.
In both the bench scale experimentation program and the field test
program, samples of treated and clarified water from each experiment were
evaluated in terms of water quality by the test(s) that would be used by
the pertinent regulatory bodies in a real disposal situation. In Alberta,
the main water quality test, developed especially for this purpose, is a
modified fish bioassay using rainbow trout. Therefore, the trea-tment pro-
cess was designed primarily to transform a maximum amount of a given sump
fluid into clarified, detoxified water that passes a trout bioassay.
COMMERCIAL APPLICATION OF THE PROCESS
The process that evolved from the above research project has been
applied commercially in Alberta during the operational seasons of 1973 and
1974, and to a lesser extent in British Columbia in 1974. An operational
season is generally limited to the time between spring thaw and fall freez
up, but has been extended a month or so beyond freezeup by using heating
equipment to melt ice caps or keep them from forming on the sumps while
the various steps of the process are underway.
A rather methodical approach is taken in the commercial application
of the process. For a given sump, this involves a series of activities
that include a prior sump evaluation, a cost projection and contract bid,
and the actual field treatment and disposal of the fluid.
1. Sump Evaluation
In order to insure that a given sump can be treated successfully and
disposed of at a predictable cost, a complete evaluation of it is carried
out. This evaluation takes place both at the sump site and in the labora
tory.
454
-------
First, the location is visited to obtain direct information on the
sump, the lease, and the surrounding area. The surface dimensions of the
sump are measured. Using a boat to traverse the surface of the sump,
depth measurements are taken (by probe or weighted string) from various
points so as to estimate both the average total depth of fluid in the
sump and the average thickness of the mud layer in the bottom of the sump.
Similarly, with the boat located at different points on the sump surface,
fluid samples are taken from different elevations in the sump. The exist-
ence and approximate volume of an oil layer are noted, as well as the rela-
tive degree of solids suspension in the fluid body. Finally, a visual
appraisal is made of the lease access road, the surface condition of the
lease, and the surrounding area. This helps to predict what mobility prob-
lems might be encountered, and also indicates where the service rig could
De located next to the pit and where the treated water could eventually
>e pumped.
The laboratory evaluation involves treatments of the sump samples
;o determine the proper sequence and dosages of chemicals required for
;uccessful toxicity reduction and clarification of the sump fluid. The
ifficacy of each treatment program thus determined is verified by trout
ioassays on the lab-treated samples. Certain analyses are done on both
ntreated and lab-treated samples to enable prediction of various ion con-
entrations and pH of the final water.
The thorough sampling procedure of the field evaluation (which invari-
bly yields two to four dozen quart samples of fluid from each sump),
Dupled with some simple analyses on the individual samples in the labora-
)ry, has proven time and time again that sump fluids tend to become stra-
ified. This is especially true of sump fluids containing a high concen-
'ation of suspended solids. A typical example of a stratified sump is
lustrated by the data in table 1, in which the results of calcium, chlor-
le, and pH determinations are listed according to sample depth. The data
iow that all three—the calcium content, the chloride content, and the pH
the fluid—increase remarkably with increasing fluid depth, and that
e ions appear to be associated with the suspended solids. Similarly, it
455
-------
Table 1. Selected analyses on samples according to depth
Sample
elevation
surface
3 ft depth
Sample
point
12
2
5
7
Sample
appearance
almost clear
almost clear
almost clear
almost clear
Ca,
ppm
300
320
360
360
Cl,
Ppm
1650
2330
2720
2820
pH
7.1
7.4
7.2
7.5
3 ft average
6 ft depth
6 ft average
8 ft depth
4
9
almost clear
almost clear
almost clear
350
480
500
490
560
2620
6800
7000
6900
7000
7.4
9.2
9.2
9.2
9.3
10
10
ft depth
ft average
1
6
8
10
11
—
light solids
high solids
high solids
light solids
light solids
—
600
5360
400
680
560
1520
7000
11650
6900
6600
6700
7990
8.2
9.6
10.6
10.9
9.2
9.7
can be shown that the level'of dissolved, toxic organics in a surface
sample can be radically different than that in a depth sample. This wide
variation in fluid composition in a stratified sump is emphasized, because
it points out the necessity of the multisample approach, so that a composi
sample can be made up to represent the majority of the fluid body in the
sump.
2. Cost Projection and Contract Bid
Based on the information of the sump evaluation(s), the total cost tc
treat and dispose of the sump fluids on a given lease is estimated. This
cost projection can be influenced appreciably if contracts to treat other
456
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sumps in Hjr sai.ie yeoera! ar»>» 'i<-,:i •. :i -;i:.i i .,
of equipment: and ovw reduces the projected •.<)<•, 1 j.^r C'tntf'vj. !
The total treatment and disoosdl cost is a^avs -^n'" :?<.'! »•,' ••> ^ ;••>
tract bid, although the cost expressed in cencs u^r i.ut.^'i .1' 'ho MU i
fluids to be treated can be determined f i or. "''he in forget'1 !•>> ';,< nu- 'duo
evaluation.
3, field Trfctinent and liisposdl
The tucal sump 'i.r.eatiiient and disposal process c *n t;»- [>>•<•!:.>'<, d>n..,<•', ui.'ior^
f i na i da rif" i ca i; i on. t: nd pump -ou t..
Removal ;;f oil fr',ifi! d sufip is necessary, nor n.is? :u tr,, -.•.-.n? ih,-
subsequent Toxicit/ reduction step, but to mn«•'!'. "::^.;'b!( .-
well, i'n most (.d^es, I'ne residual voIuiTie of ol; ih f an.3 riM\+r
est merhod of oil reii'CN'rJi is to burn it on the ••>'•!• '^\<..^ of ! f»-- '''!.," \^<\--
If" pe-'nn's^ ion t'j du ^o (..atinot be1 otained i'c'mi ihe •','(;;*! '^v- / o •.:' <--,
jbUdily becdih-tu d real vire hazard to surruiindn:..} *,,-<,^^,iia-n • i.i.s. j-u-ir
it is lieceisary 'co ski«,i the o'il from the ^usrip. In ',-.\iiio.n '..- i>- >•>(•:, i-^n
if light fiiechd'ii( a ( equipment for thu sKiiriti.ifi'.j do-J >• tint-'j] ,•>•>_><'',.< ,-;
liquid .surToctarit is sotnet imos used to assis-, (n IHOV^MJ tfic ;,-• i j / , .IK
iurr'dCfc: c-f the water, ihe oil scuin rerun */er.f fr's.i-i tn^ '.i.iMo is iV.x:'M;-,.f, i-.
)tit. into d sifw 11 ou.xi i tary pit fo»' suhss-Ljuent \v» u h<:; v •<: •.»' id'.;
wte spreadmg acid ifrixinn into the l'i(soi> '<:i i!u- ':->..,;
A prior c.idt HicdtJi^'i :,.tep is necebs^fy if <"hc < .ini,,^'^ i u> 'ettif'd 'uu-i i •-'e^ >, ;>••<. sc.." .^d
oo hi-yfi, i:s diitimpftuoii that the suspended sol "Js ^u.'l s ..'-e '-'-o v-'^n
he chemicals used in the subsequent detox i f icitt ion of >..••*'' i;o?f ;.'•-!.•,,•
lari ficdtiori of the susi:p wafer i.s dt.ci^npl isn^d b' « i in . •,-,'• ,->., n,^ ^>?\,
allowed by a period of time sufficient to allow >.ft; ii:i.; f- 'is.. M,-»«,',
a ted solids f,o the bottom of the sump, ihe f h,'< cufa \\->, •< \'m,> .-. t^i-",.;
jt by dispersing i.r>ao!uldr,-ts add flocculants (fioly^sVt! .li/f'.1- < .'s;t. i,^.
jmp water at predetei'i'iined concentrations. A truck-"M-mii-,!! -• i.',•;/,.-H.
>stftiblvv i.oas is t! no primarily of a puinpinj did soMit lo-i ;'i..i .»",)' , -,j ,-:
iGdtjfivi siii.-ip ,i-fxer ^-"fe provided to effect r.hss -.i---^- r-a, ,".-u- ; .ii.v-.-.t-i
45,
-------
units can recirculate the sump contents at rates up to about 3,000 barrels/
hour, while the floating mixers can turn the sump contents over at rates
up to about 9,000 barrels/hour. Depending on the original solids concen-
tration in the sump and the "tightness" of the solids sludge after set-
tling, usually about 60 percent of the total fluid body is obtained as a
solids-free water layer.
If a sump has been classified as toxic, in that an untreated sample
of it has failed the trout bioassay, then it must be treated to reduce
the level of toxic components dissolved in the water. This is done by
thoroughly mixing treatment chemicals into the body of fluid using the
truck-mounted unit in conjunction with a floating sump mixer. In addition
to removal of dissolved toxic components from the water, it is sometimes
necessary to adjust the pH of the water so that ultimately it will pass
a trout check. Choice of the kind of acid for pH-adjustment is important,
so that the concentration limit on the anion added (chloride, sulphate,
or phosphate) is not exceeded.
A final clarification step is always required after the detoxifica-
tion step in order to remove any residual suspended solids and thus pro-
duce the clarity required for off-lease disposal of the treated water.
As described above, clarification is accomplished by coagulation-floccu-
lation and sedimentation of the solids.
After the detoxification and clarification steps have been completed,
a representative sample of the final water to be pumped out is taken for
a final trout bioassay and water analysis. These tests are done at a
certified commercial laboratory or at the Alberta Energy Resources Con-
servation Board laboratory, but in any event, the results of the tests an
made available to the pertinent regulatory body personnel. Because a suo
cessful trout check requires 4 days, there is usually a time lapse of at
least a week between the final clarification step and the pump-out step.
Pump-out of the clarified, treated water from a sump is done only
after permission is obtained from the regulatory bodies and very often is
done under their surveillance. Because it is invariably desired to pump
the water on the land adjacent to the lease, the applicable regulatory
body and/or land owner is approached ahead of time so that the exact area
458
-------
for disposal is agreed to by all parti'es. Two methods of pump-out have
been offered—one using open-gated irrigation hose, and the second using
an irrigation gun (sprinkler). The open-gated irrigation hose is the pre-
ferred pump-out method because of its higher disposal rate (about 3,000
barrels/hour) for the horsepower provided, and in 2 years of commerical
operation it has always been used for the pump-out step.
There are certain practical considerations that place limitations
or constraints on the use of the process. Because the sump contents must
be in the fluid state to undergo the various operations, the process is
a seasonal one, in that use of it is generally limited to the time between
spring thaw and fall freezeup. Accessibility both to the lease and to the
sump is essential for each processing step. Usually these steps are
spaced across a time span of more than 2 weeks, with several trips to the
lease involved. The service rig must be able to park within about 15 feet
of the sump, and vehicular mobility on the lease is required to some ex-
tent for all the processing steps.
The primary feature of the treatment process is its ability to reduce
the level of dissolved, toxic components and suspended solids in the sump
yater so that the trout check can be passed. The process does not lower
the chloride content of the water. Therefore, if the initial chloride
:oncentration of the untreated water already exceeds the limit set by the
'egulatory bodies for disposal in a given area, then disposal of the
:reated water, even if the trout check is passed, may still be a problem.
COST OF THE PROCESS
Selected statistics and cost data on all the sumps treated and dis-
osed of by Wilson Mud Service Ltd. in 1973 and 1974 are presented in
able 2. From this data, it appears that the overall average cost of
he process is in the order of 30 cents per barrel of sump fluids treated.
owever, as table 2 also shows, the cost varied widely, from below 20
ents to above 50 cents per barrel of fluids treated.
This treatment cost variation can be traced to various contributory
actors, such as sump size, the number of sumps per lease, the remote lo-
ations involved, and especially the nature and varied composition of the
459
-------
Table 2. Selected statistics and cost data on treated sumps
1973 1974
Number of treatment-disposal contracts 15 22
Total fluids volume per lease,
(barrels)
-average 33,200 34,000
-range 3,000 to 74,000 12,000 to 75,000
Volume pumped out, (% of
total treated) 62.5 51.9
Depth of well drilled, ifeet)
-average 12,260 11,550
-range 6,400 to 18,000 7,280 to 18,530
Total fluids volume, (barrels),
per foot of hole drilled 3.02 2,95
Total treatment & disposal cost, ($),
per contract
-average 9,220 10,420
-range 1,500 to 20,000 1,500 to 34,000
Total weighted cost, (^/barrel) of
treated fluid
-average 27.8 30.6
-range 17.1 to 57.8 13.5 to 61.5
fluids themselves. The effect of some of these factors on treatment cost
can be shown by segregating the treatment .contracts of 1974 into two
categories, one in which no special problems were apparent and in which
the treatments were considered "typical", and the other in which two fac-
tors (the nature of the fluids, and very remote locations) obviously in-
creased the cost and the treatments were considered "nontypical". This
has been done to derive the statistics and cost data displayed in table 3
where the "nontypical" contracts of 1974 include four sumps containing
invert drilling fluid systems, one sump containing a modified lignite dri
ling fluid system, and two sumps remotely located in British Columbia.
The data of table 3 show that the average treatment cost (at about 44
460
-------
Table 3. Selected statistics and cost data on treated sumps
(segregation of 1974 contracts)
1974 Treatment Contracts
Typical Nontypical
umber of treatment-disposal contracts 15 7
otal fluids volume per lease,
(barrels)
-average 31,200 40,100
-range 12,000 to 75,000 19,000 to 66,000
)lume pumped out, (% of total treated) 48.1 58.4
jpth of well drilled, (feet)
-average 10,520 13,740
-range 7,280 to 16,910 8,900 to 18,530
ital fluids volume, (barrels),
per foot of hole drilled 2.97 2.92
tal treatment & disposal cost, ($),
per contract
-average , 7,090 17,540
-range 1,500 to 13,300 6,400 to 34,000
tal weighted cost, U/barrel) of
treated fluid
-average 22.7 43.7
-range 13.5 to 33.6 32.3 to 61.5
ts per barrel of fluid treated) of these seven special problem sumps
almost double that (at about 23 cents per barrel of fluid treated) of
other 15 contracts. The higher treatment cost of these special problem
35 was despite their larger sump size, which normally tends to decrease
cost expressed in cents per barrel of fluid treated.
Based on the cost projections arising from about 120 sump evaluations
; to date, and on the actual costs of 42 contracts completed successfully
;he field, it can be concluded that the one factor that has the greatest
uence on a sump treatment program, and therefore the treatment cost, is
nature of the drilling fluid system used to drill the well. In general,
461
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the cost projected to treat sumps derived from either an invert or a KC1-
polymer drilling fluid system is in the order of 35 to 40 cents per bar-
rel of fluid treated, whereas the cost projected to treat sumps derived
from various freshwater-gel systems is about 30 percent less. These par-
ticular drilling fluid systems are mentioned, because they are the ones
that generally have been encountered in the sumps evaluated to date.
DISCUSSION
MR. RICHARD S. SCALAN (University of Texas, Austin, Texas): I admit you
have a problem up there in Canada. But in South Texas, I wonder if
the thing to do, in light of the gentlemen from GURC and Exxon, would
be simply to put it on a barge, take it out to sea, and dump it?
MR. SPECKEN: Well, of course, we are discussing onshore disposal in a
certain area. It seems that down in Texas you do not have the
same volume of water involved in your pits. If anything, you are
happy to get any kind of water on the land.
In Alberta we have the head waters of all of our rivers forming
in those foothills, and I imagine this is one of the reasons why the
regulations have evolved.
MR. DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba, CAnada): Arc
you allowed to discharge any of your clarified waste to surface water;
MR. SPECKEN: Yes, but only if we get the permit to do so from the Alberta
Department of Environment. It takes longer, you have more analyses t<
present to them, and it has to be a special case. But it can be
achieved, yes.
MR. WRIGHT: I see. Does your process reduce chloride concentration in
any way?
MR. SPECKEN: Definitely not. You can reduce some of the ions, perhaps
phosphate if you have to, but chloride is not reduced and, therefore,
what is there you are stuck with.
There again, limiting the amount of water in a pit usually works
the wrong way, because more water decreases the chloride concentratic
462
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THE TOXICITY OF DRILLING FLUIDS,
THEIR TESTING AND DISPOSAL
D. R. Shaw*
'jstract
The composition of drilling fluids is often complex3 and the various
mponents and combinations of chemicals are frequently quite poisonous.
the time the well is completed these materials have been relegated to
e sump where they become a disposal problem. A method of sampling and
sting has been outlined, so that the toxicity of sumps can be determined.
ideline outline appropriate action to be taken by the operator and the
vernment agencies to insure that fluids are disposed of by methods which
feet the environment as little as possible.
IP FLUID COMPOSITION
Drillir.g fluids may be clay in water suspensions, or they may be pro-
issively more complex or specialized for deeper wells. Modifications may
;lude the addition of chemicals to raise or lower the viscosity and gel-
ength, or adjust wall-building characteristics. The chemicals may be
pie, like bicarbonate of soda, or very complex, particularly if the mud
t be adjusted with emulsifiers or partially emulsified oil, bentonite
anders, thickeners, etc. A recent count of the brand name additives on the
ket exceeded 600.
A deep well may encounter soluble minerals such as salt, anhydrite, or
;phates. These materials dissolve into mud, usually necessitating
addition of special chemicals to offset the effect of the dissolved
jrial. High temperatures of deep holes also necessitate the use of
:ial chemicals in the mud system. Portions of .all of these fluids and
•efore portions of everything used in the drilling fluid or on or about
rig will find its way into the sump. The final fluid may then contain:
*Chief Chemist, Energy Resources Conservation Board, University of
rta, Edmonton, Alberta, Canada.
463
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(a) bentonites, drilled shales and minerals such as salt and
anhydri te;
(b) formation fluids such as brines or crude oil;
(c) Mud additives such as:
(1) thinners like quebracho, tannins, lignins, and sulphon-
ates;
(2) viscosifiers such as carboxymethylcellulose;
(3) emulsifiers like detergents and soaps;
(4) completion chemicals such as frac-fluids and acids;
(5) coagulants like the polyacrylamides;
(6) emulsified oil - crude oil or asphalt or diesel;
(7) special chemicals for drilling mineral beds;
(8) chemicals to stabilize emulsions;
(9) chemicals to decrease heat susceptibility;
(10) preservatives like Dowicide 6 and formaldehyde.
(d) rig wash compounds, and housekeeping chemicals;
(e) yard drainage, and spills of lubricating oils, diesel fuel,
glycol, etc.;
(f) drilled cement, accompanied by chemicals used to minimize the
effect of cement on drilling fluids.
SUMP FLUID TOXICITY
Experimental work done at the Energy Resources Conservation Board
Laboratory indicates that many of the chemicals used in drilling fluids
are toxic to plant and animal life. Some are synergistic with other
commonly used or frequently spilled compounds. Synergism is the ability
possessed by certain pairs of compounds such that they mutually cooperate
to produce an effect greater than the sum of the effects produced by each
component alone. A few of the materials used in drilling fluids are eithe
not toxic, or are only toxic in very high and seldom used concentrations.
A very few inorganic salts appear to be antisynergistic. The determina-
tion of all of the synergistic and antisynergistic effects of the millions
of possible combinations that could be produced by mixing some of the more
464
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than 600 additives would be inters, i,"^, h«* vi-tj3!iy I i.'jX.- •> s 1- 1^ ' " '••'• p5
duce. A number of the more impu^Um. ;,:-!"iX'<-e.>r<: «?k; aji<;bii'aj. -^r ^ 1,1
components have been testad in wau.1-' .J.-,IHM rairih.-^ Vo'a* bav" on '.i
tests the following generalization^ seno u> ;>e ironic-;.
(a) Some hydrocarbons such as -:;<', i-«,-u>i :or.
tests may not be iethal until the coiirwira' • ••> ;:•> ->''M 400
mg/1 ;
(b) Some detergents such ai; raj-wct:-f< ...^wpouncii. •
lethal at, fairly f?iyh cor'.'^.:'il^oU.:.'i, '
mixtures when qsiite 'Jik'U>.',
(d) Stable suspensions nf ••.-:/! 'c: J.- ! ,!'wu-«
of the drilling rnucO T?C i--iM; ; s,.-/ '
suffocate their;. The c'led*- '!.<•." -' ;:
suspensiofiS of 10 iDj/bi-J ; ''"," •
lethal to rainbow trout •?,•! 9-:- h-v,
(e) Diesel fuel from fuel sp;'.-. :i<-^ i.;-:vr: >e ;'.*;-,•'.:".)' , -:er»
upon the method uf ^ana^acmth , ;;dy !>'- /-.-"^ t*.-- ;•• .
(f) The clear water exrract.rd '•••wi- .j ;;: , :.-,(i",-v :*>.':, e.^H;h •. i'.i'i;-' •'•
used in drilling mud- :.\, i,:, i tox - i'i-r i..-;,. •• r!;c ••h-ri - .>5^'d
5 Ibs/bbl 04,285 i;].'j/u ;
(g) A particular brana of rtaje?^ • -.'ra ••'!•• K1..' ' ^.•-.>, -^ •',>•. :-.f,.hc:! *',
concentrations as low ^s '! w»/\, fhv< >:a.s ;jr;tv ps:M.f'<:_, v»v.e
sodium salts are not toxit; -)f, iou ,-0 nK;/; M " 5s '.IN?,., ;n :,i.,e,:id!
drillirsg muds;
(h) Ammonium phosphate and aw.or ii>n :;'.• ''••'. ule, whic:1; ,i;-e • M,;>, }"
drilling muds to inhibit ciay sv-e S •;:;:•. ..•'•.- ^/?L ,.-•>;-< ,^t '-.he
same low concentrator i !'.'-. .'.•(••.u ;t; De ',-/j:-f-':,'^'\ S",';CA- •?:!:!•." ,.f- >
is dangerous to ruobt ar^jrai •>••;• /, . tsv\'.> ''••••• • • •; et * :a . ;vm s
(less than 100 mg/1 ) i
(i) Many of the polyarry (amide b^ntw- 1: • !<;•. cu >!.r\i*> : *-;,ft''us"f ,
used in dv'illint/ fluids art no>v to> it ?•: iov. .:':"(>,'r,:^-;, r l;-_ri
(below 100 iny/i), 'Ih;% i - wv ! i w;;> ,., Ip-e ., f'^. r'^-s i1". ';/•.:.
»"
465
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(:,} unvosion inhibitors from drilling muds or packer tests are
(fciiefdlfy very toxic (in the same toxicity class as bacteriostats,
v.'Mds they resemble in structure);
\, toil hter'ISents and weed poisons used on the lease are often
very toxic to animals, being in the less than 1 mg/1 class;
(\] ^onse humic acid mud thinners are toxic at very low levels of
l cellulose used in drilling muds as a viscosifier
i.v water loss additive generally is not toxic until beyond the
!;Gr.i;ai u^aye, Concentration (possibly because food grades are
iikH'keted for use in drilling fluids);
Uiiiiin type liiud thinners tend to be less toxic than other
ttii liners (provided that they are tannins and not mixtures con-
ic* 1 fti ng other materi al s);
{•oud*yrade glyco'ls and some of their polymers, which could be
•,'Srd in special muds or as motor antifreeze, may be only very
toxic (20 Ibs/bbl or 57,140 mg/1);
of the polyethyleneoxy types of detergents or dispersants
HSubif in drilling fluids or as rig-wash compounds are only
%!ujhUy toxic, Some closely related compounds are quite toxic;
<) ^hjifiir-uni salts, trivalent metal salts, and alums, which may be
use! to clarify sumps, may produce a very toxic solution if the
l^ii is not carefully controlled. The result is that the metal
•>a\i Ihdt would normally precipitate will remain in solution;
Souse i icjiiobuipnouate mud thinners are toxic at concentrations
fcxce^ding 100 mg/1;
?>) Sotii« of the phosphoric acid ester dispersants, which could be
••iitiJ in tit'ii liny fluids or for rig-wash compounds, are toxic
above t'ht: 1U mg/1 level;
(t) Kit.e seed oil, which could be used to replace the more poisonous
uUs in drilling muds, is nearly nontoxic (provided that the
edible variety--low in erucic acid--is used, and that surface
aoi.ive ajents or detergents are absent);
466
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(u) The clear water extracted from barium sulphate
material is not toxic;
(v) Powdered gilsonite used in oil emulsion muds is no* *•*•'•'
concentrations below 0.33 Ib/bbl (about 1000 mg/I);
(w) Emulsion breakers used in muds seem to be v^ry k>xk, ir t
same class as some corrosion inhibitors and bart«> -ins* *?.$
may have similar structures;
(x) Sodium lauryl sulphonate used as a washing compound oro'/H'-
very toxic solutions at low concentrations,
SUMP FLUID DISPOSAL STANDARDS
As stated, sump fluids, since they contain the miH chenn'col-; as
as rig spills of diesel fuel, floor washing detergents, testing
and formation fluids, have a very good chance of being toxic, w
well is completed or abandoned, the sump fluids must be evaluab-ni
disposed of accordingly. Realizing the disposal problem, th*1 H^
Resources Conservation Board, the Department of Energy and N^ur-i
Durces, and the Department of the Environment,, all of the fYf.-< •
\lberta, have jointly developed requirements for- the treatmenr =,r
>sal of drilling sump fluids, directed toward minimi/in^
jnvironmental effects.
The requirements respecting the testing, treatment, and
'ell sump fluids have been developed although they are not yet
'hey will:
(a) Permit subsurface disposal to deeper formations that- arp not
locally commercially productive of oil or gas, and corita^; rv>
water having less than 20,000 ppm total dissolvp-r! sc!i.!--.
(b) Permit surface disposal to the lease, provided that l.'^- "< '.^1
volume for disposal is less than 6,000 tarreis, and t;-.<-'r. •!•><-
lease is more than 300 feet from a strea-n, lakr, •)> r- •;•• w*i-t-
water well. Disposal to certain leases may He p>-s>hioi ia-J AVP
if the preceding criteria are met, if in t.hp yf»w of thr i;ovA
ment representative the lease will not accept ::h>', dii":i-:> c,;
fluid without runoff, or the fluid may migrate <"m (h^'1 (•= i! "'
feet to a body of water or freash water WP!i ;
467
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',!i''itu)'.-,f5"i to the land surface provided that the
fVji.-!-, i\-f^i I'.'l'.ri ii:?•';•'', .*>•-; *han 2 ,'"'" -j mii/i of sulphate ion,
'.b/'y <•:•.'•"'•*,••-> >'•><-, ib»n 'KO1)'- mg/1 of total dissolved solids,
:,he pH ' " '• . S»« !.V'- '• "> h ;'"i\ R , 5 , a?id
iro"- v>r/H'f' ">'• hfc.ir^ "»n tb° clfar aerated fluid;
f :yki>n-,r= . (.-» -••unp :l-ri'l«; tc wate? only if suitable land
•.'.•^i'lU.- •;• M^r-cs- ; •' • .i*i,.,<•*• ,\ <=a, the approval of a repres-
^f^.ai. "••••' ••' !np I'pp"'--;.'^'-'', jiiV'/pr-iw ' Op|)-:rtm^nt is required before the
f !u iris ;>-\" IK- '!i ;.urjcd •,;<
'7";.' ->;-'t ' "•-. uT '.hn,>- -•:;?• sn''v/t^!>', find other dissolved solids on veg-
* >t;r- (.-I*t5" 1) The r.oncenhration limits set out
lA-r«'"'t >' "nw t* M^niiin'ze toxic effects on most
- ^n'-.vi--, -r* rhe effects on vegetation of the
junci -r: -.,,^10 il.ri'l^. Approval to dispose of
i--''-!..?' j;, 4:Nn ^im]Rct to passing a test using
.i >:.•.• .- ; , ha^f"! on the fact that even though
ijr'*1:.''^1, "5 (' may eventually find its way
i-(j a r>; ,,<.;-,! .•;< -j test species (ref, 1)
': ••.•, 'K's.f v^hich sump fluids may flow,
t>. ••ir,'tv,,-.. i'^.. iherrnore, rainbow trout
;• n ' ""•.' , '.-''•;
••-u; -('-,;,ova f . ;!;-••" s vt ! ; •>;•• -^», }.--v,Mi in on^ year. Further studies
t'. f •')-• ii-' •:,-!•.',•,!-." :.. .i/' •-•„">• 'h^ fffects r>f ^.uinp fluids on vege-
n ':|i' n.-o;u'\! n.'>^irp of bentonite, coupled witl
, ••.; .,; ;. ;.!.,;. of w,-,t^f- the •v.ump1? are almost
-------
never uniform in composition throughout. It is therefore neces-
sary to take many samples from various places at several depths.
Each of these samples will usually be found to have a quite dif-
ferent analysis, without any predictable chemical relationship
to the nearby sample. A composite sample should be taken,
mixed thoroughly, and then tested to determine certain key
parameters;
(b) Preparation of sample - Before analysis, the bentonite must be
flocculated so that a clear fluid can be obtained. If the
bentonite is left in suspension, chemical as well as biological
tests will be masked or changed. Generally the calcium ion
(from CaCl2 or CaSOj is effective in reducing the electrical
charge or Zeta potential, when followed by the addition of an
organic polyelectrolyte, which usually "tightens up the floe"
so that a clear fluid may be readily produced. Notes of the
amounts used to produce an acceptable sample should be kept so
that this information can be applied to determine the concentration
of chemicals needed to flocculate the sump fluid in the field;
(c) Chemical analysis - The clear fluid may now be analyzed to det-
ermine the pH, chloride, sulphate, and total dissolved solids.
If the criteria are met, disposal may proceed according to the
guidelines;
(d) Biological testing - While the chemical analysis is taking place,
another portion of clear fluid is subjected to testing with live
rainbow trout in accordance with sound testing procedures (ref. 2).
This is done because there is NO single chemical test or group
of chemical tests that will indicate whether a fluid is toxic
or not. A live animal will be influenced by i*s total environ-
ment, therefore testing the fluid with live trout should show
synergistic actions or other untoward total effects caused by
all the chemicals in the fluid. As testing sump fluids pro-
ceeds, there are two misconceptions which begin to be believed:
(1) The belief that if the pH is near 7 and the chloride ion
concentration is low, then the fluid is most likely to be
nontoxic. Few statements could be as wrong as this.
469
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(2) The belief that if trout survive the test for 4 days, then
the fluid is nontoxic. This is also incorrect. The fluid
may be judged as relatively nontoxic, since the fish did not
die quickly, but the test fish may actually die some time
later or be sterile;
(e) Treatment - The concentration of chemicals needed to flocculate
the sump fluid for the laboratory examination is now utilized
to predict a treatment for clarification of the sump fluid in
the field. This is then followed by a treatment of the sump
in the field that is specific to the type of poison most
probably causing the toxicity. Another paper will be given at
this symposium setting forth various precedures for field detox-
ification of poisonous sumps.
SUMMARY
Companies, as well as Government agencies, should work together to
insure that:
(a) Methods of recycling waste fluids be developed such that the
ideal situation of little or no waste water may eventually be
approached;
(b) The toxicity of all the chemicals used be evaluated in relation
to their effect on the environment;
(c) Alternative chemicals be developed which are less toxic than
those currently used;
(d) Methods of detoxifying effluents be evaluated such that each
situation can be effectively and cheaply dealt with;
(e) Samples of all effluents, whether they have been treated or not
be finally checked for toxicity prior to disposal by using some
species of live animal;
(f) Research and Development be encouraged by the surveillance arm
of the Government such that there is an incentive gain to
research. This could be managed via tax relief, but should
result in improved practices (i.e., reduction in volume of wast
water and/or development of more effective, less toxic chemical
470
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REFERENCES
Diagnosis and Improvement of Saline and Alkali Soils, Agriculture
Handbook No. 60, U.S. Department of Agriculture, U.S. Government
Printing Office, Washington, D.C. (p. 70, particularly).
Standard Methods for the Examination of Water and Waste Water.
13th Ed., 1971, American Public Health Association, 1015 Eighteenth
Street, N.W., Washington, D.C. 20036.
SCUSSION
. DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba, Canada): Could
you outline the methods that you use in your trout check?
. SHAW: I would prefer to say, find a determination of water and sewage
in Standard Methods for the Examination of Water and Waste Water
(ref. 2). It is covered on page 568, if I remember correctly.
I used an alternative, as specified there. I do not use,
generally speaking, 10 fish. There are reasons for it. I will go
into that quite deeply with you if you wish.
You see, the point is that what you wish to do is find an in-
dication. You are not concerned, by and large, with the TLM's and
your threshold limits and this kind of thing. I generally do not
head this way.
DONALD L. WHITFILL (Continental Oil Company, Ponca City, Oklahoma): With
the exception of, say, biocides, do you feel that turbidity, pH, and
conductivity tests could accomplish what you are shooting for there?
SHAW: Well, if you mean to tell you whether the material is toxic
or not, no, definitely not. I am sorry.
WHITFILL: This is what I was wondering about, because you pointed
out quite frequently that, normally, turbidity would give you some
idea about the bentonite; conductivity is going to give you some
idea about the total dissolved salts that are in there; and you pointed
out that pH by itself is not an indication, but that pH and conduc-
tivity together will give you quite a bit of information as far as salt
values.
471
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MR. SHAH: You could, for example, have a material that is nonionic in
nature and still exceedingly poisonous. If sugar were poisonous,
that would be an example, since it is a material that is nonionic
in nature.
So you cannot really correlate your toxicity to an ionic
structure, either conductivity or otherwise.
MR. WHITFILL: I feel this is quite true in most cases. But most of the
time we know what materials we are putting into a mud system.
MR. SHAH: Most of the time you think you know. I mean, I have had
several cases of sumps that were toxic and people say, "Oh, no, we
did not put any chemicals in." Then you begin checking and you find
out they used rig-wash chemicals that are extremely toxic.
MR. WHITFILL: Right. So you have to make the assumption that you do
know what you put in, for this sort of test.
MR. SHAW: Well, as you know, there are a lot of commercial materials
on the market that are patented or trade secret mixtures, and you
may know a major ingredient but very often you do not know the minor
ingredients, and they can often be the ones that are toxic.
MR. WHITFILL: Did I understand that you had 100 milligrams per liter
chloride maximum?
MR. SHAW: No. A thousand, I believe, was the rough rule of thumb, but
this is after the detoxification step and not prior to it.
472
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SOME BIOLOGICAL IMPACTS ON THE AQUATIC
ENVIRONMENT BY GEOTHERMAL ENERGY DEVELOPMENT
Max Katz, Ph.D.*
It seems that I was asked to give this talk because someone spotted
my name as chairman of the Biological Impacts Committee at a recent work-
shop on Environmental Aspects of Geothermal Resources Development (ref. 1).
I would like you to know that I accepted the chairmanship of that
:ommittee only after I was assured that I did not have to prepare a paper,
md did not have to give a talk. Nevertheless, here I am. I certainly do
lot wish to assume the position of an expert on the environmental impacts
)f geothermal development. I do not know anything special about the
n'ological aspects of geothermal development on aquatic organisms because
ly limited experience indicates that the environmental problems of geo-
hermal development are not unique. I do not want people to think that
eothermal energy development is opening a new bag of worms. It is not.
In fact, the only thing that is unique so far about the environmental
npacts of geothermal development, as far as I am concerned, is the nice
iaces that you get to work, and the rather spectacular views of steam
scaping from the various geological structures and artificial devices
lat you get to see. Instead of the typical soiled industrial development,
)U do your work in rather beautiful scenic areas and the unique environ-
ntal hazard that I have found is well-nourished rattlesnakes—which is
worthwhile trade-off if you are a rattlesnake fancier.
But to get back to the biological impacts of geothermal development,
want you to take note that our Committee on Biological Impacts at Ansi-
mar seemed to be the most vocal of all of the groups that participated
that workshop, because we came up with 21 real and imagined biological
oacts, while, for example, the Water Quality Committee came up with six
jblems, and the Air Quality group only four problems. There was, of
jrse, considerable overlap in problems and our committee listed all of
i problems included in the Water Quality Section.
*
Director of Research, Parametrix, Inc., Environmental Services
:tion, 4122 Stone Way North, Seattle, Washington 98103.
473
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Now of course you in the working world, as contrasted to the academic
or regulatory world, may feel that many if not most of the problems that
my committee listed among the biological impacts (ref. 1) were imaginary
or that we were making mountains out of molehills. Most of the
industrial people who participated in the workshop took this view in
regard to our list of biological impacts. They may not have been right,
but they were very sincere and vocal in their objections. On the other
hand, the conservationists accused our committee of overlooking and under-
playing the true hazards. Our committee felt, however, that if someone
of even modest competency thought that there was a problem in regard to
geothermal development, then it was a genuine problem, and should be so
listed and considered. This is actually a realistic approach because I,
and I am sure others of you, have found out that if a group of dedicated
and aroused environmentalists believe that a problem exists, then they
can create a climate of public opinion that has to be answered. If a
segment of the public believes that drilling will cause earthquakes or
will reactivate the dinosaurs, then all earthquakes therefore are a resull
of drilling, and we have to prepare for the dinosaurs, unless you can pro'
otherwise. Environmentalists and regulatory agencies are able to, and
have not been at all reluctant to stop projects for reasons that have
little or no scientific and technical validity—nonsense and: irrational it
are real factors in the environmental business and we had better not for-
get it--and it is mandatory that the energy developers come up with con-
vincing answers to their charges. This is part of the business.
Obviously, I do not have the time in this talk to go over all of the
21 biological impacts proposed by my committee at Ansilomar, which is fir
because I am not prepared to discuss on a professional level those probl*
other than the aquatic problems. And some of the aquatic problems are m
real enough in my opinion to be worthy of using this limited time for di:
cussion. When we get down to the potential aquatic problems of enough
timely importance or interest to be worth discussing, we find that these
problems are often not unique to geothermal development, but are common
to other industries and land uses. They have been studied, discussed, a
474
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fairly well understood and were under a degree of control well before
geothermal energy and its development became popular areas of concern
and discussion. Some of these concerns—for example, thermal discharges—
ire already under many sorts of strict controls at the Federal and State
levels. But I would like to see how State and Federal legislation can
:ompel a fumarole that has been discharging hot water for a hundred years or
lore in the bottom of a stream to cool down and start producing cool water.
Thermal Discharges
One of the first biological impacts considered by our committee
as the thermal effect of liquids discharged from the power site on
rganisms in the receiving waters. The effects of thermal discharges
rom industrial operations, thermonuclear and fossil fuel power plants,
ive been documented in a voluminous literature. Robert C. Axtmann, in
recent paper in Science (ref. 2), has documented thermal discharges
one of the major environmental impacts of the Waireki Geothermal Power
ant on the Waikato River in New Zealand. Incidentally, for those of
u in the regulatory agencies who would like to have a listing of most
the undesirable effects of geothermal development upon which to build
regulatory structure, I would suggest Axtmann as a good reference.
In my experience, the thermal impacts at The Geysers were from
naroles, hot springs, and warm soil in the bed of Big Sulphur Creek.
j Sulphur Creek drains most of the area in The Geysers development.
; thermal effects of these springs are evident primarily during the
f-flow periods of the summer and early fall, at which time the radiant
rgy addition from the sun is substantial. Water temperatures were
high for trout, while suckers and minnow species that preferred
her water temperatures were the predominant fish species and were pre-
t in large numbers.
In developments in which significant amounts of warm water are
Dived, the liquid discharged into surface waters may have to be cooled
neet the water quality criteria of the State and Federal agencies.
475
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Pi ssol ved Subs .tan ces
Another biological impact regarded as important by most members of
our workshop was the toxic effect (both lethal and sublethal) on aquatic
organisms of the dissolved mineral substances in condensates. These
condensates may vary in different developments from quite soft water to
supersaturated brines that precipitate as salts as they cool. These
salts can affect water quality considerably by changing the salinity,
affecting the pH, and by the toxic metals which might be present.
Axtmann (ref. 2) presents a table of the chemical discharges to the
Waikato River by the Waireki Geothermal Power Plant. It is presented here
as table 1.
Table 1. Chemical discharges to the Waikato River (ref. 2)
Constituent
Increment
in River
Concentration
(ppm)
Constituent
Increment
in River
Concentration
(ppm)
B
Li
Na
K
Rb
Cs
Mg
Ca
F
0.27
0.13
12
1.9
0.029
0.026
4.7 x 10
0.17
0.077
Cl
Br
I +
NH,+
soj
As4
Hg
Silica
29.8
0.055
0.0047
0.014
0.24
0.039
1.5 x 10-6
6.3
Axtmann (ref. 2) quotes a source that states that the geothermal plan
discharge supplies 75 percent of the arsenic input into the stream and
believes that a sizeable contribution of mercury to the river system is
supplied by the plant. Let me emphasize, Axtmann does not state that ther
are adverse biological effects due to mercury and arsenic. Mercury ore
deposits are frequently found in association with hot springs (ref. 3). 1
fact, abandoned mercury mines are characteristic of the area surrounding "
Geysers. For example, the metropolis of Mercuryville, population 2, is a
mark on the road between Santa Rosa, California, and The Geysers. Again,
476
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in a stream, and is readily measurable. A few parts per million of tur-
bidity is readily obvious, and is a temptation to enthusiasts to extra-
polate widely all sorts of biological impacts—real and imaginary. And
do not forget the general public usually chooses to select the wildest
imaginary impacts upon which to base its environmental activity.
I wish to make it clear that even at The Geysers, which has the
conditions conducive to erosion damage, that siltation due to erosion
is not a serious environmental impact. The impact there is the hot
springs and warmed ground that increase water temperatures in the vici-
nity of the stream.
Endangered Species
The last biological impact, and one that really concerns me, is the
effect on endangered species. This concerns me because I am an aquatic
biologist and I am an aquatic biologist because I like aquatic organisms
and I think that they are wonderful creatures and should be preserved.
We can get into a philosophical discussion, but I believe that the pre-
sence of a pond with an unusual array of bugs and fish contributes to my
conception of the quality of life and is as important to man as a tank
full of gasoline is for an automobile or the power to run a T.V. set.
And if we have to spend a few thousand dollars more or spend an hour more
of planning to preserve a little swamp that is one of the few remaining
homes of a rare organism, we should do so. I still think that life should
be worth living and interesting organisms are a part of that good life.
Thermal areas are marked often by warm ponds, hot springs, or other
unusual and unique environments which, over the centuries, develop an
interesting complex of animals and plants. These areas are often quite
small and few in number and quite unknown, except perhaps to the biolo-
gists in the closest college or State University. These habitats can
easily be destroyed by a few passes of a bulldozer blade. But they need
not be destroyed. They are local treasures and should be respected.
Destroying the small ecological treasure is often pure vandalism
and is not good development practice.
480
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Reinjection Waters
Another problem that was of real or potential significance was the
effect of reinjected water that might escape either by accident or by
poor engineering into the surface water and affect aquatic organisms.
It is a policy, I understand, to reinject moisture back into the
wells for good technical reasons. If the waste waters were injected
into formations from which they would not escape into surface water sup-
plies, then obviously, there would not be a biological problem. If the
reinjected waters were pumped into a formation from which they would
escape to surface water supplies, a problem of water quality affecting
aquatic Organisms might occur. Our group felt that this problem was
quite readily soluble by good engineering practices, and should not be
a problem in any project that utilizes such practices.
Erosion
The biological impacts of sedimentation arising from the erosion
from surfaces disturbed by the explorations and the geothermal develop-
ment is by far the most potentially disturbing of the problems that I
have observed. When roads and trails are built into previously undis-
turbed areas, when the ground is cleared and leveled, or when the land
is hilly or mountainous and is subjected to heavy seasonal rains, we
have a potential and a probability of soil washing into the streams and
causing problems which vary all the way from the esthetic to perhaps seri-
ous local disturbances of the stream bottom.
In my limited experience, the biological impact of soil erosion is a
major aquatic impact of geothermal development. Of course, my opinion
was formulated at The Geysers area, which is in the California coastal
mountains, and is characterized by a wet winter season and a dry summer
season. The erosion problem is compounded there by a serious overgrazing
situation.
Erosion and its biological effects, as seen at The Geysers, would not b
as great a problem in more level terrain or in a drier climate or a less agr
culturally abused area. Fortunately, or unfortunately—depending on the sid
of the fence you are on—the trubidity resulting from erosion is quite visib
479
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obviously being taken quite seriously by the present meetings. None of
the speakers on the present program were on my workshop panel at Ansilo-
mar and none of my panel, to my knowledge, presumes to an expertise that
is equal to that of the speakers at this meeting. Our panel was concerned
with the problem of the safe disposal of drilling muds and insuring that
they were not discharged advertently or inadvertently into the waterways.
They presented some recommended approaches to solving the environmental
problems of drilling muds. These recommendations were (ref. 1):
1) As part of the planning for the exploration and development
of the field, provisions should be made for the safe disposal
and removal of drilling muds.
2) During the operation, care should be made to insure that the
waste drilling products are retained and stored in the areas
cleared for the drilling operation, or in an area where they
can be watched and accounted for and where the chance of their
being discharged into a water supply is slight or impossible.
3) Many of the drilling muds have components that are toxic to
aquatic organisms. The composition of the drilling muds should
be known to some responsible person so that the toxicity can be
predicted. It should be possible perhaps to select from several
drilling preparations one or two nontoxic muds that could be
used to do the job in an area where there are many productive
lakes and streams.
4) In areas in which there are few lakes and streams and where
accidental discharges will have minimum aquatic effects, the
choice of drilling substances qould be based on mechanical
efficiency and cost.
A laboratory research effort could be directed to determine the com-
ponent and components toxic to aquatic organisms of interest. Changes in
formulation and substitution of less toxic components might be made to
reduce the toxicity and to confine effects of physical stresses, e.g.,
siltation and sedimentation.
478
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me emphasize, we often find geothermal sources where we find mercury
ore deposits. Geothermal development does not produce mercury or util-
ize mercury; it is already there.
The presence of substances such as arsenic and mercury, regarded
to be deleterious to aquatic organisms, is of interest, but should not
be a serious problem unless someone wishes to make it so.
Even if an agency should decide the mercury or arsenic content is
unduly high in fish residing in a stream or receiving water, one,could
simply classify the stream or lake as a trophy fish stream. One then
would be allowed to fish, but would not be allowed to keep the fish taken.
With the reduced mortality and the reduced patronage of the "meat" fisher-
men, the stream would become a habitat for large fish and would be more
popular than before and would be regarded as a superior recreational
asset. The management of streams and lakes as trophy fish sources is
an accepted management practice in Washington State and other places.
pH Changes or Acid Water
Although our panel believed that there was only a slight chance of
this occurrence, we discussed the possibility of acid rain as a result
of geothermal development. The better chemists on my committee felt
that it is possible that the H2S that is often part of the vapors in
thermal areas could oxidize to S03» and then would fall as H2S04 in
the rain. This precipitation might possibly lend to the acidification
of lakes and streams, especially if the streams were slightly buffered,
as are many of the lakes and streams in our coastal mountains. Acidifi-
cation of lakes and streams is documented by Brosset (ref. 4) in Sweden,
and by Beamish and Harvey (ref. 5) in Canada. There is no documentation
that this has happened as a result of geothermal activity. The Canadian
experience is a result of smelter operations in Ontario, and is not due
to a geothermal development.
Effects of Drilling Substances on Aquatic Organisms
The toxic effects of drilling substances on aquatic organisms is a
problem that was taken quite seriously by members of my panel, and is
477
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REFERENCES
1. D. N. Anderson and R. 6. Bowen, Proceedings: Workshop on Environ-
nental Aspects of Geothermal Resources Development, State of Cali-
fornia, Department of Conservation, Division of Oil and Gas, State
of Oregon, Department of Geo. and Mineral Ind., Nat'l Science Foun-
dation, Grant No. AER 75-06872, 1974, 123 pp.
?. R. C. Axtmann, "Environmental Impact of a Geothermal Power Plant,"
Science. Vol. 187, No. 4179 (March 7, 1973), 1975, pp. 795-803.
3. D. E. White, M. E. Hinkle, and I. Barnes, "Mercury Contents of
Natural Thermal and Mineral Fluids," Mercury in the Environment,
U.S. Geological Survey Professional Paper 713, U.S. Government
Printing Office, Washington, D.C., 1970,. pp. 25-28.
4. C. Brosset, "Air-borne Acid," Ambio. Vol. 2, (1973), pp. 2-9.
5. R. J. Beamish, and H. H. Harvey, "Acidification of the LaCloche
Mountain Lakes, Ontario, and Resulting Fish Mortalities," Jour.
Fish. Res. Bd., Canada, Vol. 29, 1972, pp. 1131-1143.
DISCUSSION
MR. DONALD W. HECKER (Union Oil Company of California, Los Angeles, Cali-
fornia): Max, you mentioned the Science paper which goes into the
environmental effects of condensate and discharges into streams. I
think we should mention here that this particular problem is nonexis-
tent in the United States because the U.S. geothermal industry has
made a standard practice of the reinjection of all of the condensates
from our geothermal operations.
DR. KATZ: Good.
481
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DISCUSSION
CHAIRMAN GIAM: Earlier in the day there were a few questions (during
individual lectures) that we could not answer due to lack of time.
If the questioners are still here, I think we can entertain those
questions.
DR. CHARLES F. JELINEK (Food & Drug Administration, Washington, D.C.):
I wanted to ask one question. I do not know if anyone has the
answer that would help put into perspective this question about pen-
tachlorophenol and whether it might form dioxins under conditions
in oil fields. Does anyone here know how many pounds or hundreds
of thousands of pounds of chlorinated phenols are used in oil field
operations? I think that would do a lot to tell us whether this
might really be a problem or not.
MR. HARRY L. HARRISON (A C Drilling Specialties, Odessa, Texas): I am
not at all an expert on chlorinated phenols, but these materials
are used as preservatives in the sack mud. When it is used in the
field, it is used in the sack in concentrations of less than one
percent.
When you put the chlorinated phenols in the mud system, they
go way down and, consequently, in the overall system the level is
very low. I have no numbers on this, but it would be low to begin
wi th.
:WURMAN GIAM: Would you think it is in the parts per billion range?
IR. HARRISON: No, I would not go quite that low.
I understand these compounds are quite susceptible to calcium
and precipitate. Calcium is a problem in any drilling system, at
least those in West Texas and Southeastern New Mexico; and it is
something that we have not gone into here. We always are drilling
into the calcium deposits and have calcium counts in mud that run
up to 5,000 to 6,000 parts per million.
L WALTER J. WEISS (Texaco Incorporated, Bellair, Texas): The chlorin-
ated phenols are used to preserve the gum type of fluids. They are
usually used at about 300 parts per million, and that level is
recommended in the formulation.
483
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CHAIRMAN GIAM; (Comments refer to the possibility of a dioxin being
produced in drilling fluids or muds during drilling operations
at high temperatures.) I am suggesting that a well resembles a
reaction pot. For example, let us find out if the ingredients
such as phenol and sodium hydroxide for salt (pentachlorophenol)
formation are there. If these ingredients are there—in the parts
per million range—I would like you to consider the following:
First, you should do some research and find out what the yield
under these conditions is. If the yield is 50 percent or 30 per-
cent, you are still in the parts per million range of this dioxin.
If indeed that is true, then the next question you have to ask your-
self is how much of this mud with parts per million you are dumping?
Where are you dumping the mud? What are the species that are eating
it? And will these species that are eating the phenols, the dioxin,
be ultimately consumed by man?
If answers to these questions are all yes, then I strongly sug-
gest that you look into dioxin formation very seriously because you
may have a problem that at one time 245-T was not acceptable. I
believe one of the problems of 245-T was the fact that toxic benzo-
dioxin was present in parts per million. Please remember, I said
all the ifs. I am not suggesting that dioxin is present. I am sure
all of you would want to make sure that dioxin is not present. So I
hope I made my statement very clear. I do not know whether your
question has been answered, Dr. Jelinek.
DR. JELINEK; No. Actually, what I wanted to know is how many hundreds
of thousands of pounds of pentachlorophenol are used in the whole
United States in well operations, to help put this in the proper con-
text.
MR. FRANK J. SHELL (Phillips Petroleum Company, Bartlesville, Oklahoma):
I think it depends partly on where the material is used rather than
how much is used. We do not use pentachlorophenol in a hot part of
484
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the hole where a dioxin reaction would take place. This material
is always used in the upper part of the hole. We have no reason
to use it in the lower part of the hole and so we do not. We for-
get sometimes that the Lord made this universe, and He protects
us even if we are not wise enough ourselves. And I think He has
built in certain safeguards, like not letting man use a material
like that where it would get him in trouble.
CHAIRMAN GIAM: Probably, by alerting people like us to watch over our-
selves. That is one possibility.
DR. KATZ; The pentachlorophenol has been used by the Japanese as part
of their pond culture of fish. I do not remember exactly the pro-
cedure, but I think the pentachlorophenol is introduced to kill the
algae. After a couple of days, the pentachlorophenol breaks down
in the sunlight. The Japanese then planted carp and away they
would go, and they would harvest and market them when they got large
enough. This is apparently a fairly well-accepted procedure there.
Whether it is good or bad, who knows. It is better than dying of
starvation, but it shows that pentachlorophenol and fish can get
along if used correctly.
Another point I would like to bring up. All the time during
this meeting you talked about the 13th Edition of the American Public
Health Association in regard to the toxicity bioassay methods. I am
not saying it is an injustice, but I would like to call your atten-
tion to the fact that these toxicity bioassay methods were developed
by Dr. Peter Doudoroff. Some of you people may have it in your
company's library—it is a Hart, Doudoroff, and Greenbank book that
came out in J9S& or 1944. Pete Doudoroff headed the committee, in
about 1950, of the Water Pollution Control Federation group that set
up the toxicity bioassay methods used today. These procedures have
been used again and again under many names, and Pete has been res-
ponsible for, you might say, nursemaiding this baby of his into the
Standard Methods. To his great horror and disgust, everybody uses
them incorrectly, but then that is not Pete's fault.
485
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MR. J. P. SIMPSON (Baroid Division, N L Industries, Inc., Houston, Texas):
I do not have an exact figure to give you on tonnage or poundage, but
it is more in the range of poundage.
I would perhaps put it in perspective, though, by saying one mud
out of a thousand might use pentachlorophenol and it might be closer
to one in 10,000.
CHAIRMAN GIAM: Well, one good point, perhaps, that came out of this
morning's off-the-cuff remark was I was talking with a gentleman
from Dresser.
I had been informed that you do not have to use pentachloro-
phene if, indeed, in that reaction they found dioxins. You could
use, say, formaldehyde.
MR. GERALD A. SPECKEN (Wilson Mud Service, Limited, Edmonton, Alberta):
For what it is worth, I believe that pentachlorophenol is one of
those compounds that on a trout bioassay would kill in about a part
per million range. You can treat fluids for land surface disposal
so that they pass these kinds of bioassays. Perhaps the significant
thing is whether soil bacteria will decompose them when spread to the
land, and I think that applies to any drilling fluid compound. But
if you can remove them from the fluid when you dispose of the fluid,
why can they not be used? What is the difference?
CHAIRMAN GIAM: If there are no more questions, I would like to thank all
of you for your patience. I would like to thank Dr. Fisher.
486
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23 May 1975
Session III:
ENVIRONMENTAL IMPACT OF
THE BYPRODUCTS OF WELL DRILLING
Pat M. Wennekens, Ph.D.*
Chairman
"Oceanographer, Alaska Department of Fish and Game, Anchorage, Alaska.
487
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SESSION INTRODUCTION
Pat M. Wennekens,
Session Chairman
This morning's session has proved to be a very interesting session.
low that we know or we suspect what some of the waste material might be that
s introduced into drilling fluid, the question becomes, "What do you do
ith such fluids once you do not want them anymore, and how do you handle
nem?"
The papers that are going to be presented will address themselves
) this very germane problem.
We are faced with this very problem in Alaska, as in any place else.
ie of the main features that I think needs to be really improved upon; we
st do much better planning for it. In many instances we do not want the
ste released into a certain place nor do we want a waste treated in a
rtain way; but the problem remains—it has to be put somewhere. Unless we
eat the problem as a total package—a total problem of waste handling—
2 problems of control handling, the method of disposal, and proper siting
disposal areas become a very crucial portion of the environmental planning
1 programs for this material.
My strong recommendation again is that we must look at a total package.
489
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THE HANDLING AND TREATING OF
WATER-BASED DRILLING MUDS
Robert B. All red*
Abstract
In the process of drilling most wells, a thixotropic colloidal suspen-
sion with water as the continuous phase is used to remove cuttings from
the bore hole. This suspension is continually circulated during drilling
operations from surface tanks down the drill pipe, out the nozzles of the
bit, and back to the surface in the annular space between the drill pipe
ind the casing or open hole.
At the surface the unwanted solids, gases, and liquids are removed
from the drilling fluid with specialized equipment. Discharged solid and
'.iquid materials are either stored in holding tanks or reserve pits.
'•ases are properly disposed of at the well site. Contaminants and physical
roperty defects are treated with various chemicals so that the drilling
luid is in suitable condition to make another trip down the hole.
Under normal conditions, drilling fluids are free from toxic proper-
ies, and spillage on personnel results in only momentary inconvenience.
?oper washing of the derrick floor and walkways and other regular good
~>usekeeping practices are the only precautions necessary in handling the
Billing fluid. When high pH drilling fluids are used or toxic contami-
'.nts are encountered, special procedures are followed to insure the safety
* personnel and the protection of the environment.
The advent of rotary drilling brought about the use of clay and
ter as a drilling fluid as early as the Lucas well at Spindletop in
01 (ref. 1). Over the years, drilling fluid has developed from muddy
ter into a thixotropic colloidal suspension capable of removing cut-
igs from the bore hole, cooling and lubricating the drill pipe and bit,
Iding back formation pressures, and increasing penetration rate (ref. 2).
It is worthwhile to consider the nucleus of the colloidal suspension,
*Supervisor, Drilling Fluids Section, Production Service Laboratory,
Oil Company, Richardson, Texas.
491
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a hydratable clay (in most cases a Wyoming sodium bentom'te), which pro-
duces the property of thixotropy. Thixotropy is the property enabling
certain colloidal gels to liquify when agitated and then to return to the
jelly-like form when at rest. The drilling fluid is pumped down the drill
pipe and sprayed out the bit nozzles, spearheading the grinding action of
the bit. On its return to the surface, the velocity of the fluid is less
than on the trip down the drill pipe, mainly due to the larger size of
the annul us, the space between the drill pipe and the casing or open
hole. The reduced velocity allows the formation of the colloidal gels,
which suspend the cuttings produced by the bit and carry them to the
surface. The gels are more intense when the fluid is in a static con-
dition; therefore, if pumping is discontinued, the cuttings will remain
in suspension and not fall to the bottom of the bore hole. In some wells
(in order to overcome formation pressures) barite, barium sulfate, is
added to the drilling fluid so that a density of up to 20 Ibs/gal may be
obtained. The barite is also suspended by the clay particles.
A drilling fluid contains solids, liquids, and sometimes gases.
There are two types of solids with a variation of sizes: the wanted ones
colloidal solids, clays (0-2 microns) and weight material (barites)
(1-60 microns); and the unwanted ones - drilled solids, silts (2-74
microns), sands (>74 microns), limestones, anhydrites, and other contam-
inants (ref. 3). The continuous liquid phase is water, which varies from
fresh to saturated salt. In nonrestrictive areas, some drilling fluids
carry 2 to 10 percent emulsified oil, diesel, or crude. In some wells, ui
wanted gases (some contain hydrocarbons or hydrogen sulfide) may be defusi
into the mud system. See figure 1 for an overview of the circulating sys
tern.
When the drilling fluid comes to the surface, the unwanted constitu-
ents are removed by different methods of separation. The gas (hydrocarbo
not entrained in the drilling fluid is removed by flowing all of the mud
through a mud-gas separator inserted in the flowline between the casing
annulus and the screening machine. The mud-gas separator, as shown in
figure 2, is usually a large-diameter pipe with interior baffles to slow
down the mud stream. This permits the gas to go out the top and the mud
492
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SWIVEL
4IXING
TANK
^KELLY
UCTION TANK
CENTRIFUGE
DESILTER
DRILL PIPE
ANNULUS
DRILL COLLAR
BOREHOLE
BIT
Figure 1. Components of a flufd circulating system.
493
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S-
o
•«->
-------
to go out the bottom. The gas is then piped from the top of the separator
and safely vented away from the rig to a flare pit where it may be burned
if necessary.
A recent addition to the "Notice of Lessees and Operators of Federal
Dil and Gas Leases in the Outer Continental Shelf, Gulf of Mexico Area on
tydrogen Sulfide in Drilling Operations" states that: "Drilling mud con-
taining H~S gas shall be degassed at the optimum location for the particu-
ar rig configuration employed. The gases so removed shall be piped into
closed flare system and burned at a suitable remote stack." It also
resents new orders on the handling of gas that is circulated to the sur-
ace when killing a well. The order states that: "The disposal of HpS
nd other gases shall be through pressured or atmospheric mud-gas separator
quipment, depending on volume and pressure of HpS gas. The equipment
nail be designed to recover drilling mud and to vent to the atmosphere
id burn the gases separated." From the mud-gas separator the drilling
uid goes to the screening machine, thus beginning solids separation.
Vibrating screening machines come in many different sizes and con-
gurations with any number of screens. A triple-deck screening machine
shown in figure 3. Most of the modern machines shake or vibrate in
me manner and use sieves so that the liquid will go through the sieves
d into the sand trap. The sieve sizes vary from 10 to 80 mesh. Thus,
is possible to remove all particles greater than 178 microns depend-
3 on the sieve size. The solids will remain on the screens and be
msported off the screens and out of the mud system into the discharge
:. The screens are horizontal, sloped, stacked, or a combination of
;se. The screening machines are planned so that the greatest amount
solids (depending upon the particle size and amount of solids plus the
culating rate) will be removed from the mud stream. Although efforts
made to lessen it, some water is removed from the mud stream along
h the solids by the screening machines. Vibrating the screens helps re-
e the water from the solids. Backing fine screens with coarse screens,
that a wicking effect can take place, also removes water from the solids.
The mud falls through the screens and into settling tanks. Settling
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en
496
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jllowed to be in a near static or static condition so that large and/or
leavy particles will have an opportunity to drop out of the drilling fluid.
"he size of the tanks depends on available space and equipment. Sand
raps in the active system should have sloping bottoms so that they may
e easily cleaned (ref. 4).
After leaving the sand traps, the drilling fluid is pumped into the
egassing or desanding and desilting compartments. If the drilling fluid
jes contain entrained gas (hydrocarbon), it goes through a degasser prior
) entering the desander or desilter. There are many types of degassers,
II of which spread the mud as thinly as possible on some surface permitting
le entrained gas to migrate out of the mud. The gas is removed by a vacuum
imp or other depressuring device and vented away from the drilling rig.
e such degasser is shown in figure 4.
Desanding and desilting are done by the use of hydrocyclones, the type
solid removed depending upon the size of hydrocyclone used. Desanders
2 usually 6-inch to 12-inch cyclones that can remove particle sizes of
microns and larger. Desilters are usually 4-inch cyclones that can re-
'e particle sizes of 15 microns and larger. The number of cones used
tuld be dependent upon the maximum volume of mud circulated during the
11 ing of the well.
In a hydrocyclone as illustrated in figure 5, pressure energy is
verted into centrifugal force by tangentially feeding the drilling
id into a conical vessel. The centrifugal forces developed multiply
settling velocity of the larger suspended solids, driving them outward
ird the conical wall and downward to the solids discharge point at the
;om of the cone and out to the discharge pit (ref. 5). Each solid
:icle is coated by water as it leaves the bottom of the hydrocyclone.
water phase and smaller particles of the mud, being lighter, move in-
ly and upwardly as a spiral ing vortex to be discharged at the top of
cone and reenter the mud system. After being desilted, the drilling
d can now be centrifuged.
There are different types of centrifuges, but they basically produce
same results and operate from the same principles of separation
. 6). They are capable of separating particle sizes from 2 to 9 microns
the larger particle sizes. A decanting centrifuge is shown in figure 6.
497
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Mud is diluted with water as it enters the centrifuge to reduce vis-
cosity and allow efficient separation of solids. As the diluted slurry is
rotated by the machine, G forces of 800 to 1,000 are produced, driving the
larger and heavier particles to the outside of the bowl where they are
conveyed to the coarse solids discharge. The fluid and smaller, lighter
particles stay in the inside of the bowl and are conveyed to the liquid
discharge. Depending upon which stream carries the desired solids or
liquids, one is returned to the mud system while the other goes to the
waste pit. If a high-density fluid is processed, the larger, heavier
solids are mostly barite and they are returned to the active system, while
the liquid phase containing viscosity-producing colloidal solids is dis-
carded to the waste pit. However, in an unweighted polymer fluid, the
liquid discharge carrying the expensive polymer is returned to the mud
system while the solids, mostly drilled solids, are discarded. Centrifuging
is the last stage of solids removal, so the drilling fluid then goes to the
:hemical treating tanks.
The drilling fluid is treated with chemicals so that viscosity, gel
trengths, and density are of correct values. At this point, the afore-
entioned drilling fluid functions and efficient removal of solids and
ases can be performed. Flocculating drilled solids with calcium compounds
r polymers in particular mud types are also used to improve efficiency
f solids removal (ref. 7). If poisonous hydrogen sulfide gas is encounter-
d, it is chemically neutralized and not allowed to leave the mud as a gas.
iter-base drilling fluids themselves are usually not harmful to humans
*ef. 6). However, when the drilling fluid is being prepared or chemicals
Ided for maintenance purposes, precautions are taken in the handling of
mcentrated compounds. Goggles, gloves, and breathing apparatus are used
the mixing hoppers. Neutralizing solutions are placed in strategic
eas so that harmful effects from the chemicals can be avoided.
Once drilling fluids are mixed, only basic good housekeeping practices
d precautions are necessary in handling the drilling fluid. The lubricat-
g qualities of mud may cause the drilling floor and walk to become hazard-
s. Continuous washing of the areas where the mud is spilled insures safe
;sage. The use of high-alkalinity muds requires added flushing precautions
i the use of neutralizing solutions by the crew.
501
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Removed solids are usually diluted with water before they are dumped
into the waste pit. If harmful chemicals such as high-alkaline compounds 01
oil are used in the drilling fluids, special handling of the removed cuttin<
is required.
Training is conducted at the wellsite on the proper handling of danger
ous drilling fluids and their component parts.
Proper drilling fluid management requires great care in the mixing,
handling, and use of the fluid components to protect the health and safety
of the employee and to safeguard the environment.
REFERENCES
1. Walter F. Rogers, Composition and Properties of Oil Well Drilling
Fluids, third edition, Gulf Publishing Company, Houston, Texas,
1963.
2. P. L. Moore and F. W. Cole, Drilling Operations Manual, Petroleum
Publishing Company, Tulsa, Oklahoma, 1965.
3. API Bulletin on Drilling Fluids Processing Equipment, American Petro-
leum Institute, Dallas, Texas, 1974.
4. George S. Ormsby, "Correction of Common Errors in Drilled Solids
Removal Systems," Second Adriatic Symposium on Oil Well Drilling,
Porec, Yugoslavia, 1973.
5. "Solid-Liquid/Liquid-Liquid Separation Equipment," Pioneer Centri-
fuging Company, Houston, Texas, 1975.
6. Principles of Drilling Fluid Control, twelfth edition, Petroleum
Extension Service, The University of Texas, Austin, Texas, 1969.
7. "How to Reduce Fine Mud Solids for Better Drilling," The Oil and Gas
Journal. Vol. 63, No. 12 (March 1965), pp. 74-77.
DISCUSSION
CHAIRMAN WENNEKENS: What do you do with this colloidal material? The
colloidal material might be a carrier of a lot of the toxic frac-
tions. And I was wondering if you had any thoughts on that.
MR. ALLRED: I will tell you what we do with it.
If we remove the colloidal material with a centrifuge, it is
cut with water, and it goes to the reserve pit of the waste areas,
where we throw it away. We remove it from the drilling fluid.
If it is, as I pointed out, a polymer or something that we wan
to keep, we keep it in the drilling fluid, because the drilling flu
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is a colloidal suspension; we certainly need the colloidal solids that
are in there. But sometimes in the process of removing some solids
we have to remove those that we also would like to keep.
MR. GEORGE H. HOLLIDAY (Shell Oil Company, Houston, Texas): Dr. Wennekens, I
was rather intrigued by a comment that was made by Dr. Fisher a couple of
minutes ago about the work that you had done in Alaska in looking at the
environment. And I wonder if you might permit me to ask what field evi-
dence you have found of any environmental damage as a result of the
drilling operations in the marine environment of Alaska?
HAIRMAN WENNEKENS: I do not know if this is germane to answer this at this
particular moment, but for those who are interested I will be glad to
sit down at lunchtime and have a discussion about that. At this par-
ticular time, with the schedule we have, I do not think I can really
respond on this. So if you could wait, I will.
t. HOLLIDAY: Yes. Do you have any evidence?
IAIRMAN WENNEKENS: Evidence of what?
. HOLLIDAY: Of damage to the marine environment in Alaska from drilling
fluids, drilling operations? Just a yes or no will do fine.
AIRMAN WENNEKENS: I will say, at the present time, I will defer that
answer until —
. HOLLIDAY: Yes is shorter than deferring.
\IRMAN WENNEKENS: Well, the problem is, what do we call damage and what
do we call evidence?
HOLLIDAY: I will be delighted to have you define it, sir.
IRMAN WENNEKENS: Well, it takes more than just a yes or no answer on
this.
HQLLIDAY: Thank you.
DENNIS G. WRIGHT (Environment Canada, Winnipeg, Manitoba, Canada):
If solids removal equipment was 100 percent efficient, there would not be
any need to use the vast quantities of drilling fluids that you do use in
a hole; you could probably get by with that which is in the active mud
system. Could you comment on this, please?
ALLRED: Well, you are asking for something that is almost impossible.
You have to remember that during the surface hole we are removing
between 5 and 10 tons of materials per hour.
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Yes, if the efficiency were 100 percent, I imagine you could.
We try to make it as accurate as we can, but we do not have those
types of machines.
It is a good point. I wish we had that type of equipment but,
unfortunately, we do not.
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HANDLING AND TREATMENT
OF OIL-BASE DRILLING MUDS
W. C. McMordie, Jr., Ph.D.*
Abstract
Oil-base drilling fluids are specialized muds which account
for 5-10 percent of the total mud usage. They are used for produc-
tivity and in drilling operations in which water-base muds do not
perform satisfactorily. Oil-based muds contain diesel oil, inorganic
solids, surface active agents, asphalt, and water. Rig site handling
is a two-part problem—treatment of mud and treatment of cuttings.
Vud is contained in a closed system during drilling operations, then
"eturned to the mud plant. Methods of handling and treatment of cut-
tings are: (1) containerize all cuttings and return to mud plant for
authorized disposal, (2) wash cuttings, and (3) burn oil from cuttings.
Descriptions of these methods are presented.
INTRODUCTION
Oil-base drilling fluids are specialized muds which have been in
Dmmercial use for 33 years. Originally, they were used as completion
luids to obtain greater recovery of petroleum from water-sensitive
Deducing formations. The advantage of oil-base completion fluids for
lese productivity applications has been verified by the Bureau of Mines
1-base drilling muds are stable at high temperatures and do not react
th the formation. Because of these .properties, oil-base muds have
so been accepted as drilling fluids for high temperature wells, acid
s areas, water-sensitive shale, and salt drilling. Since oil-base
uids provide protection against corrosion, they are used as a protec-
/e pack for casing. Another major use of oil-base drilling muds is
jeing drill pipe stuck in water-base drilling mud. Oil-base muds
:ount for 5-10 percent of the total mud usage.
*
Director, Research and Development, Oil Base, Inc., Houston, Texas
127.
505
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COMPOSITION
Basically, oil-base drilling muds are a suspension of oleophilic
colloids in a continuous diesel oil phase. Barite is used to adjust
the mud density. -Surface active agents are added to emulsify water
and oil-wet the barite and drill cuttings. Each mud company has
proprietary formulations for its oil-base drilling muds. Neverthe-
less, some generalizations concerning compositions are possible.
The oleophilic colloids function as viscosifiers, gelling agents,
and filtration control additives. Examples of these colloids are air-
blown asphalt, emulsifed water, and quaternary ammonium-substituted
clays. The water-in-oil emulsifiers generally used are oil soluble
calcium soaps of fatty acids, naphthenic acid, and/or tall oil acids.
Modified fatty amines, polyethoxylated compounds, and sodium sulfo-
nates are examples of the dispersing surfactants that oil-wet barite and
drill solids. Many oil-base muds contain hydrated lime which is used
for the in situ formation of the calcium soap and as an acid gas
scavenger.
HANDLING AND TREATMENT
Modern drilling rigs are equipped to protect the environment and
conserve mud. Catch pans are placed under the rig floor and the drill
pipe rack. A valve is placed in the top of the drill string so that
spillage will be minimized when additional lengths of pipe are added
and when the drill string is pulled out of the hole. Oil-absorbant
materials are used to clean up any minor spillage. Oil-resistant
pipe wipers are used to clean the outside surface of the drill pipe.
These precautions are taken so that the drilling fluid can be contained
in a closed system.
Oil-base drilling mud is normally delivered as bulk liquid mud
in tank trucks or boats. At the rig site, the liquid oil-base drilling
mud is pumped through oil-resistant hoses into steel mud pits. Catch
pans are used at connections. Usually, water-based drilling fluids are
506
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used to drill the upper part of the well. Therefore, the water-base
mud in the hole must be displaced in order to drill with oil-base
rnud. During the displacement operation, a water-oil interface is
obtained. The interface is pumped into a standby truck or boat and
transported to the mud plant for authorized disposal.
As drilling begins, mud is circulated through the hole to bring
the drill cuttings to the surface. The treatment of oil-base dril-
ling muds now becomes a two-part operation—handling of the mud and
handling of the drill cuttings. The mud and cuttings are allowed to
flow over a shaker in order to obtain an efficient separation. It is
imperative that a high-speed multiscreen shaker be used so that the
maximum amount of mud can be removed from the surface of the cuttings.
Unlike water muds, oil muds do not make mud from drill solids. There-
fore, the volume of the oil-base mud does not increase during the
drilling operation. In fact, as new hole is made, mud must be added
to maintain the necessary volume. While circulating mud is in the
pits, colloids, surfactants, and/or diesel oil are added, if required,
to maintain the mud properties.
In addition to the antipollution regulations, there is a strong
economic reason to keep oil mud contained. Economics have caused con-
servation of oil-base drilling mud long before the national concern
over environmental protection. An oil-base mud system can cost over
$100,000. However, after the well is completed, oil-base drilling
muds are returned for credit. Thus the apparent high initial cost can
be substantially reduced by careful handling practices.
Upon completion of the well, a portion of the oil-base mud is
gelled and left in the hole as protection for the casing. The remain-
ing mud is removed from the drill site and returned to the mud plant.
The returned mud is treated, if necessary, and then reused.
The environmental problem with oil-base drilling muds arises from
lisposal of the cuttings, since an oil coating remains on the solids.
n drilling 100 feet of 8-1/2 inch hole, 40 cubic feet of drill cuttings
'ay be generated. As a rule of thumb, this volume of cuttings will be
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contaminated with 20 cubic feet of oil-base mud. Therefore, the han-
dling problem with cuttings is the removal of oil from a nontoxic solid
so that the environment remains free from contamination.
The handling and treatment of cuttings will be determined by the
location of the well. On land locations, cuttings are collected in
an area that is protected by an earthen dam. After the drilling is
completed, cuttings are buried or burned in an approved area. For in-
land waters, cuttings are collected in a gondola barge. On completion
of the well, the barge is towed to shore and the cuttings are disposed
of in an approved area.
Three methods have been used to handle cuttings on offshore rigs--
burning, cleaning, and collecting. Burning removes all hydrocarbons
so that the cuttings can be dropped overboard. However, in most cases,
supplementary fuel is required since the cuttings do not contain
sufficient combustible materials. A sophisticated incinerator is
required for safe operation and prevention of air pollution. This
has been used in Europe for several years.
Cleaning cuttings consists of catching the cuttings as they come
off the shaker and conveying them to the rig cleaning plant. Contami-
nated cuttings are washed in a diesel oil-surfactant solution and then
mixed with water in a holding tank for separation. After oil, water,
and solids separate, the oil is recirculated into the cleaning system,
the water and cuttings pass over a shaker, the cuttings are dropped
overboard, and the water is recirculated into the cleaning system.
After the mud concentration in the diesel oil reaches a predetermined
level, the diesel oil-mud solution is added to the oil-base drilling
fluid, and fresh diesel oil-surfactant solution is added to the
cleaning system. This method must be closely monitored to insure
hydrocarbon-free cuttings.
In the collecting process, the cuttings are collected as they
come over the shaker and are placed in containers. For ease of han-
dling, the containers are 30-50 cubic feet in capacity. After the con-
tainers are filled, they are sealed and transported by boat to a land
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location, to an authorized disposal area. Of the three methods discussed,
this method is the safest, both for environmental and personnel pro-
tection. However, transportation scheduling and limited rig storage
may present a logistics problem with the cuttings collecting method.
There is a need for oil-base muds to prevent damage to the pro-
ducing formation and when difficult problems are encountered. With
proper care in treatment and handling of mud and cuttings, oil-base
drilling mud can be used without endangering the environment.
DISCUSSION
MR. HARRY L. HARRISON: (A C Drilling Specialties, Odessa Texas): I
would like for you to point out to the panel, if you would, the
phase in which these oil-base muds come into the drilling opera-
tion. At what point in the drilling operation are they normally
entered?
DR. McMORDIE: Oil muds are used deep down in the hole; normally, the
surface hole is not drilled with oil muds. Probably the last 2,000
or 3,000 feet of drilling would be all that would be drilled with
the oil muds.
MR. ROBERT B. ALLRED (Sun Oil Company, Richardson, Texas): Warren, let
me help you a little bit. Many people have asked me to tell them
what kind of drilling fluids we begin the hole with. Usually, the
first thing we do when we get to a site is to drill a water well
because we must have water when we start any hole, unless we air
drill it or gas drill it. Then we usually just start with plain
water, maybe with a little sodium or bentonite in there, sometimes
for depths to 7,000 feet.
What I am trying to point out is in the areas where you have
your runoff waters and where contamination might be taking place,
the drilling fluid is usually only water; it does not contain any
lignosulfonates, lignite, or any poisons. At best, it contains gel
from the earth, and water from the earth.
Oil is used, as Warren pointed out, very deep, but we do not
need an oil mud to start a well with. Oil muds are expensive.
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If you use an oil mud on the well, you are usually talking
about $100,000, sometimes as much as $500,000. So you only use
it when you must because it is expensive.
DR. McMORDIE: Not only is it expensive, the crews do not like to use
it either.
CHAIRMAN WENNEKENS: You mentioned that you take the residue to an
approved disposal site. Can you give us a little detail on that?
DR. McMORDIE: I am afraid I am going to get into somebody else's talk
if I do, but I can give you an example of what our company does in
Louisiana.
We have burning sites that have been approved by both the
parish and the State of Louisiana. The cuttings, or sludge, is
taken there and burned.
MR. DENNIS G. WRIGHT (Environment Canada, Winnepeg, Manitoba, Canada):
When you spot diesel oil to free stuck pipe, I imagine the
diesel gets very emulsified as it is coming to the surface. How
do you separate that out from the system?
DR. McMORDIE: There are two ways you can handle stuck pipe applications,
One of them is by complete displacement; that is, the entire mud in
the system is displaced after the pipe is free, then the oil mud is
removed from the hole and water mud is placed back in. Normally,
spacers are used; that is, water between the oil mud and the water
mud. The delivery vessels, either the boat or truck, carry all of
this back to the mud plant where it is treated.
The second method is to spot, say, a hundred barrels of oil
mud in the hole opposite the stuck pipe area. In this case, some
mud is emulsified in the hole; however, when you get it. free, the
majority of the oil is removed and returned to the mud plant.
But, yes, you are correct; some oil mud is emulsified in the
water mud.
MR. DONALD W. SQLANAS (U.S. Geological Survey, Metairie, Louisiana): I
do not want to cut into Warren's business, but I feel that I must
comment, again, that oil-base muds are not permitted to be used ir
the offshore operation on Federal areas. They can only be used
510
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under special problem instances. They can only be used by special
permit approved by the U.S. Geological Survey.
Also, the generalization that in the bottom 2,000 or 3,000
feet of a hole is where oil-base muds are usually used does not
mean that oil-base muds were used in the bottom 2,000 or 3,000 feet
of every one of the 20,000 wells that have been drilled offshore. I
would roughly estimate that 99-44/100 percent of wells drilled use
water-base muds.
DR. McMQRDIE: Yes. That is something I have written here, but I did not
read it.
USGS regulations are that no oil muds will be used for drilling
offshore unless a special application is there, and unless special
permission is received.
In addition to that, no oil will be dropped in the water.
Oil muds are a specialized mud. They are used in 5 to 10 percent
dollar volume of the mud industry, as best we know. As Bob said,
they are extremely expensive, so that makes their physical use much
less than that. They are used only when water muds do not perform
satisfactorily. The application has to be an extremely specialized
one.
R. DALE P. VOYKIN (Pennsylvania Department of Environmental Resources,
Williamsport, Pennsylvania): I heard one gentleman over here say
that shallow aquifers are drilled through with water. You say that
the oil-base muds are used at depth. What protection do we have
for a shallow water table aquifer with the underlying impounding
that you showed in your slides? •
1. McMQRDIE: By the time the oil mud is in the hole, there are normally
two strings of casing that have been set down and cemented across
the shallow water aquifers.
. VOYKIN: In the pits, the reserve pit.
. McMORDIE: Yes.
. BRECK STRAUGHAN (A C Drilling Specialties, Odessa, Texas): We
pretty well solved this in West Texas. We line our pits with
polyethylene plastic to keep the contamination from going into the
ground.
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DR. McMORDIE: There have been some applications in which the cuttings,
themselves, were caught in metal containers.
DR. RAYMOND W. MILLER (Utah State University, Logan, Utah): I do not
know anything about muds; but I know if you are going to put in the
bentonite solution, you are not going to get much water infiltrating
to that pond bottem. By the time you get the oil mud in there, it is
likely to be even worse. So I agree that there is not going to be
any movement of water through the pond bottom.
MR. JAY P. SIMPSON (Baroid Division, N L Industries, Inc., Houston, Texas):
Perhaps there is a misconception here, Warren. The oil and mud are
not put into the reserve pit. You would have to handle just the
cuttings. You do not put the oil mud out into an earthen pit; that
is kept in steel tanks.
DR. McMORDIE: Right.
MR. JOHN R. JIMINEZ (EPA - New York): I have noticed (a little sarcasm
here) that bird feathers have been used at times in drilling muds
for special purposes.
Now, my question is, do these bird feathers get into the soil
pits accidentally or are they put there for a special purpose?
What I am really trying to ask is, what protection do you have for
wildlife to prevent them from mistaking these pits for lakes?
MR. HARRY L. HARRISON: On a rig, these things run 24 hours a day, 7
days a week, holidays not excepted. Those big old motors up there
make noise, and they pretty well keep all wildlife away in West
Texas. Now, I don't know about your Louisiana swamps, but they
will do it out in Texas.
MR. JIMINEZ: That may be true in Texas. I know the Audubon Society has
been concerned that a lot of the migratory birds have mistaken oil
pits for lakes, and have actually landed in them. Quite a lot of
birds have been lost this way.
I know they are trying to use flares and guns for noise, but tl
are still having problems. And I want to know exactly what the
industry proposes to do in some of these areas in the Central
United States where, when you fly over one of these pits, you
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cannot tell if they contain oil or water.
Are you going to put scarecrows up there to keep away the
birds?
DR. McMORDIE: These pits are water pits. I hope I did not leave a
misconception that we have got oil out in an open earthen pit.
There are lights around these things, there is noise, there
is human activity.
Personally, I think it is very unlikely that you will see any
kind of animal or bird life around the pits.
I have been on a rig in Alaska up on the North Slope and the
small amount of animal life I did see was extremely careful not to
get around the activity, noise, humans, et cetera.
A PARTICIPANT: There are millions of birds here during the spring and
winter. They are a nuisance. How do you get rid of them?
MR. JIMINEZ: Well, the proposal from the Corps of Engineers was to
drop a solution on the birds and very nicely freeze them to death.
If that is what you like, that is fine, but that is an opinion.
1R. GLEN W. ANDERSON (Standard Oil of California, Oildale, California):
I think we have lost perspective on this drilling sump idea, in
that this is a very temporary thing that is only used at the time
that the well is being drilled. As soon as the rig equipment is
moved out, the sump is disposed of and covered up, and the land is
put back as was.
Further, in California we have a certain number of production
sumps left that we are able to use to dispose of production water
and things like this. However, we have, over the past 2 or 3 years,
reduced these in number by at least three-fourths. The ones that
we do have left are completely fenced with a very fine hog wire fence,
and they are covered completely with a netting to prevent the birds
from getting into them.
. SOLANAS: Just one comment on the question by the gentleman from
EPA from New York on the feathers subject. The feathers that are
used are for loss of circulation problems. They do not come from
birds landing in the mud pits. They are probably chicken feathers
from chicken-plucking operations.
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WASTE WATER BASE DRILLING FLUID DISPOSAL
Dr. L. R. Louden and
R. E. McGlothlin*
Abstract
In 1970 a new patented process was developed for disposal of thick>
watery fluids into a nontoxio and safe material that is environmentally
attractive. This process is based on reactions between soluble silicates
and silicate setting agents, which can be reacted at controlled rates to
solidify mud and cuttings. This paper investigates drilling fluid dis-
posal and its effects upon the environment. It reviews the nature of
past and present drilling muds3 discusses the contemporary disposal
methods^ and investigates the results of pollution tests conducted.
INTRODUCTION
Strong concern for our environmental quality has been growing
in public importance the last several years. Preserving our environ-
ment presents industry a research and development challenge to create
effective products and adequate disposal methods. This paper investi-
gates drilling fluid disposal and its effects upon the environment.
It reviews the nature of past and present drilling muds; it discusses
the contemporary disposal methods; and it investigates the results of
pollution tests conducted.
Traditionally, disposal of water-base muds was not a difficult
process. Typical drilling fluid was composed of fresh or salty water,
Dentonite, barite, drill solids, and drilling jchemicals, all basically
inert. Thus, in many cases a mud pit, after drying over a period of
*Dr. L. R. Louden is with Swaco Operations and R. E. McGlothlin
s with Magcobar Operations, Oilfield Products Division, Dresser
ndustries, Inc., P.O. Box 6504, Houston, Texas 77005
515
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time, was covered with overburden or spread onto surrounding land and
disked into the soil. Offshore, drilling mud was sometimes pumped to
the ocean bottom through a spreader pipe for disposal.
With the recent development of more stable mud systems that pro-
vided fluid stability under extreme pressures and temperatures, classi-
cal disposal systems were esthetically objectionable. Mud pits could be
unsightly and persistent.
When drying, drilling mud forms a surface crust that retards evap-
oration. Additionally, the mud will not dry by subsoil leakage, and
therefore a holding pit of mud may require several years to dry .com-
pletely. Environmentally, the traditional method of pumping onto a
field and plowing it under when dried is not compatible with present-day
philosophy of proper disposal.
Four years ago a major engineering development project was ini-
tiated by Dresser's Swaco Operations to study effective mud and cuttings
disposal. Several processes which included both mechanical and chemical
disposal methods were investigated. Mechanically, a system was developed
with four burners, each of one million Btu capacity, that would sinter
drilling mud at a cost of $9-12 per barrel. Burning water-based drilling
mud, however, was deemed uneconomical.
Chemically, a new technique was developed to solidify drilling mud
and cuttings into a nontoxic and safe material that is environmentally
attractive. This patented process is based on reactions between soluble
silicates and silicate setting agents which can be reacted at controlled
rates to solidify the mud and cuttings. After solidification and curing,
the material can be mixed with native soil with no plant growth detriment.
During the curing period, crystalline growth builds a "pseudo clay"
material containing the same moisture content as the underlying soil
with a very-low-humus subsoil basic compositon. In the initial phase of
this process, a rapid reaction between soluble silicates and polyvalent
metal ions produces insoluble metal silicates. These insoluble compounds
are nontoxic and almost impossible to resolubilize because of the crystal'
line "pseudo clay" structure.
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The second phase of reactions occurs between soluble silicates and
the reactive setting agent. The rate of the reaction is proportional to
the concentration of setting agent. Under a controlled rate, the reac-
tion forms a reticulated solid matrix which acts as a sponge, entrapping
and immobilizing drilling mud components (for example diesel oil) in
the structure. This mud solidification process was studied to develop
data on resultant solids chemical characteristics. Of prime importance
was a measure of the chemical composition of solidified mud constit-
uents before and after rainfall or water percolation.
No standard procedure approved by regulatory agencies existed;
therefore, a reproducible test was required. An industry-developed
test method was selected (refs. 1,2). This test method has been thor-
oughly evaluated, and results can be duplicated in accredited labora-
tories and also correlated with field results.
STANDARD LEACHATE TEST
(1) One hundred grams of the material to be leached is placed
in a 40- by 600-millimeter column- containing 1 inch of
cotton and/or glass wool at the bottom interface.
(2) The material to be leached is placed into the column.
(3) The column above the material is filled with distilled
water (the diluent used for ease of reproducibility).
(4) Diluent water is seeped through the solidified material at
a rate of approximately 1 cubic centimeter of water per
minute. The diluent water seeping through the solid material,
called the "leachate", is collected.
(5) Leachate normally is collected in 100-cubic-centimeter portions.
Every eight portions simulate approximately 25 inches of
ground water passing through the material in the field.
Larger portions can be collected, if required.
(6) Leachate portions of various composites are analyzed by
atomic absorption, spectrographic, colorimetric, or wet
methods (as required) to determine the concentration of
any constituents leached from the material under analysis.
Results are reported in ppm.
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Analytical data illustrate that higher initial concentrations
drop to less than 1 ppm within 1-2 days as the crystalline growth
(curing) is initiated. Once the crystal growth is completed, the
constituents do not leach out of the solidified mud.
In the initial test to predict long-term characteristics of pro-
duced solids, a 12-pound-per-gallon water-based drilling mud was sol-
idified and used as landfill in a central Illinois farm where the dril-
ling location was slightly subgrade following well completion and well
head installation. Rather than fill with hauled dirt, solidified mud
was used to build location grade, and covered with top soil. During
this process, local agriculture agencies conducted extensive analyses
and testing, including controlled agronomy studies. Results of agency
and collaborative studies indicated that additions of up to 30 percent
of solidified waste drilling fluid mixed with the area's black soil
caused no detrimental effects on plant development or crop life. Further,
properties of this solidified mud tended to approach that of the host
soil. There was no harmful effect to corn, soy bean, or other crops.
Another field test under different circumstances was conducted in
Grand Isle, Louisiana. A southernmost extension of the State into the
Gulf of Mexico, Grand Isle is essentially a sand bar at the mouth of a
bayou facing the Gulf with approximately 30 miles of swamp behind it.
As a major oil industry marine base, the island has a large mud disposal
pit. Hurricane or other threats causing rising water which could displace
mud made it imperative to develop alternative methods of mud disposal.
The holding pit contained mud from offshore marine rigs and large
barge-mounted marsh rigs and had a 28 percent oil content.
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The following is an analysis of the mud before solidification:
Mud wt.
% Oil
% H20
% Solids
PH
Ca++
Mg++
Na+
Cl"
so4=
K+
Zn+
11.8 Ib/gal
28% Cr+++
41% Ni++
31% Mn++
10.1 Fe++
2,720 ppm
4 ppm
5,800 ppm
13,100 ppm
870 ppm
230 ppm
2 ppm
1 ppm
1 ppm
1 ppm
1 ppm
New disposal procedures used mud as area fill behind the bulk-
heads and at tank sites as dike material. Several alternate fill
techniques were studied including using solidified material mixed
with locaT fill; also, solidified mud was poured directly from the
solidification unit into forms, much as a wall or dike might be
poured from cement. Although the structural strength of solidified
nud is not great, in poured and undisturbed states it demonstrates
superior qualities over conventional earth tamping techniques. Solid-
ified mud was also tested as a low permeability vertical wall because
if its oil retentive claylike structure.
A long-term leaching analysis was run on the solidified Grand Isle
ud with the following results:
519
-------
LEACHATE ANALYSIS (Days)
Equivalent inches of rain
(Curing time 48 hours before leaching began)
Constituent 1 Day 2 Days 8 Days 15 Days 28 Days
pH 12.1 12.3 12.0 11.8 10.6
Ca++ 420 400 260 220 120
Mg++ <.l <.l <.l <.l <.l
Na+
cr
4
K+
Zn++
Cr+++
2,100
2,750
50
90
2,000
2,600
40
40
20
10
9
5
10
10
3
3
10
8
2
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Mn++
Fe++
The required concentrations of silicate reactants and setting
agents vary considerably depending on (1) the composition of the slurry
to be solidified, (2) the physical characteristics required for the
final solidified materials, (3) the time allowed for setting to occur,
and (4) the conditions present, during the setting period. Required
quantities are determined by pilot testing the mud to be solidified.
Since the slurry and reactants mixture frequently has a high gel strength
it is imperative to add the activator after the setting agent has been
mixed into the slurry.
Systems containing high concentrations of heavy metal ions require
additional activators to complete the chemical reaction. Initially, the
heavy metal ions are precipitated as a metal salt. This salt is then
bound within the solid matrix of the solidified material and is not
leached out by excessive rainfall.
520
-------
To demonstrate this process, a 11.6 Ib/gal laboratory mud was
prepared with metallic ions commonly found in drilling muds. An
excess concentration of these ions was added for this test.
The composition of this mud was:
Mud wt. 11.6 Ib/gal
pH 10.0
Cr+++ 1,388 ppm
Zn++ 2,800 ppm
Mn++++ 2,522 ppm
Co++ 285 ppm
Fe++ 13,300 ppm
An analysis of the filtrate showed:
pH 8.3
Cr+++ 550 ppm
Zn++ 60 ppm
Mn++++ 210 ppm
Co++ 3 ppm
Fe++ 100 ppm
This system was then solidified and leachate analysis taken after
each established curing time: (1) 24 hours, (2) 48 hours, (2) 96 hours,
(4) 168 hours (7 days), (5) 336 hours (14 days), (6) 672 hours (28 days),
After each sample had cured the predetermined time, 100 ml of
leachate were taken each day for 28 days. The data illustrates that
following only 1 day of curing, less than 0.1 ppm of the metals
leached out.
LEACHATE ANALYSIS
Equivalent inches of rain
Cured 1 day Cured 7 days Cured 28 days
Constituent 1 7 28 1 7 28 1 7 28
Cr+++ <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
Zn++ <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
Mn++++ <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
CO++ <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
Fe++ <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
521
-------
CONCLUSIONS
Mud solidification is an excellent disposal solution for most
drilling operation byproducts. The attractive advantage is that
this disposal system of chemically reacted and solidified materials
is nonpolluting and environmentally safe.
The pseudo-clay material resulting from the crystalline growth,
encapsulation, and dehydration, can be employed for numerous applica-
tions, including for reclamation landfill and for treating a large
variety of industrial wastes. When used in agricultural fill restora-
tion, seed germination studies conducted by an independent agronomist
indicated that germination was not affected in garden soil which
included up to 40 percent of solidified mud, and germination was re-
tarded only a few days in soils containing up to 80 percent.
Cost factors determine the necessity for adequate solids control
equipment and processes. This mud solidification process costs about
$3 per barrel, and portable systems capable of processing 1,000
barrels a day are available. Correct solids handling equipment and
proper drill site drainage can reduce mud volumes to be solidified
as much as 75 percent, significantly reducing drilling fluid disposal
costs.
REFERENCES
1. M. Kawamura and S. Diamond, "Stabilization of Clay Soils Against
Erosion Loss," Joint Highway Research Project, Purdue University
and Indiana State Highway Commission, March 1975.
2. Ralph Wisniewski, "Process Converts Sludge to Landfill," Oil and
Gas Journal, March 17, 1965.
522
-------
DISPOSAL OF DRILLING FLUIDS
AND DRILLED-UP SOLIDS
IN OFFSHORE DRILLING OPERATIONS
W.J. McGuire, Ph.D.*
stract
Water-base drilling fluids are used predominantly in offshore drilling
srations. Fluids containing oil are resorted to only where special problems
:tessitate their use.
Since OCS Order No. 7 was issued August 28 3 196 9 j drilling fluids con-
Ining oil have been transported to shore and have either been stored for
bure use or disposed of in landfills. Most oil-coated solids were also
iposed of on shore. Some recent attempts to clean the cuttings for off-
->Te disposal have succeeded.
Many offshore lease agreements stipulate that drilled solids must be
•charged at a distance no greater than a designated distance from bottom
ually 20 feet). These stipulations are imposed in estuaries and near
All rotary drilling operations require that a fluid be circulated while
bit penetrates the encountered formations. In almost all cases, this cir-
ation is down the drill pipe, out through ports in the drill bit, across
bottom of the hole where it sweeps up the cuttings generated by the bit,
i up the annulus between the drill string and the hole.
In the basic drilling operation, the returned drilling fluid is first
;ed through a vibrating screen called a shale shaker, where most of the
led solids are removed from the system. Then the fluid passes through
;tting tank, where the small particles of rock which passed through the
e shaker screen settle to the bottom. Ultimately, the fluid is picked up
i a suction pit by the slush pump and then put back down the drill pipe.
Besides removing the cuttings from the hole, the drilling fluid must main-
sufficient hydrostatic head to prevent the intrusion of formation fluids
the hole. If such intrusion is not prevented, the drilling operation
kly degenerates into a disaster called a blowout.
*Associate Professor, Petroleum Engineering, Texas A&M University,
ege Station, Texas.
523
-------
Many deep formations contain fluids under a pressure that greatly ex-
ceeds the hydrostatic pressure gradient of water, 0.43 pounds per square
inch per foot of depth. In some areas formation pressures have been observed
to be as high as 0.9 pounds per square inch per foot.
As a result, drilling fluids must frequently have densities over twice
as great as that of water. This is usually accomplished by adding a particu-
late weighting material to the system, most commonly barites (BaSO.).
The addition of weighting materials to the system places another require
ment on the drilling fluid—it must possess a gel strength. That is, the
resistance to shear at zero rates of shear must be finite so that the barites
will not settle when circulation is suspended. Hence, a colloidal system
having a gel strength is required.
Colloidal suspensions are notoriously delicate. The array of over 200
proprietary chemicals is comprised mainly of colloid stabilizers. Most of
these are tannins, lignite, and lignosulfonates.
Since the present price of barites offshore is about $94 per ton, very
little drilling fluid is discarded. Most drilling fluids are stored for
future use. However, when a water-base drilling fluid is discarded, it is
usually disposed into the ocean with no attempt to salvage any of its com-
ponents, despite the fact that the recovery of barite by centrifugal methods
is a common practice on land.
Many lease agreements state that leases issued as a result of the lease
sale will contain the following stipulation for the protection of high-relie
offshore banks: no structures, drilling rigs, or pipelines will be allowed
within the aliquot parts established for the offshore banks. In addition,
operations on leases issued covering the tracts described as well as operat-
within the aliquot parts of the tracts will be restricted as follows: dril
cuttings and drilling muds must be disposed of by shunting the materials to
bottom through a downpipe that terminates 20 feet or closer to the sea bott
However, if the Supervisor, after consultation with the Manager, Gulf of Me
Outer Continental Shelf Office and the Regional Director, U.S. Fish and Wil
Service, Albuquerque, New Mexico, determines that the shunting method is no
adequate to protect the unique character of the subject areas, then the Sup
visor will require the barging and dumping of these materials a minimum of
524
-------
js from any of the above described aliquot parts of the seven banks. Should
barging method be required, disposal sites must be approved by the Super-
»r, and any other agency or agencies having jurisdiction at the time.
The disposal of cutting through a downpipe poses some difficulties.
led-up sands and cuttings from many shales present no problem. But some
led-up shales, marls, and clay are difficult to handle. These intractable
rials react with water. The cuttings absorb large volumes of water, swell-
to many times their original volumes. In doing so their density approaches
of seawater so they do not sink nearly so rapidly as a comparable piece
>ck would. They also develop a sticky surface. The particles agglutinate
;orm an unmanageable sticky mass that will not move down the pipe spontane-
'. Therefore, the downpipe must be equipped with high-velocity water jets
i force the sodden mass to the bottom.
Because all drilling fluids must exert a hydrostatic head that exceeds the
ure in all of the fluids penetrated, there is a persistent flow of the
d phase—or more generally, the continuous phase—into all of the permeable
tions expossed by drilling.
This invasion of permeable formations deposits the solid fraction of the
ing fluid at the interface, where it forms a filter cake. Filter cakes
;eful insofar as they help stabilize sand formations, which are not highly
lidated. But they create an ever present hazard, the possibility that
pipe or drill collars will become embedded in the filter cake and become
This so-called wall sticking is more complicated than its simple name
s. Figure 1 is a diagram of an open hole in a permeable formation. The
cake has a thickness (t). The pressure in the formation is designated Pf
e hydrostatic head of the drilling fluid, P., exceeds P. by as much as
unds per square inch. The filter cake is orders of magnitude less per-
than the formation. Therefore, it is the controlling restriction to
The entire pressure difference is exerted across the filter cake. For
:ity, it is assumed that the entire 500 psi in the example is exerted on
;ide surface of the cake.
len a drill collar becomes embedded in the cake as shown, this pressure
jnce is exerted against the chord AB~. Considering moderately thick filter
in ordinary deep drilling situations, this chord length may be as long as
>s. Then each foot of embedded drill collar is pushed against the wall
525
-------
&;&&:::;:::;•;;;;:;
v^2^:;;;;;;!!;;;;;
^^:::::::::::
r'>* ."•'••\IiIIIJ"
i'-Vjx.V:::::;:
^::;:::;
I.
-------
the hole by a force of 30,000 pounds. The coefficient of friction between
el and filter cakes has been determined to be in the vicinity of 0.5. Then
Dree of 15,000 pounds would be required to slide the 1-foot length of drill
lar out of the cake.
When many wells are drilled from offshore platforms, one only is vertical.
the rest must be deviated from vertical. Many achieve angles as high as
from vertical. In such situations wall sticking is a virtual certainty.
When this occurs it is not uncommon to attempt to free the drill stem by
ting small quantities of special fluids over the stuck portion. These
ds are oils containing large quantities of chemicals that enhance their
bility of wetting steel preferentially. Such materials invariably become
srsed throughout the drilling fluid system. OCS order No. 7 of August 28,
,* specifically prohibits the disposal of such material offshore. As a
t, these materials were barged ashore and trucked to land fill disposal
When wall sticking interferes too frequently with drilling operations,
ase systems or inverted oil emulsions are employed. These systems deposit
mely thin filter cakes so that the chord of penetration is negligibly
thus subverting the sticking mechanism. Oil Base, Inc. "Black Magic" is
al oil system using diesel oil and asphalt. This mud system requires drill
igs to be contained and transported to a disposal site onshore. The mud
ly is working to develop a drill cutting cleaning system. The present
i requires a number of tanks and their size imposes a space requirement on
ire platforms, which restrict or prohibit its use during drilling operations,
nverted oil emulsion mud contains from 60 to 80 percent diesel oil. It
s its name from the fact that oil is the external or wetting phase. The
gs generated when either system is used are completely wet with oil.
f the expense of transporting the cuttings ashore (estimated to be $15,000
20,000 foot well) is to be avoided, the cuttings must be cleaned.
/vo approaches to this problem have been considered. The first was to
ie oil off by submitting the cuttings to a 4,000°F temperature generated
)rilling mud containing oil shall not be disposed of into the Gulf. Drill-
! containing toxic substances shall be neutralized prior to disposal. Drill
!s, sand, and other solids containing oil shall not be disposed of into the
iless the oil has been removed.
527
-------
by high-intensity lamps. In the pilot operation of this process, the cuttings
were transported under the lamps by a stainless steel conveyor. The process
was abandoned because of unequal exposure to the heat. Also it was feared the
the high temperatures involved would be considered to be an unacceptably high
risk by the insurers.
The second approach, washing the cuttings with a special detergent, appei
to be a practical solution. Most washing systems are similar, but there are
variations in equipment and techniques. Baroid Division of National Lead
Industries has used three different schemes. One consists of a Medaris cutti
washer installed at the discharge of the shale shaker. Cuttings are directec
into the washer through a funnel-shaped intake. As the cuttings pass through
the washer they are tumbled in a revolving screen within the washing drum anc
are sprayed with the wash solution. When rig layout does not allow this arr;
ment, the cuttings are brought to the washer by an Archimedes screw. Clean
cuttings are then discharged through the downpipe.
This system requires two 5-horsepower moyno pumps and a retention tank
the wash solution.
One Medaris washer can handle cuttings from a 9-7/8" diameter hole bein
drilled at 50 feet per hour. Larger holes and faster drilling rates require
two washers.
Another system Baroid has used is built around a 50-barrel tank partia"
filled with a wash solution. Cuttings fall into the tank as they fall from
double-deck shale shaker.
The wash tank is equipped with a conventional mud-tank mixer that agit
the wash solution. A centrifugal pump circulates the wash solution and cut
over a second double-deck shaker on top of one end of the wash tank.
As the wash solution is circulated over the second double-deck shale s
clean cuttings are discharged for disposal and the wash solution is complet
shut down for a few minutes to allow the oily particles to settle.
In order to overcome an extremely difficult drilling and casing situal
in the North Sea, Placid Oil Company required an oil mud. In order to sat-
the Netherlands restrictions on pollution, Placid installed a third Baroid
cuttings cleaning system.
This system is a somewhat more complex cuttings washing system, and h
528
-------
n Installed on a rig drilling for Placid Oil Company in the Dutch sector
the North Sea under the approval of Dutch authorities. The cleaning system
built around two double-deck shakers and a smaller shaker with the same
"ating motion as the rig units.
The two rig shakers accommodate full mud flow from the well. Drilled
;ings pass from these onto the smaller shaker, where they are thoroughly
ed with a unique nonaqueous washing solution cirulated by a small centrifugal
•
The washing solution is miscible with the oil mud being used, and after it
nes contaminated it is returned to the mud system.
One key to the effectiveness of this system is a sump arrangement through
i cuttings are discharged to the ocean floor. The sump consists of a 20-inch
ig, installed in one of the jack-up rig's legs, and extending, almost to
icean floor. Within this 20-inch casing is a 10-inch pipe that extends to
: 30 feet above the bottom of the 20-inch casing. Cuttings enter the 10-
pipe from the small shaker and fall through it into the 20-inch sump and
the ocean floor.
Removal of any contaminants in wash solution remaining on the surface of
uttings takes place during the fall through the 20-inch pipe, and any such
ninated wash solution is contained within the 20-inch pipe.
To remove accumulated contaminants from the 20-inch sump, a submergible
s also run into the 20-inch pipe and placed near the water surface to pump
intamination from the sump.
11 contaminants from both the submerged pump and from the cuttings washer
uted to an oil/water separator. Oil from the separator is returned to
d system; the water is discharged back into the sump. This "loop" provides
letely closed system.
ie system can also accommodate any displaced mud that might pose a con-
tion problem. It is designed to handle almost anything that might re-
lydrocarbons.
i this particular installation, mud from the rig shakers goes directly
i the main deck to the return mud system.
529
-------
Conclusions
1. Water-base drilling fluids are preferred in offshore drilling situations
to avoid oil contamination.
2. Oil-base drilling fluids are a frequent necessity to overcome extreme
difficulties.
3. There are devices that clean cuttings generated in invert oil emulsion
drilling fluids to government specifications.
4. All oil-base drilling fluids are disposed of by barging to shore.
REFERENCES
1. G.E. Cannon, and R.S. Sullins, "Problems Encountered in Drilling Abnorm,
Pressured Formations," API Drilling and Production Practices, 1946.
2. Department of the Interior, Bureau of Land Management, Outer "Continenta
Shelf of Texas, Oil and Gas Lease Sale 37, February 4, 1975.
3. M.R. Annis and P.M. Monaghan, "Differential Sticking - Laboratory
Studies of Friction Between Steel and Mud Filter Cake, J. Pet. Tech.,
May, 1967.
4. Kennedy, John L., "Cuttings Can Meet Offshore Environment Specificatioi
Oil and Gas Journal, August 14, 1972.
DISCUSSION
MR. JAMES B. JOHNSTON (Bureau of Land Management, New Orleans): I would li
to say that concerning the margin of cuttings from drilling operations
that is one method. The other method you mentioned concerned the shur
of the materials to the bottom. On the Gulf of Mexico we have had twc
•
wells drilled, one in an area around the Florida middle ground, and or
the east flower gardens in Texas. In both of these operations there
was shunting to the bottom. In the Florida area it was 50 to 60 feet
from the bottom, and in Texas I think it was 20 to 30 feet from the
bottom.
Also, let my say that shunting is not necessarily confined to fi
banks. We are also concerned with coral areas, like the middle groun
and the flower gardens.
530
-------
The one case I would like to mention is in the Florida middle
ground area, in which myself and three divers from the State of Florida
(marine biologists) dove on the drilling location after the well had been
drilled. We were unable to detect any of the cuttings in the immediate
area, which I would say is 200-300 feet from the actual drilling spot.
I later found out from the USGS people that they had talked to some
divers from Texaco, who said that the cuttings had been confined to an
area with a diameter of about 50 feet and 6 feet in height. As I said,
we were unable to find any detected cuttings. We did find an empty drill
cutting bag on the bottom so we knew we were in the area, based on our
readings.
I think it was Mr. Scalan from the University of Texas who pointed
out that we at the Bureau of Land Management are investigating this.
-lopefully, we will be able to monitor some of these drilling operations
[that is one reason Dr. Monastero is not here today) and solve some of
the problems that have been raised at this meeting.
531
-------
ENVIRONMENTAL EFFECTS OF DRILLING MUDS AND CUTTINGS
James P. Ray, Ph.D.,
and E. A. Shinn*
jtract
In 19?S3 a She'll research group studied some of the environmental
^ameters concerning offshore drilling discharges. During a 2-day period
1973, they collected 34 water samples around a Shell platform off the
st of Louisiana. Samples were taken at the surface (1 ft), midwater
0 ft), and at the bottom (245 ft). The platform was actively drilling
the 9,000 ft level with lime base mud at the time. Analyses were made
alkalinity, total dissolved solids, total suspended solids, total
inic carbon, and total dissolved chromium. Results indicate that all
•meters approached normal background levels as close as 60 yards to the
-,form. Mid- and bottom-water samples beneath the platform showed some
Actable chromium, but hexavalent chromium was not detected in any samples.
Theoretical dilution curves were estimated for a current of 0.5 feet
second and dishcarge rates of 40 and 250 barrels per hour. Dilutions
,000:1 were estimated at approximately 1,000 and 10,000 feet, respec-
ly.
The importance of environmental observations is stressed. Mr. E. A.
n, an experienced diver and underwater photographer, has observed marine
under Gulf of Mexico platforms for many years. He has observed that
light mud fractions appear to drift upward and laterally, while the
Ing chips and filter cake fall straight to the bottom. Encrusting
lisms are observed prolifically covering platform structures. Barna-
are seen living on and inside discharge downpipes. Fish swim through
>arge material with no observable ill effects.
There appear to be no visual detrimental effects of drilling discharges
'ganisms that are living above the bottom. Cutting piles beneath pro-
on platforms have been observed to be repopulated with marine comnuni-
*James P. Ray, Ph.D., Environmental Affairs, Shell Oil Company, Houston,
77001; E. A. Shinn, U.S. Geological Survey, Miami Beach, Florida 33139.
533
-------
Introduction
This paper is directed at two topics. First is the presentation of
some preliminary work by Shell which indicates that discharge concentra-
tions in the marine environment are very low. This research conducted in
1973 compares favorably with that pf Zingula (ref. 1) in late 1974 at a
different location.
Second is the importance of good environmental observations by qual"
fied people. Mr. Gene Shinn of the U.S. Geological Survey has spent muci
of his career underwater, observing and photographing the marine environ
ment. Some of his comments are presented here.
Preliminary Field Study
In 1973, a Shell team engaged in a study to answer some of the ques
tions concerning platform discharges. An offshore Louisiana platform si
ated in 245 feet of water was chosen. A 2-day water sampling program wa
conducted during the lime-base mud phase of drilling at the 9,000-foot i
terval. Sampling stations were selected on all sides of the platform
(figure 1). The discharge pipe was located 35 feet below the surface.
Water samples were taken at the surface (1 ft), midwater (120 ft),
and the bottom (245 ft) using an underwater air displacement type sampl<
Water samples were analyzed for alkalinity, total dissolved solids, tot
suspended solids, total organic carbon, and total chromium.
The results of these analyses can be seen in tables 1 and 2. The
most important conclusion that can be drawn from these data is that the
concentrations found around the platform are comparable to normal back-
ground levels as reported by Zobell (ref. 2) and Dryssen et al. (ref. ^
Data presented by Zingula (ref. 1) at the Environmental Impact Hearing
Trenton, New Jersey, and at the Conference on Environmental Aspects of
Chemical Use in Well Drilling Operations (1975) in Houston, Texas, con
firm this observation.
Alkalinity, expressed as part per million calcium carbonate, rang<
from 123 to 130 ppm. This lies within the background levels given by
Dryssen et al. (ref. 3) of 120 ppm and Zobell (ref. 2) of 200 ppm.
Due to a difference in analytical techniques, values in tables 1
2 for total dissolved solids appear high when compared to literature
534
-------
BOAT
LANDING
\
ffN 30YD /?v 30YD
WIND:
5-9-73 E, 10-12 MPH
5-10-73 S, 12-15 MPH
SLIGHT SURFACE CURRENT
WITH WIND
30 YD
30YD /?\ 30 YD (f
DISCHARGE
PIPE
30 YD
Figure 1. Seawater sampling points.
;s of 34,325-35,100 ppm. Filtered samples were evaporated to dryness
)°C instead of 180°C as recommended in the standard methods. This
lone for laboratory convenience, since a 180°C oven was not available.
result, the dissolved solids numbers are consistently high, probably
o a fair amount of water of hydration bound to the salt crystals.
pie was dried at both temperatures: 60°C which yielded 41,500 ppm,
80°C which yielded 36,200 ppm. It was determined that 60°C results
be corrected by multiplying by the constant 0.872.
The values for total suspended solids are very low as would be ex-
d for offshore waters (> 100 miles). Zingula's data (ref. 1) showed
535
-------
Table 1. Analysis of seawater around platform
May 9
Wind E
10-12 mph
location
1
2
3
4
5
6
9
10
12
Depth
1
120
245
1
120
245
1
120
245
1
120
245
1
120
245
1
120
245
1
120
245
1
120
245
50
120
245
Alka-
linity
(ppm as
CaC03)
125
123
125
123
123
125
123
125
125
123
125
123
123
123
125
123
125
123
125
125
125
125
130
123
125
125
125
Total*
dissolved
solids
(ppm)
43500
42600
44100
41700
41200
41800
42600
47900
45300
42200
42200
42300
41800
44700
43100
42300
42200
42700
42400
41800
42100
42300
40400
40900
41500
41300
41600
Total
sus-
pended
solids
(ppm)
8
20
16
8
80
0
20
40
0
0
0
0
4
0
28
8
0
0
0
0
0
0
0
12
8
0
0
Total
organic
carbon
(ppm)
5
9
5
5
6
7
5
10
6
5
5
7
4
7
6
5
7
16
6
8
6
7
7
5
6
8
7
Total
chromium
(ppm)
ND (0.01)
ii
ii
n
ii
n
n
n
0.04
ND
n
n
ii
n
n
n
n
0.01
ND
0.038
0.01
ND
0.052
ND
ND
ND
ND
*Determined by evaporation at 60°C. See text for explanation,
a surface value of 5.2 ppm for clear waters upstream from the drilling
platform.
Many people have voiced concern as to turbidity effects on the ma
organisms. It appears from the data gathered that suspended sediment
are rapidly diluted and reach background levels close to the platform
total suspended solids, tables 1 and 2). It is interesting to note th
536
-------
Table 2. Analysis of seawater around platform
May 10
Wind S
12-15 mph
location
7
8
11
Depth
1
120
245
35
1
120
245
Alkalinity
(ppm as
CaC03)
123
128
125
128
125
130
123
Total*
dissolved
solids
(ppm)
41300
44000
42500
41400
41500
40100
44300
Total
suspended
solids
(ppm)
0
0
0
0
44
0
0
Total
organic
carbon
(ppm)
9
7
7
10
4
8
11
Total
chromium
(ppm)
ND
0.038
0.01
0.037
ND
0.045
ND
*Determined by evaporation at 60°C. See text for explanation.
'en though the sampling stations were close to the platform (i.e., 60
irds maximum), many of the samples have zero values for total suspended
ilids. Griffin and Ripy (ref. 4) concluded their studies on turbidity
d suspended sediment concentrations as related to environmental impact
offshore platforms, with the following statement: "There was no de-
ctable effect on turbidity, suspended sediment composition, or concentra-
on produced by any of the offshore production platforms examined in
is study (Gulf Universities Research Consortium). Therefore, although
may find them visually offensive, at least they do not muddy the water."
Considering the high chromium levels t(trivalent) in ferrochrome
jnosulfonate (30,000-40,000 ppm), it is significant that no hexavalent
'omium was detected in any solid or aqueous sample. The analysis
lures present in tables 1 and 2 are for total chromium. Despite the
atively high levels of chromium in ferrochrome lignosulfonate, it is
nificant to note that chromium was undetectable in most samples. Those
pies with detectable chromium were taken from mid- and bottom-waters
r the platform.
537
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Discharges and Dilution
It is very important to understand what does happen to our marine
discharges. If we know what happens to discharges, then we can correlate
toxicant levels determined from laboratory bioassays with real levels
actually existing in the marine environment.
It has been estimated that the average Gulf of Mexico 10,000-foot
well produced 2 million pounds of solids. Contrary to the opinions of
many nondivers, the solids (cuttings) do not form large, desert-like
mounds on the sea floor. As has been shown by Zingula (ref. 1), the
drill cutting piles are in reality, of low relief, and repopulated with
marine organisms following drilling cessation. Zingula reported that no
set rules exist to determine what the shape, thickness, and extent of
cuttings accumulations will be. Side-scan records of wellsites in the
Gulf of Mexico and Santa Barbara Channel show no definite shadows several
months after drilling has ceased, indicating that the heights of cuttings
piles are 6 inches or less. Shinn (ref. 5) stated that although a cut-
tings pile may be several feet thick and cover a half acre at the time
of well completion, each major storm will disperse some of the material.
Mr. Shinn found no cuttings beneath production platforms in 60 feet of
water at the Buccaneer field 25 miles off Galveston, Texas, where drill-
ing ceased approximately 10 years ago. Oetking et al. (ref. 6) observed
the same thing in 66 feet of water beneath an offshore Louisiana platfon
that had ceased drilling 15 years previously.
It is of interest to compare man's contribution of sediments and
solids to the Gulf of Mexico via drilling versus nature's contribution
via the Mississippi River. Boykin (ref. 7) reported an estimated djrT[y_
outflow of 2 million tons of sediment from the Mississippi River. In
comparison, the average Gulf of Mexico well produced 2 million pounds of
material during the approximately 2-week drilling period. This is 0.05
percent of the Mississippi's daily outflow, or in less than 2 days, the
Mississippi deposits more sediments than the 15,200 wells drilled in thi
Gulf of Mexico.
Ocean currents are a major factor in diluting and dispersing offsh
discharges. Shell has calculated a theoretical dilution ratio, R~, whi
538
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