600281197
May 1981
ASSESSMENT OF OIL PRODUCTION VOLATILE ORGANIC COMPOUND SOURCES
by
I.S. Eaton, G.R. Schneider, W. Unterberg, and F.G. Bush III
Environmental Monitoring & Services Center
Rockwell International
Newbury Park, California 91320
Contract No. 68-03-2648
Project Officer
Leo T. McCarthy, Jr.
Oil & Hazardous Materials Spills Branch
Municipal Environmental Research Laboratory
Cincinnati, Ohio 45268
MUNICIPAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
-------
DISCLAIMER
This report has been reviewed by the Municipal Environmental Research
Laboratory, U.S. Enviornmental Protection Agency, and approved for publication.
Approval does not signify that the contents necessarily reflect the views and
policies of the U.S. Environmental Protection Agency, nor does mention of trade
names or commercial products constitute endorsement or recommendation for use.
-------
FOREWORD
The U.S. Environmental Protection Agency was created because of increas-
ing public and government concern about the dangers of pollution to the health
and welfare of the American people. Noxious air, foul water, and spoiled land
are tragic testimonies to the deterioration of our natural environment. The
complexity of that environment and the interplay of its components require a
concentrated and integrated attack on the problem.
Research and development is that necessary first step in problem solu-
tion; it involves defining the problem, measuring its impact, and searching
for solutions. The Municipal Environmental Research Laboratory develops new
and improved technology and systems to prevent, treat, and manage wastewater
and solid and hazardous waste pollutant discharges from municipal and commun-
ity sources, to preserve and treat public drinking water supplies, and to min-
imize the adverse economic, social, health, and aesthetic effects of pollu-
tion. This publication is one of the products of that research and provides a
most vital communications link between the researcher and the user community.
This report provides a description of oil and gas exploration drilling
technology and drilling muds, and a rough estimate of volatile organic carbon
emissions associated with drilling activities in the 48 contiguous states.
Francis T. Mayo, Director
Municipal Environmental Research
Laboratory
-------
ABSTRACT
Emissions of volatile organic compounds (VOC) from oil production in new
fields were estimated, based on three types of information: (1) extent of new
oil and gas fields (those that started production after 1974) in the contigu-
ous 48 states, (2) drilling techniques used for oil and gas exploration and
production wells (and their VOC potential), with specific emphasis on the dril-
ling fluids, and (3) equipment and techniques for oil and gas production in
new fields and their potential VOC sources.
The complete record obtained from Petroleum Data Systems (PDS) has been
provided for post-1974 oil and gas production within the 48 contiguous states.
Verification and updating of PDS has been accomplished for all but nine states.
These data have been summarized with respect to the states and EPA Regions,
whereas detailed information organized by state, county, field, etc. has been
provided in Appendix A, bound under separate cover, which is on file with the
U.S. EPA Office of Air Quality Planning and Standards, Research Triangle Park,
North Carolina.
An extensive description of oil and gas exploration and production dril-
ling technology is presented. Emphasis has been placed on the makeup, use,
and disposal of drilling fluids. A simple model for assessment of VOC emis-
sions accompanying drilling is presented, along with an estimation of the po-
tential VOC emissions associated with drilling activities.
As part of this effort, documentation in the form of 35-mm color slides
with a sound tape containing a narrative description of each slide and a
written transcript is presented (under separate cover) for current oil and gas
production and drilling technology. This documentation was obtained from five
oil- and gas-producing fields located in Texas, Oklahoma, Wyoming, Montana,
and New Mexico. The slides, together with the narration and the transcript,
which provide a brief description of the major process subsystems shown in
each slide, are on file at the U.S. EPA Office of Air Quality Planning and
Standards, Research Triangle Park, North Carolina.
Quantification of the VOC emissions associated with oil and gas drilling
and production technology was hampered by lack of data in several areas.
Recommendations for further effort are presented so that the assessment of
VOC potential emissions can be made by state, county, or field.
This report was submitted in fulfillment of Contract No. 68-03-2648 by
the Environmental Monitoring & Services Center of Rockwell International under
the sponsorship of the U.S. Environmental Protection Agency. This report cov-
ers the period from January 1980 to September 1980, and work was completed as
of September 1980.
iv
-------
CONTENTS
Foreword iii
Abstract iv
Figures vi
Tables vii
Acknowledgment viii
1. Introduction 1
2. Conclusions 2
3. Recommendations 3
4. Current Oil/Gas Well Drilling Techniques 4
Basic Drilling Processes 4
Basic Drilling Equipment - Rig Components 5
Fuels for Prime Movers 12
Drilling Operations 13
Well Completion 14
Auxiliary Rig Equipment 14
5. Drilling Muds 19
Drilling Mud Composition 20
Factors Affecting Type of Drilling Fluid Used 26
Factors Affecting Quantities of Mud and Cuttings Generated . 30
Disposal of Solid, Liquid, and Gaseous Wastes
Produced in Drilling 32
6. Completion and Workover Fluids 34
Composition 34
Disposal of Completion and Workover Fluids 35
Environmental Effects of Drilling, Completion,
and Workover Wastes 35
7. Oil Well Servicing and Workover 37
Service and Workover - Rig Equipment 37
Remedial Well Work 38
Well Cleanout and Workover 39
Well Stimulation 41
8. Survey of New Oil and Gas Fields, 1975-1979 43
9. VOC Emissions From Oil/Gas Drilling Operations 55
Stored Fuel and Engine Emissions 55
Formation Gases, Hydrocarbons 55
Formation Gas, HgS 56
Prospective VOC Sources 56
Model for Drilling Operations 58
Model for Production Operations 65
-------
FIGURES
Number Page
1 Multi-engine and chain drive transmission arrangement
for a mechanical drilling rig 6
2 Diesel-electric system for power and transmission 7
3 Rotary rig hoisting system 8
4 Rotary system 9
5 Rotary rig fluid circulation and mud treating system 11
6 Casing strings and pipe used in an oil well 15
7 Typical well completion 16
8 Drilling mud maintenance system 17
9 List of VOC data to be acquired within each state 44
10 Major oil regions in continental U.S 47
11 EPA Regional Offices - standard federal regions 48
12 U.S. drilling activity since 1956 60
13 New field wildcatting since 1956 62
14 Drilling rig activity 63
-------
TABLES
Table
1 Status Report of Petroleum Data System, TEXS and OILY
Data Bases, September 14, 1979 46
2 Regional and Statewide Overview of New Field Survey and Data . 49
3 Statewide New Field Data: Fields, Wells, Depths, Gravity ... 51
4 Statewide New Field Production Statistics 52
5 Total U.S. Drilling 58
6 U.S. Exploratory Drilling 61
7 U.S. New Field Exploratory Well Drilling (Wildcat) 61
8 New Field Data Summary 65
9 Estimated VOC Emissions From New Field Well Drilling 65
vn
-------
ACKNOWLEDGMENT
The support and guidance provided by Leo McCarthy, serving as Project
Officer for the U.S. Environmental Protection Agency, Oil & Hazardous Materials
Spills Branch, Edison, New Jersey, and Dave Markwordt of the U.S. Environmental
Protection Agency, Office of Air Quality Planning & Standards, Research Tri-
angle Park, North Carolina, is greatly appreciated. The cooperation in this
effort of Chevron USA, Shell Oil, Phillips Petroleum, and Exxon by allowing
visits and photographic documentation of typical oil and gas fields discovered
after December 1974 and of drilling rigs, is gratefully acknowledged. The con-
tribution of consultants D.S. Wedding with regard to drilling technology and
of Jay Simpson of O'Brien and Coin's Engineering, Inc. with regard to the dril-
ling muds and completion and workover fluids section of this report is also
gratefully acknowledged.
-------
SECTION 1
INTRODUCTION
Rockwell International, through its Energy & Environmental Systems Divi-
sion, Environmental Monitoring & Services Center (EMSC), has undertaken a
study for the assessment of oil production volatile organic compounds (VOC)
sources.
The program consists of a survey with the following tasks:
1. Determination of the new oil and gas fields in the 48 states that
have started primary production after December 1974.
2. Determination of the VOC emission potential and techniques for dril-
ling and gas exploration and production wells and the handling of
drilling muds.
3. Documentation of equipment and techniques in use for the assessment
and quantification (to the extent possible) of the potential VOC
sources, including mud operations, waste oils, and fugitive emis-
sions from operating equipment. Five areas defined by (1) above were
visited.
This report addresses the objectives stated above. Current practices in
well-drilling techniques, drilling and workover fluids, and well servicing and
workover are discussed, and a survey of new fields is described. The survey
data are used in conjunction with drilling information to define prospective
VOC sources, and the VOC forecast is made. Appendices A and B are available
under separate cover. Appendix A provides detailed data organized by state
and county, and Appendix B is an annotated compilation of more than 300 color
slides taken during this program of new field production and drilling sites in
five states. Appendices A and B are on file at the U.S. E.PA Office of Air
Quality Planning and Standards, Research Triangle Park, North Carolina.
1 ,
-------
SECTION 2
CONCLUSIONS
1. Drilling activity in 1980 will surpass the activity of the last sev-
eral years, with an estimated 13,607 exploratory wells to be drilled.
2. Drilling has made many technological improvements in the past several
decades, but the basic rotary method remains the one most often used.
3. VOC emissions from oil and gas exploration and production drilling
are small, although several potential sources of VOC emissions (namely, en-
trained gas and oil in drilling fluids, emissions from oil-based muds, and the
number of valves, flanges, etc. associated with fuel systems) are not well de-
fined. The VOC emissions calculated using simple assumptions give less than
10 kg per well per day.
4. Reporting of state oil and gas production information is not uniform
from state to state and not up to date.
5. The number of new fields reported give an order of magnitude estimate
that can be useful, but the different definitions used by the individual states
makes a direct comparison difficult. The collected information is adequate
for use as a parameter and estimate of the VOC potential if a satisfactory
model is developed for the VOC emission associated with an oil and gas well or
field.
6. Additional data in several key areas are required to make an estimate
of the VOC emissions associated with oil and gas well drilling and production.
These areas are:
a. Drilling
. Emissions associated with mud degassing
. Emissions from oil-based muds
\
. The number of components within the fuel gas system for
estimation of fugitive emissions
b. Oil and Gas Production
. A model of major subsystems (i.e., compressor) that will
allow estimation of components to which emission factors
currently developed can be applied.
-------
SECTION 3
RECOMMENDATIONS
1. Measurements should be made to verify the magnitude of the estimated
VOC emission values presented in this study.
2. Further effort should be devoted to defining more accurately a repre-
sentative new oil and gas facility or site in terms of VOC emissions. This
should include a survey of additional sites to establish one or more models
for assessment of potential VOC emissions.
3. Component population estimates obtainable from photographic documenta-
tion provided in Appendix B of this report should be supplemented with stream
composition data so that existing emission factors can be applied.
4. Oil and gas production data from new fields should be verified beyond
the information presented in this report.
-------
SECTION 4
CURRENT OIL/GAS WELL DRILLING TECHNIQUES
The well-drilling techniques and procedures now in use have evolved over
a period of many decades. From the early oil wells drilled with cable tool
drilling methods used in the drilling of water wells, the drilling technology
has advanced to include complex modern rotary drilling equipment, blowout pre-
venters, recirculating drilling fluids especially tailored with various addi-
tives, and well completion procedures. This section presents a brief review
of the well-drilling techniques and equipment now in general use.
BASIC DRILLING PROCESSES
Rotary Drilling
The vast majority of oil and gas well drilling is done by the rotary
method. In rotary drilling, a hole is gouged and cut through the various geo-
logical formations by specially designed bits attached to the bottom of a long
string of steel pipe and rotated by means of a rotary table that turns the top
pipe (the kelly) in the drill stem. The top pipe, or "kelly," has a square or
hexagonal cross-section and fits into a four- or six-sided kelly bushing lo-
cated in the rotary table. Drilling fluid, or drilling mud, is continually
circulated down the drill pipe, or drilling string, through the bit and up and
out of the hole through the annular space between the pipe and the borehole
wall. The drilling mud serves to cool the bit, flush pieces of rock, or cut-
tings, away from the bit and out of the hole, provides hydrostatic pressure to
prevent formation fluids or gases from migrating into the well bore and poten-
tially blowing out, seals porous formations, and provides lubrication for the
drill string and protection against corrosion.
Cable Tool Drilling
In cable tool drilling, the bit is attached to a cable and is repeatedly
picked up and dropped to punch through the rock formations. At intervals the
cable and bit are hauled out of the hole and a "bailer" or "sand pump" is run
in and out of the hole to remove the cuttings. When the hole is cleaned out,
the bit is again placed in the hole and the cycle is repeated until the de-
sired depth or the prospective zone is encountered.
Cable tool drilling is cheap and simple, but the absence of drilling mud
to provide a hydrostatic head in the hole can lead to uncontrolled release of
formation gases and fluids where encountered under pressure. There are still
areas of the U.S. where cable tool drilling is utilized.
-------
Experimental Processes for Hole Forming
The increased cost of drilling has led the industry to invest large
amounts of money in primary research facilities and expand their in-house re-
search efforts to improve and speed up the drilling process and investigate
innovative approaches to "making hole." For the next 5 years, however, it
appears that no radical developments will occur in drilling technology. The
changes will be evolutionary rather than revolutionary.
BASIC DRILLING EQUIPMENT - RIG COMPONENTS
A modern drilling rig accomplishes essentially four basic tasks: (1) pro-
ducing and transmitting power, (2) hotsting equipment for the drilling string,
casing and tubing, (3) rotating the drill string and bit, and (4) circulating
drilling mud to remove cuttings and maintain a safe hydrostatic pressure in
the well bore. The components included in a basic drilling rig will be dis-
cussed in terms of these four tasks.
Power System
some
Prime power sources for drilling rigs are almost always diesels, although
natural gas or liquefied gas engines are still used.
Power requirements for different drilling jobs may vary considerably, but
most rigs require from 0.75 to 2.2 MW (1000 to 3000 HP), which is provided by
two or more engines, depending on well depth and rig design. Shallow or moderate-
depth drilling rigs will be provided with 0.37 to 0.75 MW (500 to 1000 HP) for
hoisting the drill and for circulating the mud. Heavy-duty rigs for drilling
6100-m (20,000-ft) holes are usually in the 2.2-MW (3000-HP) class. Auxiliary
power for lighting, etc., may require 0.075 to 0.37 MW (100 to 500 HP). A
typical multi-engine setup with a mechanical rig is shown in Figure 1.
Until recently, the transmission of engine power to various tasks on a
rig was invariably found to be performed mechanically via belts, pulleys, and
chain drives. On modern rigs, however, diesel-electric units are installed.
On mechanical rigs, diesel engines will be equipped with hydraulic couplings
or torque converters to smooth out the power developed by the engine and
mechanically linked by chains and pulleys (the compound, Figure 1). The com-
pound delivers engine power to the rotary table, draw-works, and mud pumps.
Diesel-electric power, the method used to drive most operating rigs,
eliminates the complicated, cumbersome mechanical drives. Diesel engines,
located at convenient distances away from the rig (to reduce the noise level
at the rig), drive electric generators which, in turn, produce electricity that
is sent to electric switch and control gear (Figure 2). The electricity pro-
duced is used to power electric motors for the draw-works, rotary table, and
mud pumps. Because of the improvements in electrical switch-gear, i.e., inte-
grated circuits and chip circuitry, silicon-controlled rectifiers (SCR) are
rapidly replacing the standard diesel-electric rig design. Improved power and
torque curves are developed by the SCR conversion system.
-------
AUXILIARY BRAKE
ROTARY DRIVES
HIGH DRUM CLUTCH
HIGH DRUM DRIVE
0.52 MW (700 HP) ENGINE!
DRILLER'S
'/PLATFORM
CONTROL
PANEL
LOW DRUM
CLUTCH
FRICTION
CATHEAD
MAKEUP CATHEAD
LOW DRUM DRIVE
CAT HEAD DRIVE
INERTIA BRAKE
TRANS. CHAINS
COMPOUND
0.52 MW (700 HP) ENGINE
0.52 MW (700 HP) ENGINE
BELT OR CHAIN DRIVE TO PUMPS
Figure 1. Multi-engine and chain drive transmission
arrangement for a mechanical drilling rig.
(Courtesy Petroleum Extension Service (U, ofT. at Austin))
Hoisting Equipment - The Draw-Works
An oil or gas well is drilled with a bit at the bottom of a long string
of pipe, and drill collars. The total weight of this drill string is some-
times as much as 230,000 kg (about 500,000 Ibs) for a deep well. During the
drilling process the drill string must be hoisted out of the hole, disassem-
bled and stacked in racks at the side of the derrick, then reassembled and re-
placed in the hole. This cycle is repeated many times to replace worn drill
bits, run strings of casing into the well, test formations, take core samples,
etc. This hoisting is done by the draw-works (Figure 3). Derricks and masts
used to support the block and tackle system utilized for hoisting (the crown
block and traveling block) are rated in various ways in terms of vertical load
they can carry and the wind loading they can stand from the side. Derrick
capacity may vary from 144,000 to 680,000 kg (250,000 to 1,500,000 Ibs).
Most derricks and masts can withstand a wind load of 160 to 210 km/hr (100 to
130 mph) with the racks full of pipe.
-------
ENGINE
jCENERATO*
ENGINE GENERATOR NO I
MOUNTED ON
ENGINE
OSNEHATOH SET
ENGINE
™
ENGINE GENESATOH NO 2
5CTTOC1
CABINET I
"M*-f ^ -V
OMICLER3
CONTRCX.I.EP!
(IF REQUIRED)
Figure 2. Diesel-electric system for power and transmission.
(Courtesy Petroleum Extension Service (U. ofT. at Austin)
The draw-works shown in Figure 3 consists of a revolving drum (around
which is wound the tough, flexible wire rope that is reeved over the sheaves
of the crown and traveling blocks), a system of shafts, clutches, and chain
and gear drives for speed and direction changes. The other end of the steel
rope from the revolving drum is called the dead line and is fastened to a
deadline anchor and an apparatus that measures the tension in the line. The
draw-works also houses the main brake, which has the capacity to stop drum
rotation, and an auxiliary hydraulic or electric brake to absorb the momentum
created by a heavy load. The so-called catheads and catshafts that are part
of the draw-works serve for smaller hoisting and pulling jobs on the rig and
for operating pipe-handling tools.
Rotating Equipment
The rotary system (Figure 4) is comprised of the swivel assembly, the
kelly, the rotary table, the drill string, and the bit. The swivel assembly
sustains the weight of the kelly and drill string, permits its rotation, and
affords a rotating pressure seal and passageway for drilling mud to be pumped
down through the drill string.
-------
FAST
LINE
CROWN
BLOCK
DEAD LINE
WIRE LINE
(8 LINES ARE STRUNG)
TRAVELING BLOCK
DRILLING HOOK
DEAD LINE
ANCHOR
STORAGE
WHEEL
DRUM BRAKE
Figure 3. Rotary rig hoisting system.
-------
KEUY HOSE
T
KEUY
KEUY BUSHING
(OTARY TABLE
Figure 4. Rotary system.
-------
The kelly transmits torque from the rotary table, via the kelly bushing,
to the drill string and is free to move vertically throughout most of its
length as the drilling deepens the hole. It is also the unit through which
drilling mud is pumped down the string. Most kellys are about 12.2 m (40 ft)
long. Above the kelly is the kelly cock, which can be used to shut off back
flow in case of a blowout.
The rotary table is powered through a reduction gear driven by an elec-
tric motor or by chain drive through the draw-works from the diesel engines or
other prime movers. A lock on the rotary table prevents it from turning when
desired; the table can be locked when breaking out pipe without tne use of
backup tongs.
The drill string is composed of drill pipe and, near the base of the
string, heavy thick-walled tubes called drill collars. A length of drill pipe
is about 9.1 m (30 ft).
The drill string to be furnished by a contractor is often carefully speci-
fied in the drilling contract for a well. The operating company specifies
size and strength of drill pipe to be used. Hole conditions will govern drill
collar selection and number employed. Directional drilling or hole straighten-
ing will require additional modifications of the drill string to be made.
Protectors for drill pipe and casing are made of rubber. Locked firmly around
the pipe, they prevent metal-to-metal contact between the pipe and casing,
thereby reducing wear.
The bits used for rotary drilling are primarily of the roller-cone type
with three cones normally being used. Fewer and longer teeth are used on the
cones of bits intended for softer formations, while harder formations may re-
quire shorter and harder teeth. For very hard formations, a bit will have
cones fitted with tungsten carbide inserts. All bits have hardened steel
nozzles through which drilling mud can be ejected downward at high velocity
to flush away rock cuttings from the bit. Bits are designed to break, dis-
lodge, or fragment formation material in such a way that the circulation of
drilling mud will remove the cuttings. The several functions of a bit are
accomplished simultaneously. Formations have many different characteristics
and different bit types are available for drilling them at maximum rates and
energy efficiency. Often, compromises are made when variable formations are
drilled because of the time and expense involved in making a trip to change a
bit.
Normally, the drilling string will be rotated at between 75 and 250 rpm
under very high loads. After as few as 10 to 12 hours or as many as 150 hours
of use, the bits must be pulled out of the hole and replaced because of either
bearing or tooth wear.
Circulation System
The drilling mud circulation and treating system is depicted in Figure 5.
Bulk storage of drilling fluid materials, pumps, and mud mixing equipment are
placed at the start of the circulation system; working mud pits and reserve
storage are at the other end. Between these two is the circulating system with
10
-------
DHU.l. COI.1.,11,
Figure 5. Rotary rig fluid circulation and mud treating system.
-------
(1) auxiliary equipment for drilling fluid maintenance, and (2) equipment for
well pressure control. Drilling mud is pumped under high pressure from a suc-
tion tank or a mud pit outside the derrick, up a standpipe, through the kelly
hose and swivel to the drill string. After jetting from the bit and sweeping
away the rock cuttings, the mud runs through the annul us formed by the drill
string and the wall of the hole, through the blowout preventer stack (Figure
4) to the mud return line, then to a shale shaker for cuttings removal, and
finally to a settling pit and temporary storage in a sump pit. Settling and
sump pits are usually steel tanks. The so-called reserve pit is actually for
waste material and excess water around the location.
The mud pump is a reciprocating, gear-driven, dual-piston type of very
sturdy construction, capable of continuous service under heavy loads and cap-
able of handling abrasive, sand-laden muds. Pumps rated at 0.75 MW (1000 HP)
or more with working pressures of 17.2 to 20.7 MPa (2500 to 3000 lbs/in2) are
commonly used on deeper wells.
Exacting requirements related to maintenance of drilling mud necessitate
some important auxiliaries. Mud pit agitators help maintain a uniform fluid
mixture of mud materials. Other auxiliaries include (1) the cone-type desander
and desilter for removing fine drilled solids that would otherwise not settle
out, and (2) a vacuum degasser for quick release of entrained gas.
The basic equipment for well pressure control is located on the well cas-
ing beneath the rig floor in an assembly called blowout preventers (shown in
Figure 4). The uppermost preventer is typically an annular type that can seal
around the drill pipe or kelly. Two or three ram-type preventers may be pro-
vided in conjunction with the annular preventer. Other equipment in the blow-
out preventer "stack" permits connection of a line for mud return to the shale
shaker, a line to fill up the hole when making a trip, a kill line to pump mud
into the hole when needed to restore pressure balance, and lines to the choke
fittings for relieving pressures in the well bore when a potential blowout
situation exists.
A choke is a device to control pressure in the well bore through a control
of flow from the well. It may be fixed, adjustable, or automatic. Drilling
fluid and gas will be passed through a choke to a mud-gas separator that saves
usable mud and pipes the gas to a safe distance from the rig.
FUELS FOR PRIME MOVERS
Over 90% of all rigs and support equipment are powered by internal combus-
tion diesel engines. About 9% of the remaining drilling rigs are powered by
natural gas or liquid petroleum gas (LPG). The remaining 1% of all rigs are
totally electrically powered with an internal combustion engine system used as
a standby in case of power failure. These rigs are equipped with their own
substation transformer system so that they can tie into a high-voltage electri-
cal system.
Diesel fuel for powering drilling rigs is stored in 18.9 to 37.8 m (5,000
to 10,000 gallon) storage tanks located at a safe distance from the rig. Tank
storage is in an approved tank equipped with a pressure containment filler and
12
-------
usually with a 1720-Pa (4-oz) pressure relief disk. The fuel is transferred
to what is commonly called a "day tank" by periodically using a transfer pump
located on the major fuel tank. A day tank is sized to furnish approximately
12 hours of fuel for each engine.
Natural gas is furnished from a field or from nearby gas transmission
lines. A regulator system is installed for low-pressure distribution. Each
engine will have a small-volume tank for starting and dehydration of the fuel
prior to its use.
Butane and/or propane (LPG) is stored in large-volume pressure storage
tanks and piped for usage throughout the power area with a low-pressure sys-
tem for continuous feed.
DRILLING OPERATIONS
The basic operations involved in drilling a hole include: (1) keeping a
sharp bit at the bottom of the hole, (2) adding new drill pipe as the hole
deepens, (3) removing the drill string from the hole, replacing a worn bit,
and running the string back down the hole, and (4) running and cementing
casing.
Early in the drilling operation, a large-diameter pipe called conductor
pipe is cemented into a hole bored by the rig or by a truck-mounted light-
duty rig or, if the ground is soft, the conductor pipe is simply driven into
place by a pile driver. Generally, a conductor pipe will extend 6.1 m (20 ft)
into the ground, but for very soft ground it may be set at 30.5 m (100 ft) or
deeper. The purpose of the conductor pipe is to prevent soft soil near the
surface from caving in and endangering the rig foundation. After the conductor
pipe is set in place and blowout preventers are installed, a large-diameter bit
will be set on the drill string, lowered into the conductor pipe hole, and well
drilling will begin on this "surface hole." After drilling has proceeded
through the soft, sticky formations, sand and gravel beds and fresh water bear-
ing formations (perhaps 152 to 1520 m [500 to 5000 ft]), the surface casing
(steel pipe) is lowered into the hole and cemented to the bore hole wall. The
surface casing seals off fresh water bearing formations (hence protecting them
from contamination), and prevents loose shale, soft formations, sand or gravel
from falling into the hole.
Following the installation of the surface casing, a smaller bit is instal-
led and drilling will proceed to greater depths. Often during this intermedi-
ate stage of the drilling process, troublesome formations are encountered.
These troublesome formations are those that contain high-pressure gas or liquid
that could blow out unless handled very carefully with the recirculating dril-
ling mud system, or that may cave into the hole. At some point, a smaller dia-
meter casing string, the intermediate string, will be run into the hole and
cemented. This intermediate string extends from the surface down through the
surface casing string and to the bottom of the intermediate hole.
The final portion of the hole is drilled to the promising formation with
a still smaller bit. The final casing is the oil or production string. An
oil string is not run into the hole until the cuttings, an electric log survey,
13
-------
and other evidence from tests indicate that the well should produce oil or gas
at an economical rate and in commercial quantities. Figure 6 depicts a cross-
section of a well bore with the casings set in place.
WELL COMPLETION
If a decision is made to complete the well, production casing is set and
cemented in the wall through the oil or gas bearing zone. The section of cas-
ing covering the producing zone is then perforated to permit the oil or gas to
flow into the well (Figure 7). The perforations are usually made by igniting
shaped charges set in a special device lowered into the well to the depth of
the producing zone.
The oil or gas is not usually removed from the well through the production
casing. Small-diameter tubing, which permits more efficient production than
casing, is safer and can be removed if it becomes plugged or damaged. Tubing
is run into the well with a packer that seals the annular space between the
production casing and the tubing, normally when the well is capable of flowing
naturally. The packer is located somewhat above the perforated casing and the
producing zone, as shown in Figure 7. The packer serves to protect the upper
portion of the casing from corrosion or pressure.
When the tubing string and the packer is set in place, a number of valves,
a Christmas tree, will be installed at the top of the casing to control and
direct the hydrocarbon flow. In Figure 7 this is labeled the "well head."
There are occasional problems with the oil/gas flowrate out of a formation
because of low formation permeability. When this occurs, various procedures
are initiated to open up the structure. If the formation can be easily at-
tacked by acid, an acid mixture will be pumped into the formation to etch chan-
nels to increase the permeability and enhance oil/gas flowrates. Permeability
can also be increased by pumping fluids into the formation under high pressure
and fracturing it. Fracturing fluids will often contain small particulates
that prop open the fractures after the pressure has been released.
AUXILIARY RIG EQUIPMENT
Drilling Mud Maintenance
The importance of drilling mud to the hole-making process has resulted in
the development of equipment for mud maintenance. In addition to shale shakers
which are intended to remove larger size cuttings before the mud enters the mud
pits or storage tanks, desilters and desanders (hydrocyclones) can be mounted
on the mud pits for the removal of fines as small as 25 microns. Decanting
centrifuges are also being used more often to remove solids from the mud.
These items are depicted in Figure 8 as part of a mud treatment system.
Drilling mud can at times pick up moderate amounts of formation gas during
passage through an uncased portion of the hole. Since this entrained gas low-
ers the mud density anywhere from a few hundredths to several tenths kg per
liter (a few tenths to several pounds per gallon), it must be removed before
the mud is recirculated. Reportedly, many wells completed as oil wells will
14
-------
CONDUQ!Qft'==
PIPE
SURFACE
CASING
SHALE
OR CLAY
H GRAVEL BED
|S£2t?SHALE
^r-rv_, FRESH WATER
:iL SAND
SHALE
INTERMEDIATE
PRODUCTION
CASING
CEMENT
CASING SHOE
nyty •„.•+!:£»* LOOSE
^is^w*.*" SURFACE SOIL
r LIMESTONE
OIL SAND
:- SHALE
Figure 6. Casing strings and pipe used in an oil well.
(Courtesy Petroleum Extension Service (U. ofT. at Austin))
15
-------
WELL HEAD
CONDUCTOR
PIPE
sass
SURFACE
CASING
OIL SAND
TUBING
PACKER
PERFORATIONS
CASING
SHOE
Figure 7. Typical well completion.
(Courtesy Petroleum Extension Service (U. of T. at Austin)
16
-------
OESiNOES
OESILTER
CONDITIONS:
Drilling: Single pump (under 3 m/min [800 gpm]) to holes. Medium-fast penetration rate.
Centrifugal Pumps: Single-purpose; feeding to single unit.
Removal Equipment": Screens, sand trap, degasser, desilter, centrifuge.
NOTE: 'OVERFLOW when degassing; UNDERFLOW when not degassing.
Figure 8. Drilling mud maintenance system.
yield gas in the mud. Mud with gas bubbles must be watched carefully to avoid
any possibility of blowout. Removal of gas from the mud is done with degassers,
since normally the mud is too viscous to permit a large fraction of the bubbles
to float to the surface in the mud tanks. The degassing method can consist of
flowing the mud in thin layers where most gas bubbles will be moved close
enough to the surface to emerge and break, or by spraying a thin sheet of the
mud against a wall. Vacuum degassers will also flow the mud in thin sheets;
the vacuum increases the bubble size and hence its buoyancy, which somewhat im-
proves the possibility of the bubble surfacing and breaking. The vacuum pump
serves to remove the natural gas-air mixture from the degasser to a remote lo-
cation where the gas can be flared.
Another component of the mud recirculating system includes the mud hopper
which is used to add solid materials to the mud stream to alter the mud proper-
ties in some desired manner. A mud house is used for storage of materials that
might be required for mud treatment or maintenance.
17
-------
Well Control
A bore hole filled with drilling mud provides a hydrostatic head to guard
against the blowout of high-pressure formation fluids. Occasionally, forma-
tion fluids can enter the mud in sufficient quantities to cause a "kick."
During a kick the level of mud in the pits or mud tanks may rise or mud may
flow out of the well even with the pump off. When this occurs, the blowout
preventers can be activated to close off the annular space between the drill
pipe or kelly and the surface casing used for mud flow, and fluid control
adjustments can then be made to eliminate the kick.
18
-------
SECTION 5
DRILLING MUDS
The solid and liquid wastes generated in the process of drilling oil and
gas wells depend to a large extent upon the type of drilling fluid used. There
are, of course, other factors. Some of the more important other factors are:
• Types of formations drilled
• Types of bits used
• Drilling practices — such as weight on bit and rotary speed
t Total drilling time
• Utilization of solids removal equipment
Consideration of such factors as these are part of the complex technology
of drilling engineering. This discussion will be directed primarily toward the
use of liquid drilling fluids, with reference to the other factors when they
are of particular significance.
Gaseous wastes result from drilling with air or gas. When compared with
use of liquid drilling fluids, however, drilling with air or gas is relatively
insignificant and will not be included in this discussion.
The primary functions of the drilling mud are to:
• Control formation fluid pressures
• Transport drill cuttings to the surface
• Provide borehole stability
• Protect productive formations
• Protect against corrosion
• Cool and lubricate the bit and drill string
Drilling conditions vary so drastically that the industry utilizes dozens
of different additives to allow the drilling mud to accomplish these purposes.
Hundreds of products are listed in World Oil's fluids guide, but many of these
19
-------
are different trade names for the same material. Only a few of the materials
would be present in a particular mud system at any given time.
DRILLING MUD COMPOSITION
The materials used in a drilling mud vary depending upon the mud type,
with the weighting material as a major exception. At this time the weighting
material used in all types of drilling muds (water-based, brine-based, or oil-
based) is almost exclusively barite (mined BaS04). The characteristics that
make barite desirable as a weighting material are:
• High specific gravity (API specification of 4.20 minimum)
• Moderate hardness (2.5 to 3.5 MOH)
• Low water solubility and chemical inertness
• Relatively low cost
There has been some small usage of certain iron oxide materials, either
separately or as a blend with barite. Recently, ilmenite (iron titanate) has
been introduced, but quantities used are still insignificant. Barite usage in
drilling muds in the United States has been estimated at about 2.3 million
tons* for 1978, including both land and marine operations. The concentration
of barite in a drilling mud may vary from about 143 kg/rrH (50 Ib/bbl) for nor-
mal pressure formations to perhaps 1430 kg/m^ (500 Ib/bbl) for abnormally high
pressure formations. In a weighted mud, therefore, the majority of the solid
material will be the essentially inert barite.
Water-Based Muds
Most muds used for drilling on land have fresh water as the continuous
liquid phase. The mud may consist simply of water and formation solids, but
ordinarily commercial additives are utilized. Some of the commonly used clas-
ses of materials are described in the following paragraphs.
Clays—
Formation clays become incorporated in a fresh-water mud from shale forma-
tions drilled. Usually the quality of formation clays is such that mud viscos-
ity increases excessively before providing the desired cuttings-carrying capa-
city, suspension of barite or filtration control. Commercial clays, therefore,
are added to most fresh-water muds. Bentonite (montmorillonite mined in the
Wyoming area) is used at concentrations of 14 to 86 kg/rrr (5 to 30 Ib/bbl).
Commercial bentonite often contains 0.25 to 1 kg/ton (0.5 to 2.0 Ib/ton) of a
sodium polyacrylate polymer and 0.5 to 5 kg/ton (1 to 10 Ib/ton) of soda ash
to increase the efficiency. Bentonite is second to barite as to quantity used
in drilling muds, with 885,000 tons reported for 1975 for the United States.
* All ton designations not in parentheses are metric tons.
20
-------
Dispersants--
Dispersants are added to water-based muds to lower viscosity, gel strength,
and filtration rates. Chrome!ignosulfonates are the most widely used and rank
third as to quantity of mud additives. U.S. consumption is about 68,000 tons/
year. The chrome!ignosulfonates are manufactured from the lignin liquor ob-
tained in the processing of paper pulp from wood. Hexavalent chromate in the
form of sodium dichromate is reacted with the lignin, reduced to one trivalent
state, and complexed with the lignin as cross-linking occurs. The final prod-
uct is a weak organic acid. Typical concentrations of chrome!ignosulfonate in
mud would be from 1.4 to 43 kg/m3 (0.5 to 1.5 Ib/bbl). Caustic soda is custom-
arily added to the mud, along with the chrome!ignosulfonate to maintain an
alkaline environment.
Lignite is widely used in fresh-water muds as a mild dispersant and to
reduce filtration rates. U.S. drilling fluids consumption for 1979 is esti-
mated as 54,000 tons. Drill ing-mud-grade lignite is the mineral leonardite,
a naturally occurring humic acid from the North Dakota area. Caustic soda is
added with the lignite for treating mud. Typical concentrations of lignite in
mud would be 2.9 to 29 kg/m3 (1 to 10 Ib/bbl). Chemically modified lignite
products are also used, including causticized, oxidized, sulfonated, and sul-
fomethylated materials.
There is some usage of modified tannins as dispersants. Polyphosphates
(used both as dispersants and in treating for calcium) are listed under inor-
ganic chemicals.
Organic Polymers--
Various types of organic polymers are used to aid in hole-cleaning, bar-
ite suspension, and filtration control. Some of the products are made from
natural polymers such as corn starch, potato starch, or guar gum. The more
widely used products are synthetic polymers such as carboxymethy! cellulose,
hydroxyethyl cellulose, xanthum gum, and polyacrylamides. These nontoxic prod-
ucts are added to muds at low concentrations (0.14 to 5.7 kg/m3 [0.05 to 2 lb/
bbl] being typical). An exception would be the starch materials used at con-
centrations of 5.7 to 29 kg/m3 (2 to 10 lb/bb!). Starch consumption for 1977
is estimated at 13,600 tons, cellulosic derivatives at 11,300 tons, and other
polymers at about 3,200 tons total.
Inorganic Chemicals--
Inorganic chemicals are added to muds for purposes such as controlling
alkalinity, adjusting calcium ion concentration, scavenging oxygen and su!-
fide, and corrosion protection. For the most part, these chemicals react with
other components of the mud and are neutralized, precipitated, or complexed.
An example of neutralization would be caustic soda reacting with lignite to
form sodium humate and water. Typical of precipitation would be soda ash re-
acting with calcium sulfate (incorporated while drilling gypsum) to form in-
soluble calcium carbonate. Sodium chromate added to a 1ignosulfonate mud being
used at high temperature would be an example of complexing, with the chromate
being reduced while cross-linking the thermally degraded chrome!ignosulfonate.
Generally, chemicals of this type are not maintained in the mud at a selected
concentration. Rather, they are added as needed for reaction, based on chemi-
cal analysis of the mud and filtrate. Some of the widely used chemicals, with
21
-------
approximate quantities used in 1977, are:
/
Sodium Hydroxide (caustic soda) 45,000 tons
Sodium Carbonate (soda ash) 18,000 tons
Calcium Hydroxide (lime) 9,000 tons
Sodium Chromate and Bichromate 3,600 tons
Phosphates 1,400 tons
Sodium Bicarbonate (bicarb) 450 tons
Calcium Sulfate (gyp) 450 tons
Sodium and Ammonium Bisulfite 140 tons
Basic Zinc Carbonate 90 tons
Surfactants--
Surfactants are used in water-base muds as lubricants, emulsifiers, cor-
rosion inhibitors, detergents, and defoamers. Since these materials are film-
formers (acting on solid surfaces and at liquid interfaces), the concentrations
required are extremely low. The following indicates the types of surfactants
and quantities used in 1977:
Fatty Acids and Soaps 4,500 tons
Ethoxylated Phenols 1,600 tons
Amine Derivatives 900 tons
Alcohols Less than 9 tons
Lost Circulation Materials--
Lost circulation materials of a considerable variety are sometimes added
to water-base muds to combat loss of mud to highly permeable or fractured for-
mations. Mostly these are natural materials of a granular, fibrous, or plate-
like structure. Walnut shells, cane fiber and mica are examples. Typical of
the method of use would be to add a high concentration of sealing material
(perhaps 86 kg/m3 [30 lb/bbl]) to a small volume of mud (perhaps 47.7 m3 [300
bbl]) and to spot that batch in the loss zone. Usage of lost circulation ma-
terials in 1977 is estimated at 18,000 tons.
Biocides—
Fresh-water drilling muds seldom require biocides. Occasionally, a bio-
cide such as paraformaldehyde might be added at concentrations of perhaps 0.29
kg/m3 (0.1 Ib/bbl) to a mud containing xanthum gum. Generally, biocide usage
would be limited to brine muds of intermediate salinity that contain pregela-
tized starch.
22
-------
Salts--
Salts used to prepare brine-based muds are principally sodium chloride
(NaCl) and potassium chloride (KC1). The NaCl is available as a produced
brine in certain localities. As such, it provides an inexpensive liquid phase
for combatting shale hydration or limiting solution of salt formations to be
drilled. In certain situations where formation pore pressure and permeability
are low (such as deep drilling in the Permian Basin), NaCl brine has sufficient
density to serve as a clear-water drilling fluid. High-molecular-weight poly-
mers are used to flocculate drilling solids, causing solids to settle in sur-
face pits and allow the clean brine to be recirculated. Otherwise, NaCl sys-
tems are customarily treated with clays, polymers, and barite. NaCl concen-
tration in the liquid phase is usually between 10 and 26% by weight (saturated).
NaCl used in drilling muds is estimated at 45,000 tons for 1977.
KC1 —
KC1 is used primarily to provide a mud to combat shale problems. Potas-
sium has been found to alter the hydration and swelling of clays having an ex-
pandable lattice structure. Thus, KC1 muds containing concentrations of 3 to
20% KC1 have been found to provide borehole stability equal to or better than
a saturated NaCl mud. KC1 usage is estimated at 4,500 tons for 1977.
Clays--
Clays of the bentonite type do not hydrate and disperse effectively in
brine. This limitation can be overcome to some extent by prehydrating the ben-
tonite in fresh water before adding it to the brine system. To avoid the in-
convenience of prehydrating, salt-water clays are often used. Attapulgite from
the Georgia-Florida area has a rod-like particle shape that provides cuttings-
carrying capacity and aids in suspending barite in brine-based muds. Concen-
tration in a typical mud would be 29 to 86 kg/m3 (10 to 30 Ib/bbl). Attapulgite
usage for 1977 is estimated at 73,000 tons. There has been some use of sepio-
lite from California as a clay for brine-based muds.
Oils-
Oils are sometimes used in fresh-water mud to reduce drill string torque
while drilling, to reduce drag when pulling the drill string, and to reduce
shale balling of bits, drill collars, and stabilizers. The oil might be diesel
oil, or vegetable oils (estimated at 450 tons for 1977) would be used where
rapid biodegradability is considered necessary.
Asphaltic Materials—
Asphaltic materials are added to fresh-water muds to serve some of the
same purposes as oil. Also, these materials are used to aid in combatting
shale instability. Usage of both petroleum asphalts and gilsonite is estimated
at 9,000 tons for 1977.
Example--
A typical water-based mud would be a lignosulfonate/1ignite system having
a composition such as:
23
-------
Component Concentration, kg/m (Ib/bbl)
Water 570 to 970 (200 to 340)
Bentonite 43 to 86 (15 to 30)
Lignosulfonate 5.7 to 29 (2 to 10)
Lignite 2.9 to 17 (1 to 6)
Sodium Hydroxide 2.9 to 14 (1 to 5)
Barite 0 to 1430 (0 to 500)
Brine-Based Muds
Most of the materials used in water-based muds might also be used in brine-
based systems. The following are some of the aspects that are specific to
brine systems.
Fibrous Materials—
Fibrous materials such as asbestos and shredded paper have had limited use
in brine-based systems to provide a sweep to lift cuttings and sloughings from
the well. While asbestos usage in 1977 is estimated at 9,000 tons, utilization
of this type of product has since declined drastically.
Example—
A typical brine-based mud composition would be:
Component Concentration, kg/m (Ib/bbl)
Water 860 to 986 (300 to 345)
Bentonite 0 to 29 (0 to 10)
Salt (NaCl, KC1) 29 to 290 (10 to 100)
NaOH or KOH 0.3 to 0.9 (0.1 to 0.3)
Polymer (CMC, Polyacrylamide) 1.4 to 5.7 (0.5 to 2)
Barite 0 to 860 (0 to 300)
Oil-Based Muds
Oil-based muds are used for special purposes, generally when water-based
systems have been ineffective or excessively expensive. Oil-based muds have a
high initial cost, are objectionable to crews when being used, and call for
special handling because of environmental constraints. The following are some
of the applications that justify the use of oil-based muds:
24
-------
• Protecting productivity of shaly sands
• Drilling troublesome shales
• Drilling water-soluble formations
• Drilling deep, hot holes
• Preventing differential pressure sticking
• Combatting severe corrosion problems (high-pressure ^S)
• Coring for connate water content, or where poorly consolidated
Oil-based muds are systems having oil as the continuous liquid phase and
water as a dispersed, emulsified phase. In earlier years, emphasis was placed
on the concentration of water in the mud, with the term "invert emulsion"
used for muds containing water at more than 10% by volume. Today it is recog-
nized that all commercial oil muds are prepared to contain a small amount of
water and that water is always incorporated during use. No distinction, there-
fore, is warranted between oil-based and invert emulsion muds.
The oil used in oil-based muds is almost exclusively No. 2 diesel fuel,
with No. 1 diesel fuel used in cold climates. On rare occasions, crude oil
might be used to save transportation costs.
Salts are used to increase the salinity (lower the aqueous activity) of
the emulsified water phase to obtain a sufficient oil mud osmotic force to
prevent hydration of shale formations drilled. CaCl2 is widely used for this
purpose because aqueous activities can be obtained low enough to cope with
shales having a high water demand. NaCl is used sometimes for the less strin-
gent conditions.
Oil-dispersible clays are used in oil-based muds for viscosity and gel
strength to lift drilled cuttings from the hole and to suspend weighting mate-
rial. The clays (usually bentonite) are made oil-dispersible by reaction with
quaternary ammonium compounds or other amine derivatives. Concentrations of
2.9 to 17 kg/m3 (1 to 6 Ib/bbl) are customarily used.
Emulsifiers and wetting agents are used to emulsify water and to prefer-
entially oil-wet solids and metal surfaces. The most common surfactants used
in oil-based muds are:
• Ca soaps of high-molecular-weight fatty acids
• Polyamides
e Alkylarylethoxylates
• Na salts of alkylaryl sulfonates
Concentrations o
surfactants are used.
Concentrations of 5.7 to 14 kg/m (2 to 5 Ib/bbl) of one or more of the
25
-------
Asphaltic materials are often used In oil-based muds to augment the sus-
pension provided by oil-dispersible clay and to provide low filtration rates.
Air-blown asphalt at concentrations of 29 to 200 kg/m3 (10 to 70 Ib/bbl) might
be used.
Oil-dispersible lignite is sometimes used for filtration control in oil-
based muds. This type of product is made by dissolving lignite in water and
then reacting it with amine derivatives. Oil-dispersible lignite is used at
concentrations of 5.7 to 34 kg/m3 (2 to 12 Ib/bbl).
Lime (CaO or CaOH) is used in most oil-based muds to form calcium surfac-
tants, to maintain an alkaline environment, and to react with acid gases such
as C0£ and H2$ that might be encountered. Typical concentrations would be 5.7
to 11.4 kg/m3 (2 to 4 Ib/bbl), with perhaps 29 kg/m3 (10 Ib/bbl) maintained
if high-pressure H2S formations are being drilled.
An example of a typical oil-based mud composition would be:
Component Concentration, kg/m (Ib/bbl)
Diesel oil 430 to 630 (150 to 220)
Water 100 to 140 (35 to 50)
CaCl2 43 to 71 (15 to 25)
Surfactant (soap, polyamide) 14 to 57 (5 to 20)
Filtrate reducer (amine lignite) 0 to 29 (0 to 10)
Gellant (amine clay) 5.7 to 11.4 (2 to 4)
Barite 0 to 1430 (0 to 500)
FACTORS AFFECTING TYPE OF DRILLING FLUID USED
A number of factors affect the type of drilling mud used. If conditions
would permit, drilling with air or gas would probably provide the fastest rate
of penetration. Conditions required are:
• Low formation pressures
• Strong, competent formations
• No highly permeable formation containing water or oil
There are not many situations where air or gas is sufficient as the dril-
ling fluid. The next choice in terms of cost and drilling rate would be clear
water or brine. Conditions for clear-water drilling are:
• Normal or subnormal formation pressures
• No highly permeable formations
26
-------
• No extremely water-sensitive shale formations
Again, such conditions are uncommon. Usually, a liquid mud is needed.
The choice of which type of liquid mud to use is based on consideration of a
number of factors.
Formation Mineralogy
Often the composition of the formations to be drilled determines what
type of mud can be used. Some formations may require a special mud to help
avoid excessive hole enlargement. Others may dictate a certain mud to avoid
hole size being reduced by buildup of filter cake or plastic deformation of
the formation.
Another aspect is the effect of the formation on control of mud proper-
ties and ultimate mud maintenance costs. Some formations require special muds
that can tolerate the formation solids without excessive treatment or loss of
control of mud properties.
Shales—
The problems encountered when drilling through shale formations are hole
enlargement and mud-making tendencies. Hydration of pressured shales contain-
ing swelling-type clays can also cause plastic flow and reduction of hole size.
Muds that combat shale hydration are utilized to achieve borehole stability as
well as minimize mud-making. In water-based muds, rate of shale hydration can
be slowed by using adsorptive polymers and minimizing the use of dispersants.
The salts in brine-based muds lessen the osmotic forces tending to hydrate
shale. A brine/polymer mud, therefore, is more effective than a fresh-water
system. If a potassium salt system is used, further help is obtained by limit-
ing clay swelling. Hydration of shale can be eliminated by use of an oil-based
mud having a high salinity in the dispersed water phase. Oil wetting of the
shale prevents the initial surface hydration, and low aqueous activity of the
water in the oil mud prevents subsequent osmotic hydration.
Sands--
Drilling through sand formations presents the problem of filtration and
filter cake buildup. If the differential between mud hydrostatic pressure and
formation pore pressure can be kept low, the main problem is reduction in hole
size. Any of the mud types can be conditioned to have very low filtration rate
to combat this problem. Bentonite, along with high concentrations of lignosul-
fonate and lignite, can serve the purpose in water-based muds. Polymers can be
used in either water-based or brine-based muds. Lowest filtration rates of
all can be obtained with oil-based muds.
High differential pressure creates a special problem in permeable sands.
The drill string that becomes buried in the filter cake becomes subject to the
differential pressure and tends to become stuck against the wall of the hole.
Surfactants, oils and lubricants are used in water- or brine-based muds for
help in combatting this problem. Differential pressure sticking is eliminated
for all practical purposes by a low-filtrate oil-based mud because of the good
lubricity of the extremely thin filter cake.
27
-------
Carbonates--
Carbonates affect the selection of mud type primarily because of interest
in obtaining improved rates of penetration. Low-solids, water-based, and
brine-based muds are helpful. If other problems dictate an oil-based mud be
used, low-colloid systems are now proving to provide greatly enhanced drilling
rates.
Soluble Salts-
Soluble salts (usually Nad) often dictate use of a brine-based mud to
avoid excessive hole enlargement. Salt contamination of most water-based muds
would also make control of mud properties very difficult. Hole enlargement in
drilling salt formations can be eliminated by use of oil-based muds. Mud
properties can be readily controlled if care is taken to utilize solids con-
trol equipment to screen the fine salt particles out of the mud.
Formation Pore Pressure
Selection of the type of mud to be used is affected by the formation pore
pressures anticipated. Highly permeable formations having low pore pressures
create a probability of loss of mud to the formation. Use of muds having a
high cost per barrel (such as some brine polymer muds or oil-based muds) can
become prohibitively expensive because of mud losses.
High formation pore pressures usually require high mud densities. Some
nondispersive water-based or brine-based muds are difficult and expensive to
control at mud densities much above 1.7 kg/liter (14 Ib/gal).
Formation Fluids
Selection of the mud type also takes into consideration the type of forma-
tion fluids that are to be encountered. Usually, mud density will be adjusted
to prevent formation fluids from entering the well. Fluids in the actual vol-
ume of formation drilled, however, will enter the mud system. Also, allowance
must be made for some fluid entry due to fluctuations in mud pressure.
Salt water, like salt formations, can be a serious contaminant for many
water-based muds. Lignosulfonate muds are often used to provide some tolerance
for salt water. Low-solids polymer muds can be used with proper utilization of
equipment to remove formation solids. Oil-based muds have considerable toler-
ance for salt water, but uncontrolled contamination would call for excessive
oil dilution and maintenance treatment.
Hydrogen sulfide is more serious as a personnel hazard and cause of corro-
sive failure than as a mud contaminant. Formations containing H£$ at normal
pressure can be handled by controlling mud alkalinity and using sulfide scav-
engers in water-based or brine-based muds. Oil-based muds are used to cope
with formations containing H£S at very high pressure. Personnel must still be
protected from H2$ that reaches the surface, but high-strength steel is pro-
tected by the mud from sulfide stress cracking.
Contamination of a water-based or brine-based mud with carbon dioxide calls
for lime and caustic soda for maintenance of alkalinity. Both mud properties
28
-------
and corrosion can become a problem if proper care is not taken. A lime mud
(highly alkaline water-based system maintained with 5.7 to 14.3 kg/m^ [2 to 5
Ib/bbl] of free lime) provides good stability when coping with (XL.
Petroleum oil or gas is not usually a serious contaminant of drilling mud.
Most muds can tolerate small amounts of oil with no problem other than possible
environmental considerations at time of disposal. Gas is usually separated by
a gas separator and/or degasser. Gas separates quite readily from an oil-based
mud. Some water-based muds (particularly the nondispersive systems) tend to
entrap gas and may require treatment with a surfactant as a defoamer. Brine-
based muds usually require use of defoamers to aid in release of gas.
Formation Temperature
An important factor in the selection of mud type is the anticipated for-
mation temperature. Most of the organic additives used in brine-based muds
degrade badly at temperatures in the range of 120°C to 150°C (250°F to 300°F).
Upper limits for most water-based systems is somewhat higher, perhaps 150°C to
180°C (300°F to 350°F). The widely used lignosulfonates degrade in this range
to form products that cause problems in control of rheology and filtration.
Lignite degrades in this range, but the degradation products are less detri-
mental. If kept free of contamination from salt, cement, etc., a lignite sys-
tem can have reasonable stability up to about 200°C (about 400°F).
A special aspect of thermal stability of aqueous muds is the reaction of
hydroxyl with shale, sand, and clays in the presence of calcium to form cemen-
titous material. The reaction is time/temperature-dependent. The longer an
alkaline mud is used, and the higher the temperature, the more of the cement-
ing material that is formed. A high-solids lime mud used at formation temper-
atures above 120°C (250°F) for several weeks, therefore, can be expected to
gel excessively or solidify when left in the hole during trips.
Oil-based muds are generally used for stability when drilling formations
having temperatures of 204°C to 288°C (400°F to 550°F).
Other Factors
Hole Deviation—
Hole deviation can be a factor in mud selection because of the need for
good hole cleaning and lubricity. Borehole stability is needed to permit con-
trol of directional drilling. Muds will be selected, therefore, to control
shale hydration and filter cake buildup. Lubricants may be added to the mud.
Economics and Logistics--
Brine-based muds may be used where there is an economical source of com-
mercial brine. Oil-based muds are more likely to be used if local usage war-
rants installation of liquid mud plants for mixing and storing the muds.
Polymer-treated muds sometimes are used because of drayage costs of greater
quantities of bentonite tend to offset the lower cost per ton.
29
-------
Governmental Regulations —
The choice of mud type is sometimes limited by governmental regulations.
Use of brine-based and oil-based muds is prohibited in certain localities.
Requirements for restoral of the drill site can also be a factor. Sometimes
mud and cuttings must be removed from the drill site, favoring use of an in-
hibitive mud and good solids removal equipment.
FACTORS AFFECTING QUANTITIES OF MUD AND CUTTINGS GENERATED
Obviously, the minimum quantity of cuttings generated in a drilling oper-
ation will be determined by the diameter and depth of hole. The quantity of
mud generated will be related to the hole dimensions, but other factors are
also involved. Types of bits used, drilling practices, and total time of the
drilling operation all affect the disintegration of cuttings and subsequent
mud-making. To minimize quantities of mud, bit selection and drilling prac-
tices should be directed toward forming large-formation chips at a maximum
rate of penetration, lifting the chips efficiently to the surface, and effi-
ciently removing the chips from the mud. Time of use of the mud would be mini-
mized to lessen attrition and disintegration of solids.
In practice, compromises must be made. Time must be allowed for logging
and testing. Directional control may dictate controlling rate of penetration.
For various reasons, quantities of mud and cuttings generated may vary widely
for a given size and depth of hole.
Type of Formations Drilled
One factor over which the operator and contractor have no control is the
types of formations to be drilled. As discussed previously, shales tend to
hydrate and either erode or slough when drilled with aqueous muds. Unconsoli-
dated sands also can cause hole enlargement and result in greater quantities
of mud and solid waste. Water-soluble formations can cause hole enlargements
and increased mud volume.
Even more important than the effect on hole volume is the effect that
shale composition has on total mud volume generated. A soft shale containing
swelling-type clays can yield perhaps 8.8 to 14 m3 (50 to 80 barrels) of 15-cp
mud per ton of solids when mechanically dispersed and fully hydrated in fresh
water. A hard shale composed of non-swelling clays might yield only 0.88 m3/
ton (5 bbl/ton). In brine-based muds the yield of the soft shale would be
drastically reduced, but there might be little change in the yield of the hard
shale. Use of oil-based mud would result in yields of less than 5 bbl/ton for
both the soft and hard shales.
Types of Mud Used
Selection of mud type is an option that the operator has to help control
the volume of mud and cuttings formed. For minimizing hole enlargement and
mud-making while drilling shale or salt formations, for example, the major mud
types could be rated in the following order:
1. Oil-based mud (with salinity control)
30
-------
2. Brine-based mud (with polymers)
3. Water-based mud (nondispersive with polymers)
4. Water-based mud
Solids Removal Equipment
Another option that can be utilized to lessen the volume of mud gener-
ated is utilization of mechanical means of solids separation. Shale shakers
(vibrating screens) are used during all phases of most drilling operations.
Screens can be used to separate drilled solids as fine as 140 microns.
For unweighted mud, desanders and desilters (hydrocyclones) are being
used to remove solids as fine as about 25 microns. Various mud cleaners are
available for use with weighted mud. The mud cleaner utilizes a hydrocyclone
to recover most of the liquid phase of the mud. The solids discharge from
the underflow of the cones is dropped onto a fine-mesh screen (120, 150, or
200 mesh) where the coarser drilled solids are removed. The barite particles
are small enough to pass through the screen and be returned to the active mud
system. The net effect is to remove drill solids as fine as 74 microns.
Decanting centrifuges are being used more frequently to remove solids
from unweighted mud. The high-speed units can separate solids as fine as 2
microns. With weighted mud, decanting centrifuges are used to recover barite
from mud that has accumulated excessive drilled solids and is to be discarded.
Effective utilization of a full suite of solids removal equipment can
drastically reduce the volume of mud required to drill a well. In 1976 an
experiment was conducted to determine if a well could be drilled with no
liquid mud waste. Unweighted mud was used to drill to below 3050 m (10»000
ft) in Wyoming. The shales encountered were hard and nondispersive in the
lightly treated fresh-water bentonite mud. By using all of the solids removal
equipment continuously while drilling, all drilled solids were removed mechan-
ically and the only liquid mud was that in the active system. Such complete
success would not be expected under normal drilling conditions. (In the ex-
periment, for example, drilling would be stopped if the solids removal equip-
ment was not functioning.) Also, a similar attempt was not completely suc-
cessful when soft swelling-type shales were drilled in South Louisiana. Mud
volumes were reduced, but liquid waste mud was not eliminated.
Examples of volumes of mud and cuttings generated can be presented only
to indicate some typical conditions. Actual quantities vary from the experi-
mental well with no waste liquid mud to perhaps 16,000 m3 (about 100,000 bbl)
of waste for a very deep well. The following can be considered representative
of three classes of well depth.
Shallow - 914 to 3050 m (3,000 to 10,000 ft)
Example: 31.1 cm (12-1/4-inch) hole drilled to 122 m (400 ft)
20.0 cm (7-7/8-inch) hole drilled to 1830 m (6000 ft)
31
-------
3
Formation solids removed from 31.1-cm hole (30% washout): 15.9 m
(100 bbl)
3
Formation solids removed from 20.0-cm hole (30% washout): 95.4 m
(600 bbl)
Total liquid mud and surface water waste: 366 m
(2300 bbl)
Total 477 m3
(3000 bbl)
Intermediate- 3050 to 4570 m (10,000 to 15,000 ft)
Example: 31.1-cm (12-1/4-inch) hole drilled to 914 m (3,000 ft)
21.6-cm (8-1/2-inch) hole drilled to 3660 m (12,000 ft)
Formation solids removed from 31.1-cm hole (30% washout): 127 m
(800 bbl)
Formation solids removed from 21.6-cm hole (20% washout): 143 m
(900 bbl)
Total liquid mud and surface water waste 3180 m
(20,000 bbl)
Total 3450 m3
(21,700 bbl)
Deep - more than 4570 m (15,000 ft)
Example: 44.5-cm (17-1/2-inch) hole drilled to 1220 m (4,000 ft)
31.1-cm (12-1/4-inch) hole drilled to 3660 m (12,000 ft)
21.6-cm (8-1/2-inch) hole drilled to 4880 m (16,000 ft)
3
Formation solids removed from 44.5-cm hole (15% washout): 636 m
(4000 bbl)
Formation solids removed from 31.1-cm hole (10% washout): 238 m
(1500 bbl)
Formation solids removed from 21.6-cm hole (20% washout): 63.6 m
(400 bbl)
Total liquid mud and surface water waste 4770 m
(30,000 bbl)
Total 5708 m3
(35,900 bbl)
32
-------
DISPOSAL OF SOLID, LIQUID, AND GASEOUS WASTES PRODUCED IN DRILLING
On land, most drilling activities utilized an earthen reserve pit (or
sump) to store drilling mud and cuttings during operations and for final
disposal. The pit is customarily deeper near the rig to allow for settling of
heavy mud solids. The reserve pit is sized according to the planned volume
of mud and cuttings anticipated, as well as rainfall expected. Walls of the
pit are usually high enough that 1 to 1.5 m (3 to 5 ft) of top soil can be
backfilled over the mud and cuttings for disposal. In certain environmentally
sensitive areas, government regulations require use of an impervious liner in
the reserve pit. Waste mud and cuttings are usually hauled off the location
to a disposal site, but sometimes they are covered over with the pit liner in
place.
Water-based muds are customarily dewatered in the reserve pit.and back-
filled for disposal. Dewatering is often done by evaporation in dry climates.
In other areas, flocculants may be mixed into the pit mud to help settle the
solids. The clarified water is then pumped off.
In recent years, more attention has been given to landfarming techniques
for disposal of water-based muds. The contents of the reserve pit are spread
over the drilling location and incorporated into the soil using tilling equip-
ment. Prior to such disposal, consideration should be given to the type of
mud, the type of soil, and the type of plants to be grown. All of these are
factors in whether the mud would be harmful or would enhance plant growth.
Brine-based muds usually are stored and disposed of in lined pits if the
salinity is above 10% by weight. For lesser concentrations, the mud may be
stored until diluted enough for disposal by other means.
Oil-based muds are customarily kept in steel mud tanks and are not dis-
carded. If cuttings have been removed effectively by solids removal equip-
ment, the oil-based mud is suitable for use for future drilling with little
modification because shale solids do not hydrate and disperse in the oil.
The oil-based mud usually is simply too valuable to be discarded. Cuttings
coated with oil mud are discarded to an earthen pit sealed with bentonite or
lined with plastic sheets to prevent seepage.
33
-------
SECTION 6
COMPLETION AND WORKOVER FLUIDS
Often the fluid used to drill a well is also used for completion opera-
tions (such as perforating, testing, etc.)- The same mud may be left in the
well on the outside of the casing and in the casing-tubing annulus. Special
completion fluids are used, however, particularly when the drilling mud sol-
ids would create problems of productivity damage, settling or solidification
in the annulus, or corrosion.
Workover operations are often conducted with the same type of fluid left
in the annulus of the well upon completion. This may be simply a drilling
mud or it may be a low-solids system.
COMPOSITION
Sol ids-Free Systems
"Solids-free" systems are designed to avoid plugging of perforations by
particles of weighting material and to avoid problems of settling when solids-
laden mud is left in a well after completion.
Salts are used for two purposes in many completion fluids. One would be
for clay inhibition, as in drilling fluids. The second would be to obtain the
desired fluid density without use of solid weighting material. NaCl and KC1
are often used for inhibition as in drilling fluids. For density, NaCl is
used for fluids up to about 1.2 kg/liter (10 Ib/gallon). Densities up to
about 1.38 kg/liter (11.5 Ib/gallon) are obtained with CaCl2 alone or in com-
bination with NaCl. CaBr2 and ZnBr2 can be used in combination to obtain
densities in the range of 2.16 kg/liter (18 Ib/gallon).
Organic polymers are used to give viscosity for lifting capacity and to
aid in filtration control in the "solids-free" system. Hydroxyethyl cellu-
lose and xanthum gum are two of the most commonly used. These materials are
used at concentrations of 2.9 to 14.3 kg/m3 (1 to 5 Ib/bbl).
Calcium carbonate, sized to act as an effective agent on permeable sands,
is used in these "solids-free" systems to allow a filter cake to start to
form. A concentration of 28.6 kg/m3 (10 Ib/bbl) would be typical for this
function. If the well is subsequently acidized, the calcium carbonate should
dissolve enough to cause the filter cake to disintegrate.
Corrosion inhibitors, amine derivatives, are used in the salt systems at
34
-------
concentrations of 4.3 to 14.3 kg/m (1.5 to 5 Ib/bbl). At these concentra-
tions the inhibitor also serves as a microbiostat to prevent degradation of
the polymer components. Otherwise, paraformaldehyde might be used as a bio-
cide.
A buffer, usually magnesium oxide, serves to stabilize the pH of the sys-
tem and keep the polymers in an effective form. Concentrations of 0.3 to 1.4
kg/m3 (0.1 to 0.5 Ib/bbl) are typical.
Defoamers of various types (alky! alcohols, sulfonated vegetable oils,
etc.) are used to combat air and gas entrapment. Typical concentrations are
in the 0.3 kg/m3 (0.1 Ib/bbl) range.
Solids-Laden Systems
These completion and workover fluids are water-based, brine-based, or
oil-based systems equivalent to those used for drilling. The principal dif-
ference would be that a system might be freshly prepared to avoid the drilled
formation solids that would have accumulated as extremely fine particles dur-
ing the drilling operation. For densities up to about 1.5 kg/liter (12.5 lb/
gallon), calcium carbonate often is used as an acid-soluble weighting mate-
rial. There has been some minor usage of iron carbonate (siderite) for den-
sities up to 1.68 kg/liter (14 Ib/gallon).
DISPOSAL OF COMPLETION AND WORKOVER FLUIDS
In general, completion and workover fluids are disposed of in the same
manner as the drilling fluids. One difference is that a significant amount
of the completion fluid is usually left in the well, in the annulus between
the tubing and the casing. The volume of completion fluid, therefore, is
usually quite small relative to the volume of drilling mud in the reserve
pit. Often a brine-based completion fluid is used in a well drilled with a
water-based mud. When discarded to the reserve pit, the salinity of the com-
pletion fluid is drastically reduced because of the large dilution.
A disposal method not previously mentioned is that of pumping the waste
down the well annulus and into a formation having sufficient porosity and
permeability. This procedure is not always feasible and the practice is
rather limited. Although drilling fluids could also be disposed of in this
manner, it is more common with completion fluids because volumes are smaller
and salinities are often higher.
ENVIRONMENTAL EFFECTS OF DRILLING, COMPLETION, AND WORKOVER WASTES
At a conference conducted by the EPA in Houston in 1975, there was much
concern expressed by various groups about possible harmful effects on the en-
vironment from disposal of wastes from oil and gas drilling operations. Half
a century of intensive drilling activity had resulted in no major impact on
the environment, other than a few isolated examples of mishandling of brine.
Nonetheless, relatively few studies had been made under controlled conditions.
The 1975 conference stimulated numerous research programs, many of which
35
-------
were reported on at a joint government/industry seminar in 1980. These stud-
ies indicated that the commonly used water-based muds and mud components are
relatively nontoxic and not harmful to the environment when properly handled.
Studies are continuing on long-term, sublethal effects that could be of im-
portance in areas of prolonged concentrated drilling activity. For example,
bioavailability and bioaccumulation of trace metals in drilling muds are sub-
jects of on-going research. Such work may result in guidelines that could
provide an added assurance that the environment is protected.
36
-------
SECTION 7
OIL WELL SERVICING AND WORKOVER
With the passage of time, all oil or gas wells will develop production
problems. These problems can be mechanical in nature such as the plugging of
a tube with sand or the failure of a subsurface pump, or may be due to the
depletion of the oil/gas reservoir. Perhaps the natural reservoir pressure
has fallen to the point where the oil must be pumped out. In general, work-
over is a term applied to efforts to increase production from old wells.
SERVICE AND WORKOVER - RIG EQUIPMENT
Upon completion of well drilling activities the drilling rig is disas-
sembled and moved to the next drill site. When well servicing or workover is
required, special rigs must be employed.
Truck-Mounted Units
Light- to medium-duty servicing and workover can be handled with truck-
mounted rigs. They are limited by the amount of structure that can be con-
veniently carried by truck and easily deployed above the wellhead and the
amount of power available.
Two basic types of structures or masts are utilized, the double-pole
masts and the structural mast. Pole masts are constructed of tubular members
and are extended to their full length by wire-rope arrangements. Structural
masts are constructed of angular steel elements and can carry heavier loads
than pole masts. The telescoping structural mast is elevated by hydraulic
devices and the upper section raised to full height by wire-line setups. The
two sections are then mechanically locked together. Both types of masts re-
quire the use of guy lines for support.
Carrier Units
Heavy-duty servicing/workover often required by deeper wells necessitated
the use of stronger, heavier, taller masts and wellhead clearance for the in-
stallation of blowout preventers. To meet these requirements, self-propelled
carrier units were designed to fit the needed engine-hoist-mast combination.
These units have capacities of 114,000 kg (250,000 Ib) or more and can handle
pipe in 9.14-m (30-ft), 18.3-m (60-ft), and even 27.4-m (90-ft) lengths.
Many of the rigs can develop over 0.45 MW (600 HP).
37
-------
Auxiliary Equipment
Well servicing/workover equipment includes (a) manually operated tubing
or drill-pipe slips for medium-depth wells and air-operated equipment for
heavier loads encountered in deeper wells, (b) hydraulically operated tongs,
(c) a rotating head with a sealing arrangement for high-pressure fluid circu-
lation and a small kelly to allow vertical movement of a pipe string during
turning, and (d) mud-pumping apparatus.
REMEDIAL WELL WORK
The most common types of repairs to wells are swabbing and the repair of
sucker-rod pumps, sucker-rods, production tubing, and packers. Normal wear
of moving parts in downhole pumps, sucker rods and gas life equipment, age
and corrosion, scale and paraffin deposits will make repairs necessary.
Swabbing
If the formation pressure is insufficient to overcome the hydrostatic
pressure of the fluid in the tubing, a swab-cup arrangement is lowered into
the well in a wireline from a truck-mounted hoist. The swab-cup raises the
fluid to the surface. The removal of the fluid from tubing lowers the hydro-
static head on the formation and induces flow from the formation.
Pump Repair
When formation pressure is too low to bring oil to the surface, pumps
must be used. There are two basic types of subsurface pumps, the tubing pump
and the rod pump. The tubing pump is attached to the bottom of the tubing
string. It is more difficult to service since the tubing must be extracted
from the well to get at it. The tubing pump can handle larger volumes of
fluid. The rod pump is more popular, since it is run in on the sucker rods
and can be removed with them for repair.
Subsurface pumps are simple, rugged, and very reliable. Failure or im-
pairment is often caused by sucker rod failure from corrosion, wear, and
stress fatigue.
Production Tubing
A tubing string must be leak-free and capable of withstanding an internal
pressure up to several tens of MPa (several thousand psi) and considerable ex-
ternal pressure. Leaks, when they occur, are usually caused by faulty or
loose couplings, a hole or split caused by rod abrasion or working of the tub-
ing as the well is pumped. Pressure testing of the tubing to check for leaks
is easily done by truck-mounted oil-well servicing units with the tubing ver-
tically mounted as it is made up in the string and run back into the hole.
Packers
Packers are used to seal off the space between the tubing and the oil
string casing (Figure 7) and isolate the producing formation and its pressures
38
-------
from the casing higher up in the well. Repairing packers having worn sealing
elements can be done by retrieving the packer. If the packer is nonretrievable
(a type frequently used) it can be removed by drilling it out.
Blowout Prevention
While most wells requiring remedial work have a low formation pressure,
service crews must always be alert to the hazard of a blowout. Gas sands from
shallower depths that have been cased off may cause problems if casing failure
occurs. Depleted sands at shallower depths have been used for gas storage and
the pressure of the injected gas has sometimes built up to levels that would
require a heavy fluid to contain the pressure.
Minimum requirements should include a rod blowout preventer that can be
closed on the sucker rod in an emergency. Connections at the well head
should be available for the pumping of mud or water into the well to overcome
formation pressures. If pressure problems are expected, a blowout preventer
should be installed before tubing is pulled.
WELL CLEANOUT AND WORKOVER
Completion, cleanout, or workover jobs comprise about half of the work
for production rigs in the U.S. Because workover jobs can require the rota-
tion of a drill pipe string and a means for circulating fluid, workover rigs
must be capable of hoisting heavier loads than well-servicing rigs. As de-
scribed earlier, these rigs will take on the appearance and function of regu-
lar drilling rigs.
Completion and Workover Fluids
The completion and workover fluids are normally either specially prepared
mud or salt water. These mixtures and the various additives used to obtain
desired properties are discussed in another section of this report.
Sand Cleanout
Sand cleanout is done with a macaroni rig which is essentially a 2.5-cm
(1-inch) diameter pipe string fitted to a high-pressure pump for salt water
circulation. If a packer has been fitted in the well or the tubing is ob-
structed, the tubing is pulled and cleared while the packer is either unseated
or drilled out. The cleared tubing can then be used to circulate the fluid
for flushing away the sand.
If sand has entered the annul us between the tubing and casing above a
packer (through a hole in the casing or through open performations in an upper
zone of a multiple completion well) in sufficient amount to prevent pulling
the packer, the free portion of the tubing is cut off and pulled. A washover
assembly is then run into the hole over the remaining tubing stub below the
cutoff projecting upward from the packer. Circulation of fluid is then used
for sand removal. Since the tubing is cut and removed, blowout preventers
must be used. Rigs employing a washover assembly are larger and heavier since
not only must the stuck tubing be pulled, but the much heavier washover unit
39
-------
must be run in and retrieved. Then, too, since the washover may involve turn-
ing the string, the rig should be equipped with a rotary.
Casing Repair
Well casing is subjected to corrosion, abrasion, high pressures and other
forces that can sometimes cause holes and splits to develop. The presence of
casing holes is usually indicated by shale or sand in the well when the tubing
is pulled. A casing hole can be located by conducting a pressure test of the
annular volume above a seal formed by a retrievable packer. The packer is
then methodically lowered down the well and sealed at various depth intervals
until the pressure test reveals a leak. When the hole is located, the casing
can be repaired in several ways.
1. Squeeze cementing: A drillable plug or a packer is placed below the
casing hole. Cement is then applied under sufficient hydraulic pres-
sure to force it into the hole. After hardening, the cement drill -
able plug or packer is drilled out, leaving the cement plug in the
hole of the casing wall.
2. Stressed steel liner patch: A corrugated steel liner tube is coated
on the outer diameter surface with a layer of woven fiberglass cem-
ented in place with epoxy resin. The corrugated patch is coated
with additional epoxy and lowered to the desired location in the
well, expanded with a special tool, and epoxied in place.
3. Upper string replacement: The upper portion of the casing string
is removed down to the leak and rerun with an overshot tool.
4. Full liner: If steps 1, 2, and 3 are not possible, a complete string
of smaller diameter pipe liner can be run in and cemented.
5. Casing roller: If the casing string has crimped or collapsed at one
point, a casing roller, or swaging tool, can be used to open up the
casing.
Sidetrack Drilling
Collapsed casing, nonretrievable junk in the well, or a desire to obtain
a better location to drain a reservoir will call for sidetrack, or direction-
al drilling. This is done by plugging back the casing at the desired depth,
removing a section of casing above the plug, running in a whipstock (a long
steel casing that uses an inclined plane to deflect the drilling tool), and
drilling the new hole off to one side of the old well bottom.
Drilling Deeper
Deepening a well is usually done to facilitate the cleaning out of the
existing producing zone rather than to find a deeper reservoir. After plug-
ging existing perforations and pressure testing, the casing shoe is drilled
out and the hole deepened. The well is logged, a liner or casing is run in,
and the well is completed in much the same manner as a new well.
40
-------
WELL STIMULATION
Oil-bearing formations are often poor producers because of low porosity
and/or permeability and lack of fracturing. Well stimulation involves the
opening up of low porosity, or dense reservoir rocks to permit oil to flow
more rapidly to the collection zone at the well. Three methods of well stim-
ulation have been developed over the years: explosives, acid stimulation, and
hydraulic fracturing.
Explosives
The oldest of the stimulation techniques is explosive fracturing. After
being considered obsolete for many years, there is a renewed interest in this
technique. Experience has shown that explosive stimulation is more effective
on certain types of tight formations than are acid or hydraulic techniques and
that older wells stimulated with explosives or "shot" produced much longer than
acidized or hydraulically fractured wells (A Primer of Oil Well Servicing and
Workover, p. 58, 3rd Ed., Petroleum Extension Service, University of Texas,
Austin, Texas, 1979).
Two basic methods of explosive stimulation are used. The detonation can
be concentrated in the well or the explosive can be injected into an existing
fracture system surrounding the well hole for dispersed detonation.
Acid Stimulation
Acid treatment serves to dissolve rock and thus enlarge channels and pro-
duce new networks of paths to induce greater flow of oil to the well. The
acids used must result in soluble reaction products, should be relatively safe
to handle, and economical. The rocks most often attacked with acids are lime-
stone (CaC03) and dolomite (a mixture of CaC03 and MgC03).
Additives--
The effectiveness of oilfield acids can be improved by the use of vari-
ous additives. Additives are available that will retard the rate of attack of
the acid to prevent oil-acid emulsions and to permit easier flow of the acid
into the formation interstices. Sequestering agents are added to the acid to
control the reprecipitation of iron deposits stemming from iron oxide, sulfide
and carbonate scale removed from oilwell tubing and casing by the acid. Fin-
ally, suspending agents are used in oilfield acids to keep fine clay and silt
particles,that are often picked up by the acid during use, in suspension.
Acids--
Various acid formulations are available. Selecting the correct one in-
volves detailed knowledge of the producing formation and its physical condi-
tion around the well. The acids used include hydrochloric acid, acetic acid,
formic acid, sulfamic acid, and hydrofluoric acid.
Acetic acid is used to acidize limestone formations at high temperatures
(greater than 120°C [250°F]). It is easily inhibited, will not cause either
hydrogen embrittlement or stress corrosion in heat-treated steels, and will
not attack chrome plating or aluminum. Formic acid can be easily inhibited
41
-------
and also can be used to treat high-temperature limestone formations, although
not as effectively as acetic acid. Sulfamic acid is stronger than acetic or
formic acid, but is not suitable for high-temperature use, and when mixed with
water, forms very corrosive solutions that must be handled very carefully.
Hydrochloric acid is generally considered to be the most efficient and econom-
ical means of treating limestone or dolomite formations. Hydrofluoric acid
reacts with quartz particles (the main constituent of sandstone), silicates
(glass and concrete), cast iron, and many organic materials. Hydrofluoric
acid is poisonous and is handled with extreme caution.
Generally, the tendency of an acid to form sludges or emulsions increases
with the concentration of the acid solution. Usually acids used in well treat-
ment will range in strength from 3% to 28% by weight in water.
Placement—
Acid injection can be performed at rates sufficiently high to fracture
the formation (the most common type of acid treatment) or the injection can
be achieved at pressures low enough to avoid fracturing -- the so-called
interstitial or matrix acidizing. The low-pressure technique should be con-
sidered when formation damage is present or whenever a water zone or gas cap
is near and fracturing could result in excessive water or gas production with
the oil.
In addition to producing new channels in a formation, acidizing can re-
move water blocks, emulsion blocks, and deposited solids from channels to in-
crease or restore production.
Hydraulic Fracturing
Hydraulic fracturing has gained wide acceptance in the oil industry for
the treatment of sandstone reservoirs to improve the flow of oil/gas.
New wells may be fractured on completion to improve production and refrac-
tured when it is required to restore productivity.
To keep the fracture open or spread, the fracturing fluids will contain
propping agents which are suspended particles that will be carried into the
newly formed fractures and deposited therein. Sand, beads of aluminum, glass,
plastics, and nutshells have all been used as propping agents. Fluids used
for fracturing are often complex mixtures. A good fluid should have low-loss
characteristics (nonpenetrating), the ability to carry the proppant into frac-
tures, and low pumping friction loss. The fluids can be oil-based, water-
based, and acid-based. The selection of the best fluid base depends on the
chemical and physical nature of the formation and of the reservoir fluid. As
stated in an earlier section, acid-based fluids are generally used with car-
bonate rocks, i.e., limestone and dolomites.
42
-------
SECTION 8
SURVEY OF NEW OIL AND GAS FIELDS, 1975-1979
According to item 1. in the Introduction to this report, information was
to be gathered for the "lower" or "conus" 48 states, onshore fields only, lim-
iting data to fields that went into primary production after December 1974.
Figure 9 was prepared to show the desired VOC Survey Data. Activity included
telephone contacts with the following organizations:
1. American Association of Petroleum Geologists (AAPG), Tulsa, OK, and
San Francisco, CA: They publish annual drilling statistics every
August for the preceding calendar year, and, in more detail, prepare
tapes that are sold through API. They do not appear to issue any
production information. The August 1979 Bulletin with 1978 data
was obtained.
2. American Petroleum Institute (API), Washington, DC: Furnish tapes
of master wells, plus tapes of AAPG on exploratory wells. Tapes
are incorporated in the PDS system (see 4. below).
3. Department of Energy (DOE) - Annual Survey of Oil and Gas Reserves
(RAPS - Reserves and Production System), Norman, OK: Producers
furnish annual data which are verified and then put on tape by the
University of Oklahoma (subcontractor) and the tape is shipped to
Washington, DC, for processing and incorporation into RAPS by DOE.
4. Petroleum Data System (PDS), Norman, OK: USGS-sponsored storage and
retrieval system located at the University of Oklahoma. Includes
most of State, API, and AAPG generated information and much of what
is desired for this project.
5. Petroleum Information Corporation (PI), Denver, CO, and Houston, TX:
Gathers nationwide data from states (except New England) on a weekly
basis and maintains digital and hard copy files. Issues annual in-
formation sooner than others. Appears to have most information
desired.
6. R&D Representatives of EPA Regions: These were requested to act as
points of contact for the states in each Region. Cooperation was
good throughout.
7. Interstate Oil Compact Commission, Oklahoma City, OK: An up-to-date
directory of state oil and gas agencies was obtained.
43
-------
1. Field Name and Operator(s) in Field
2. Formation/Reservoir
3. County
4. Primary Production Start Date (January 1975 or later)
5. Type of Field (oil, oil/gas, gas) and API Gravity (where applicable)
6. Well depth, feet
7. Producing Zone, feet (or least and greatest depth)
8. Number of wells as of recent date (state date)
a. Producing
b. Exploratory
c. Abandoned
9. Annual Production for 1975, 1976, 1977, 1978, and 1979 of:
a. Crude oil (bbl)
b. Condensate (bbl)
c. Nonassociated gas (million cu.ft.)
d. Associated gas (million cu.ft.)
e. Water (bbl)
Figure 9. List of drilling and production data to be
acquired for each new field.
44
-------
8. Oil and gas agencies or divisions of geology of all conus states.
These agencies regulate oil and gas drilling and production and
maintain records of various types. They issue annual (and sometimes
monthly) reports, and these were requested for the years 1975-1979.
Further action was taken as follows:
PDS: A computer expert from Rockwell EMSC attended a PDS seminar in
Tulsa on 11 December 1979. The seminar provided information on the files
available at PDS and on methods of accessing to their data base. The PDS
Users Guide was obtained. Table 1 shows a status report on their holdings,
from which it is seen that information in the data base is incomplete. This
means that more current information must be sought elsewhere. PDS is the
most economical computer data bank, though, and a terminal hookup to their
bank was made.
PI: A letter was written outlining our data requirements and a visit
was made to Pi's Houston facility. Pi's cost estimate to furnish the desired
data was, however, excessive compared with contract funding, so this route
had to be abandoned.
Pursuant to the inquiries described above, it was decided to access the
PDS data bank, obtain what information was available (see Table 1), and fill
in the gaps from state files. Throughout, all the information listed on Fig-
ure 9 was sought.
The PDS compilation more or less contained the data listed in Figure 9,
but "exploratory wells" were not listed. Instead, a listing of wells "cap-
able of producing" was given. The states varied greatly in their publications,
While oil and gas well drilling and production statistics are public records
and open to inspection at the state capitals or other locations within the
state, the printed reports disseminated were often incomplete or not in a
form suitable for this study (e.g., production by county, not by field).
Some of the largest oil/gas producing states (e.g., Oklahoma and New Mexico)
issued no reports, but merely furnished information to API, PDS, or PI.
Also, in many cases reporting was late by several years (see Table 1), repre-
senting the combination of delays ascribable to the state and the PDS.
Figure 10 is a map of the major oil/gas regions in the conus states.
Figure 11 is a map of the U.S. EPA Regions. Statewide summations of new fields
and wells were ordered in Table 2 by EPA Regions.
Twenty-one of the 48 states have no new fields, e.g., the New England
states have no oil or gas exploration at all. In 18 of the states with new
fields, state data were scanned, identified, edited and punched in as addi-
tions to the PDS computer compilation and appear in the printout of Appendix
A. The limited scope of this project did not permit completion of such tasks
for the nine remaining states with new fields; the PDS compilation and par-
tially processed state data are preserved (indicated as "raw" data on Table 2).
Table 2 shows that PDS and state data were available only for certain years.
45
-------
TABLE 1. STATUS REPORT OF PETROLEUM DATA SYSTEM,
TEXS AND OILY DATA BASES, SEPTEMBER 14, 1979
State
Number of Records
***
Production Years
in Data Base
Al abama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois*
Indiana*
Kansas*
Kentucky
Louisiana*
Louisiana DCS*
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
West Virginia
Wyoming
82
63
15
838
1,263
1,085
15
2,990
1,114
9,389
2,725
6,313
261
3
1,030
1,255
8
556
672
1
1,433
180
180
1,314
8,071
582
12
146
40,920
304
297
1,351
1968-1977
1972-1978
1968-1977
1968-1977**
1968-1976
1968-1974**
1968-1978
1968-1977
1968-1977
1968-1975**
1968-1975
1968-1974**
1970-1976
1973
1968-1976
1968-1976
1968-1976
1968-1977
1968-1977
1968-1975
1968-1977**
****_! 972
1968-1974**
****
1 968-1 974**A
1968-1976
1968-1975
1970-1977
1968-1977
1968-1976**
1 968-1 973B
1968-1974
* Production is reported on "Field Record"
** To be added from Dwight's Energydata, Inc.
*** Each record contains oil production data for a different field.
A - Crude oil production - 1975
B - Cumulative production only
Texas - All annual production - 1977; cumulative crude oil production - 1977
46
-------
KEY:
1. ILLINOIS BASIN
2. APPALACHIA
3. MID-CONTINENT
4. PERMIAN BASIN
5. GULF COAST
6. EAST TEXAS
7. ROCKY MOUNTAIN
8. CALIFORNIA
Figure 10. Major oil regions in continental U.S.
-------
00
SAN FRANCISCO
Figure 11. EPA Regional Offices - standard federal regions.
-------
TABLE 2. REGIONAL AND STATEWIDE OVERVIEW OF NEW FIELD SURVEY AND DATA
EPA
Region
I
II
III
IV
V
VI
VII
Conus
States
CT
MA
ME
NH
RI
VT
NJ
NY
DE
MD
PA
VA
WV
AL
FL
GA
KY
MS
NC
SC
TN
IL
IN
MI
MN
OH
WI
AR
LA
NM
OK
TX
IA
KS
MO
NB
Data
PDS
76
-
-
75-77
-
75-76
75-76
75-77
75-77
75-77
75-76
-
75-77
-
75-78
75
75-77
75
75-78
Years: New Field Data:
State Printout Raw Only*
/
75-78 /
75-79 /
77-79 /
75-79 /
/
75-78 /
75-78 /
75-78 /
75-78 /
75-78 /
78-79
75-78 /
75-76 /
/
/
75-6,78 /
75-78 /
75-79 /
No New
Fields
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*Not worked up for printout.
(continued)
-------
TABLE 2 (Continued)
EPA
Region
VIII
IX
X
Conus
States
CO
MT
ND
SD
UT
WY
AZ
CA
NV
ID
OR
WA
Data
PDS
75-76
75-77
_
75
_
75
_
75-76
-
_
Years: New Field Data:
State Printout Raw Only
75-76 /
75-78 /
75-79 /
75-79 /
74-78 /
75-78 /
75-79
77-78 /
75-79 /
75-79
75-79 /
No New
Fields
X
X
X
TOTAL CONUS STATES:
18
21
In terms of EPA Regions, there are no new fields in Regions I or II,
whereas every state in Regions VI and VIII does have new fields. Regions IV,
V, VII, IX, and X have some states with new fields and some without. It
should be borne in mind that the definition of "field" varies with the state.
For example, in Texas the term is frequently used for a single well, whereas
in Ohio it is applied to formations that may be over 161 km (100 miles) in ex-
tent. Thus, Ohio, which has had recent drilling activity, is technically
listed as not having new fields.
Statewide totals and averages are shown in Table 3 for the 18 states on
the printout. In addition to total new fields and wells in new fields, aver-
age well depths and average pay (or producing) zone extent are listed where
such data were given. The average pay zones are generally 15.2 m (50 ft) or
less in extent. The average well depths vary from hundreds of meters (one or
two thousand feet) to over 3660 m (12,000 ft). In the case of oil fields,
average API gravity varies from 18 to 50.
Table 4 is a compilation of statewide new field production totals, in
each of the 5 years of interest (1975 through 1979), separated into five cate-
gories (crude oil, associated gas, nonassociated gas, condensate, and water).
The information headings presented on a statewide basis (18 states) in
Tables 3 and 4 appear on a fieldwide basis in the printout of Appendix A,
alphabetically by state, within each state alphabetically by county, and with-
in each county alphabetically by new field. Because of the mass of the print-
out (including Texas with over 4200 new fields), it has been placed between
50
-------
TABLE 3. STATEWIDE NEW FIELD DATA: FIELDS, WELLS, DEPTHS, GRAVITY
No. Wells in New Fields
New Fields
State
Alabama
Arkansas
Colorado
Florida
Illinois
Indiana
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nevada
Oregon
Pennsylvania
So. Dakota
Texas
W. Virginia
Wyoming
Total
23
62
107
4
96
1
18
35
141
91
99
1
1
26
2
4208
21
6
Oil
11
50
58
4
NG
1
>n
8
>79
>62
55
1
0
NG
2
>1408
0
NG
Gas
21
18
57
1
NG
0
>3
29
>28
>15
45
0
1
NG
0
>1922
21
NG
Produc-
ing CAPDG* Shut In
102
2174
138
3
>151
0
>32
55
169
123
419
14
5
NG
2
6392
21
NG
0
0
0
0
(total wells)
2
(total wells)
4
22
12
0
0
0
NG
0
4303
0
NG
0
0
11
3
0
8
1
19
104
0
0
NG
0
0
0
NG
Avg
m
3,014
1,853
1,734
3,934
1,352
344.4
569.7
3,324
1,623
3,667
2,720
1,246
833
1,165
2,728
2,276
1,095
2,880
Depth , Avg
(ft) Zone,
(9,889)
(6,078)
(5,689)
(12,906)
(4,435)
(1,130)
(1,869)
(10,906)
(5,325)
(12,030)
(8,924)
(4,087)
(2,700)
(3,823)
(8,950)
(7,468)
(3,591)
(9,450)
5.2
6.7
9.1
4.9
6.7
11.
7.9
Pay
m (ft)
(17)
(22)
(30)
(16)
NG
NG
NG
(22)
NG
3 (37)
(26)
NG
183 (600)
(sands)
NG
3.05 (10)
4.6
18.
NG
(15)
6 (61)
Avg API
Gravity
40
36
38
31
18
NG
NG
47
50
41
40
27
NA
NG
33
42
NA
24
* Capable of producing
NG = not given NA = not applicable
-------
TABLE 4. STATEWIDE NEW FIELD PRODUCTION STATISTICS
Key: TCRU75 TNGS75 TAGS75 TCON75 TWTR75
TCRU76 TNGS76 TAGS76 TCON76 TWTR76
TCRU77 TNGS77 TAGS77 TCON77 TWTR77
TCRU78 TNGS78 TAGS78 TCON78 TWTR78
TCRU79 TNGS79 TAGS79 TCON79 TWTR79
TCRU: Annual crude oil production, barrels (1 bbl = 0.159 m )
TNGS: Annual nonassociated gas production, million cu.ft. (million cu.ft. * 28,317 m )
TAGS: Annual associated gas production, million cu.ft. (million cu.ft. « 28,317 m )
ICON: Annual condensate production, barrels (1 bbl * 0.159 m )
TWTR: Annual water
AL
AR
CO
FL
IL
IN
150
406
542
965
949
80
573
1,212
1,378
NR
155
406
2
NR
NR
NR
NR
130
93
121
6
47
2,938
NR
NR
1
NR
4
NR
NR
,524
,350
,583
,433
,586
,743
,727
,083
,072
,242
,260
,219
,286
,461
,948
,300
,300
,400
,365
,868
production.
81
28
3,579
12,213
12,066
NR
NR
548
888
NR
806
4,355
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
barrels
,499
,067
,173
,688
,875
,621
,484
,745
,247
(1 bbl -
152
333
389
774
666
97
522
1,247
1,669
NR
128
424
7
NR
NR
NR
6
5
7
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
0.159 m3)
,647
,182
,277
,968
,085
,249
,905
,681
,665
,133
,902
,679
574
,407
,718
,918
NR
NR
86,070
372
268
NR
NR
NR
NR
NR
1,844
24,953
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
259
345
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
5
79
9
57
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
,323
,005
,435
,472
,821
,756
NR = no data reported. (continued)
52
-------
TABLE 4 (continued)
KY
LA
MI
MS
MT
NV
OR
PA
95
NR
NR
NR
NR
141
1,168
NR
NR
NR
473
2,822
NR
NR
NR
534
1,451
NR
NR
NR
88
687
1,553
2,036
NR
NR
19
548
1,084
1,160
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
,415
,414
,706
,347
,236
,993
,989
,462
,213
,616
,765
,055
,226
,523
,804
NR
NR
NR
NR
NR
7,729,441
14,703,879
NR
NR
NR
652,113
7,613,651
NR
NR
NR
1,403,855
4,764,596
NR
NR
NR
741,753
2,481,750
7,500,326
8,565,412
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
39,043
NR
NR
NR
NR
NR
NR
NR
NR
135
516
NR
NR
NR
236
2,375
NR
NR
NR
64
850
NR
NR
NR
653
738
2,929
5,722
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
15
NR
NR
NR
NR
NR
,505
,375
,541
,440
,831
,445
,204
,373
,549
,375
,160
NR
NR
NR
NR
NR
190,841
377,061
NR
NR
NR
56,814
325,206
NR
NR
NR
21,954
126,453
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
59
467
NR
NR
NR
835
3,605
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
10
119
107
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
,860
,930
,174
,531
,952
,442
,208
(continued)
53
-------
TABLE 4 (Continued)
SO
TX
30,216
NR
NR
NR
NR
4,575,848
16,078,350
24,482,236
NR
NR
NR
NR
NR
NR
NR
168,752,960
376,611,104
646,636,032
NR
NR
1,232
NR
NR
NR
NR
475,899
6,864,836
36,059,528
NR
NR
NR
NR
NR
NR
NR
1,015,566
2,958,835
6,148,281
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
No production statistics were available for West Virginia or Wyoming.
separate covers. The time and effort allocated to this part of the program
did not permit close scrutiny and correction of the many inaccuracies found
in the printout as it came from PDS. For the present purpose, absolute veri-
fication of all items is not warranted. However, under the constraints men-
tioned above, the data do show those states with drilling activity and
can be used for qualitative predictions.
54
-------
SECTION 9
VOC EMISSIONS FROM OIL/GAS DRILLING OPERATIONS
A review of the literature on oil and gas well drilling practice published
by the API (e.g., Baker, Ron, A Primer of Oil-Hell Drilling, 4th Ed., Petrol-
eum Extension Service, University of Texas, Austin, TX, 1979) and information
supplied by drilling consultants indicates that there are three main sources
of VOC associated with the drilling operation. These are:
1. Stored fuel for the drilling rig prime movers (usually diesel fuel)
2. Exhaust products from the prime movers (usually diesel engines)
3. Formation fluids, high-pressure, low-molecular-weight hydrocarbons
and H^S from unsealed "troublesome" formations
STORED FUEL AND ENGINE EMISSIONS
Estimates of VOC emissions from storage fuel tanks and prime movers asso-
ciated with drilling operations have been specifically excluded from the scope
of this effort. These VOC sources will be considered in studies conducted
elsewhere.
FORMATION GASES, HYDROCARBONS
Many wells will have some gas in the drilling mud at times. Some wells,
near completion, may send larger amounts of gas into the mud before drilling
is completed and must be watched closely. High-pressure formation gases enter-
ing the bore hole during the drilling procedure will be entrained and, to a
much lesser extent, dissolved in the drilling mud. If the entrainment rate is
not severe enough to cause a kick (a rapid reduction in hydrostatic head that
permits more high-pressure formation gases to enter the drilling mud, resulting
in a further loss of hydrostatic pressure and a potential runaway, or blowout,
situation), the entrained gases will be removed in the mud maintenance system
by a degasser. Some gas bubbles will be removed from the drilling mud during
processing by the shale shaker and during storage in the mud pits or tanks
while awaiting recycling into the borehole. Ordinarily, however, drilling muds
will be too viscous for gas bubbles to rise to the surface and break at an ap-
preciable rate in the mud pits. While some formation gases entrained in the
mud will be emitted to the atmosphere in the mud pits and should be taken into
account, most of the gas will be extracted by the degasser.
If, during the well-drilling process, a kick does occur and it becomes
necessary to activate the blowout preventers to shut off the drilling mud in
55
-------
the well bore, the gas can be bled off of the well annul us through the choke
manifold and then flared to the atmosphere.
In summary, formation gas entering the mud will be removed in the shale
shakers, degassers, the mud pits (reserve pit, settling pit, and suction pit),
and the choke manifold (when necessary). Small quantities of gas will also be
lost from valves, flanges, and other fittings in the mud recirculation system.
The probability of gas intrusion will vary according to the operation be-
ing conducted in the bore hole (i.e., drilling, tripping to change bits, run-
ning casing, cementing, well logging, and completing) and the formations that
have been exposed. When the mud flow is stopped and the drill string is being
hoisted from the hole (tripping), one is more likely to get gas intrusion, the
so-called trip gas.
Unlike the VOC emissions from the on-site fuel storage facilities and
the diesel engine exhaust, the emission of formation gases from the well via
the drilling mud can vary greatly during the well boring process and, as in-
dicated above, depending on the operation being conducted. VOC emission may
be negligible until certain "troublesome" formations are penetrated. Even
then, the amount of formation gas intrusion could depend on the skill of the
drilling crew and the mud handler in plugging such a formation with ingredi-
ents added to the mud. Once such troublesome formations are sealed off with
casing cemented in place, the VOC emission rate will again be small. The
sporadic nature of the VOC emission problem from formation gases would indi-
cate that some average gas entrainment rate in mud be obtained for troublesome
formations specific to a certain oil/gas field or geological area. This rate
could then be multiplied by an average formation exposure time to the mud be-
fore the zone is sealed off with well casing. Finally, this total gas leak-
age must be corrected to eliminate the fraction of the gas that is collected
and burned. Presumably, this burned fraction will include gas removed from
the drilling mud by the degasser and through the choke manifold.
FORMATION GAS, H2S
Intrusion of H2S into the mud is usually handled by chemical means. Iron
sponge, a specially processed hematite that has extremely large surface area,
can be suspended in the mud to react with H£S to form insoluble iron sulfide.
Zinc carbonate has been widely used in drilling muds in areas of high H£S con-
centration. The reaction time of H2S with the zinc carbonate is much faster
than with iron sponge. Virtually all drilling muds are maintained at a high
pH. Reactions of H?S to form an alkaline sulfide are favored at pH above
10.5.
PROSPECTIVE VOC SOURCES
Estimates of VOC emission of hydrocarbon formation gases must include
data on the number of oil and gas wells being drilled and the number of dril-
ling rigs in operation. Current information on drilling activity in the U.S.
has been reviewed and is summarized in the following subsections.
56
-------
Drilling Activity
According to World Oil's 1980 forecast (World Oil, "U.S. Drilling Rec-
ords Are Falling," p. 95, February 15, 1980), the number of oil and gas wells
drilled in 1980 will increase sharply; the prediction was that 56,083* new
wells would be drilled in the U.S. in 1980. This forecast, if verified,
would make 1980 second only to 1956 in terms of holes drilled; it represents
an 11.4% increase over the 50,332 wells drilled in 1979 and a 12.3% increase
over the 49,831 wells drilled in 1978 (World Oil, loc. cit.}. The data on
total U.S. drilling activity since 1974 are given in Table 5, while data
since 1956 are plotted in Figure 12 (World Oil, loc. cit.) along with infor-
mation on how many of these wells were oil, gas, dry, and service wells.
As indicated in Table 5, only 31,121 wells (18,051 new oil and 13,070
new gas) drilled in 1979 were productive. It is these wells we would be con-
cerned with as sources of VOC. Figure 12 shows the prediction of 35,001 pro-
ducing wells for 1980, a 12.5% increase over 1979.
The number of exploratory wells drilled in 1979 was 11,658 (23.2% of the
number of wells drilled in 1979), of which 3,055 were productive (1,236 oil
and 1,819 gas) (World Oil, "More Wildcats Expected," p. 105, February 15,
1980). For 1980, it was predicted that 13,075 exploratory wells would be
drilled (World Oil, loc. cit.). The data are given in Table 6 and are plotted
in Figure 13. The category of "exploratory well" includes new field, new pool,
deeper or shallower pool, outpost, and extension. Information on one of these
categories, i.e., new field wildcats, was available and is presented in Table
7 and Figure 13 (World Oil, loc. cit.).
From the Oil and Gas Journal, actual U.S. well completions from January
through July 1980 number 31,981, of which 13,652 are oil, 8,160 are gas, and
902 are service wells. This can be compared with 26,873 for the similar per-
iod of 1979. Using the ratio of well completions in 1980 and 1979 for this
7-month period (1.19) multiplied by the total well completions in 1979 to es-
timate the total number of well completions in 1980, one obtains 59,900. This
estimate can be compared with the World Oil forecast of 56,083 new wells. It
is quite apparent that drilling activity in the U.S. for 1980 will greatly ex-
ceed predictions made at the close of 1979.
Drilling Rigs
Data on the number of operating drilling rigs as a function of time are
plotted in Figure 14. It can be seen that 1979 saw a decline in drilling
activity; only 2,194 rigs were active. This decrease has been attributed to
confusion over the Natural Gas Policy Act of 1978, a surplus of natural gas on
the market, and a "wait and see" attitude by many operators regarding the gov-
ernment energy policy. However, an increase in natural gas prices and decon-
trol of some categories of crude oil in mid-1979 and the promise of total
crude price decontrol in the near future spurred drilling activity near the
If Alaska, offshore Louisiana, and offshore Texas drilling are eliminated,
the total number of new wells is predicted to be 54,861.
57
-------
TABLE 5. TOTAL U.S. DRILLING
Productive WeT
Year
1974
1975
1976
1977
1978
1979
Oil
13,719
16,626
16,389
17,876
17,755
18,051
Gas
7,032
7,437
8,003
9,836
11,169
13,070
Is
Dry
11,867
13,203
13,396
14,198
15,437
14,947
Service &
Suspended*
852
1,121
2,741
4,196
5,570
4,264
Total
Wells
33,470
38,387
40,529
46,106
49,931
50,332
* Most suspended wells will likely produce at some future date. No
information is available regarding producing/nonproducing status.
end of the year. By January 28, 1980, 2,647 drilling rigs were reported to
be active (Oil and Gas Journal, "Hughes Rig Count," p. 97, February 4, 1980).
The all-time record high was set in May 1956 when an average of 2,899 units
worked. World Oil's forecast issued in January 1980 was that an average of
2,525 rigs would be needed for 1980.
The cumulative average number of drilling rigs in operation in the U.S.
as of 8 September 1980 is 2,788 compared with 2,070 on 10 September 1979 (Oil
and Gas Journal, "U.S. Well Completions - July 1980 API Data," p. 178). This
represents a 34.7% increase in rigs over 1979. It appears that drilling ac-
tivity in 1980 will exceed the previous record year of 1956. The total num-
ber of well completions up through July 1980 is 19.0% ahead of the figures
for 1979, while the total footage drilled is up only 16.8%.
MODEL FOR DRILLING OPERATIONS
An equation summing the total VOC emissions (E, kilograms per day) occur-
ring during the drilling of an oil/gas well will consist of three general
parts, or terms.
The first term of the equation will attempt to account for the VOC result-
ing from the oil contained in the volume of porous rock cut from a producing
zone by the drill and flushed out of the well-bore by the drilling mud. Thus,
this term of the equation will contain the volume of producing zone rock re-
moved, multiplied by factors to account for the porosity of the rock, the den-
sity of the oil in the producing zone, and the fraction of the oil contained
in the pores of the cuttings that can be considered as VOC (some of the oil
will not readily volatilize, while the light hydrocarbons, methane, and eth-
ane are not reactive enough to be considered as VOCs).
58
-------
The second part of the equation to be considered when summing up the VOC
losses will account for the rate of leakage of oil/gas from an oil-bearing
zone into the drilling mud. As stated earlier, leakage of oil into the mud
does not normally occur; the mud density is very carefully controlled so as to
maintain a positive pressure on all formations likely to be encountered. The
entrance of low-density fluid or gas bubbles into the drilling mud is highly
undesirable since it could result in a "kick" and a possible blowout situation
that would activate the blowout preventers and result in lost drilling time.
Regardless of the precautions taken, leakage of formation fluids into the
drilling mud does occasionally happen during exploratory drilling when unex-
pected high-pressure formations are encountered. Adjustments are rapidly made
in the drilling mud density to quell the leakage problem. Leakage can also
occur if the drill string is hoisted from the well-bore at too rapid a rate;
a slight lowering of the hydrostatic head below the drill bit can be produced
under these conditions (swabbing the hole). The occurrences described may
have a low probability and may account for minor VOC emissions, but they should
be considered and warrant inclusion in an equation describing the total VOC
emissions.
The third and final term included in the total VOC summation expression
is concerned with the emission from.oil-based muds. The rate of evaporative
loss of No. 2 diesel fuel (the usual liquid phase ingredient in oil-based mud)
must depend on the mud tmperature at the mud-atmosphere interface, the total
area of the mud-atmosphere interface, the wind velocity and other factors.
This rate of loss would be multiplied by the length of time the oil-based mud
was used. Oil-based muds are not often used and the inclusion of their VOC
contribution is not meant to imply that the evaporative loss is excessive.
The fraction of wells drilled using oil-based muds is quite small and a factor
can be included in this VOC term to account for this usage.
An expression summarizing the total VOC emissions (E, kilograms per day)
occurring during the drilling of an oil or gas well can be written as:
C —•
Volume of Hole
Drilled
m3
(Producing Zone Interval'
Well Depth
Fraction
'Porosity of Pro- \
ducing Zone j
^ Cuttings, Fraction /
/ Density of Oil \
(in Producing Zone) x |
\ kg/m3 /
/Average Producing \]
I Zone Exposed Time 1 +
\ Days /J
Fraction of Oil \
Considered VOC J + I
Fraction /J I
"/ Fraction of Wells '
(Using Oil-Based Muds
A Fraction /
Leakage of Oil/Gas
Into Drilling Mud
kg/day
/ Oil-Based Mud , -
(Evaporation Rate I x [ Drilling Time
\ kg/day / \ Days /J
\ / Average Hole \ 1
59
-------
en
o
Q
Z
<
in
n
O
i
K-
CO
_l
LU
56,083
35,001
20,622
0
1956 58
78 1980
Figure 12. U.S. drilling activity since 1956.
-------
TABLE 6. U.S. EXPLORATORY DRILLING*
Productive Wells
Year Oil Gas Total
1978 1,215 1,483 2,698
1979 1,236 1,819 3,055
1980 (predicted Jan.)
(cum. July) 841 1,063 1,904
(predicted July)
Total Conus Avg
Exploratory Depth, m (ft)
12,125
11,658
13,075
- 6,247
13,607
1,767 (5,798)
1,809 (5,936)
* Includes new field wildcat tests, new pools, shallower pools, outoost,
and extension.
TABLE 7. U.S. NEW FIELD EXPLORATORY WELL DRILLING (WILDCAT)
Productive Wells
Year
1975-
1976
1977
1978
1979
Oil
510
508
506
516
547
Gas
522
530
526
501
744
Total
1032
1038
1032
1017
1291
Total
Wildcat*
7026
6438
7121
6779
7680
Average
Depth, m (ft)
1778 (5834)
1787 (5863)
1838 (6031)
1913 (6275)
1895 (6217)
* 1976-1979 totals include suspended new field wildcat wells. It is pre-
sumed that most of these tests will ultimately be finalized as oil or
gas discoveries because they were suspended.
61
-------
cr>
fNi
C/)
ID
O
I
h-
111
1956
78
1980
Figure 13. New field wildcatting since 1956.
-------
Ol
OJ
Q
2
13
O
I
I-
(3
2
h-
<
DC
LU
Q_
O
CO
O
cc
1968
78 1979
Figure 14. Drilling rig activity.
-------
Terms involving stored fuel tank losses and unburned organics in prime
mover exhaust products could be added to this general equation, but considera-
tion of these items is not in the purview of this study.
Estimates of the order of magnitude of the 'VOC emissions occurring during
the drilling of oil/gas wells (E) can be made by judicious utilization of new
field information provided from PDS files referred to in Section 6 and Appen-
dix A and the statistics on drilling activity such as those presented in Tables
5, 6, and 7. Values for some of the pertinent terms in the equation for E can
be obtained from these data and estimates of other terms, such as the porosity of
the producing formation (0.20 is a good estimate) and the density of the oil/
gas in the producing zone (approximately 600 kg/m3), can be made.
Using information given for 1979 on the total number of wells and footage
drilled in the conus 48 states (excluding offshore drilling) and the average
number of active drilling rigs for 1979, the following statistics were calcu-
lated:
Average well depth 1491 m (4893 ft)
Average depth drilled per day 117.3 m (385 ft)
Average well drilling time 14.7 days*
Average exploratory well depth 1809 m (5936 ft)
Average exploratory well drilling time 17.4 days*
New field data given in Table 3 provide values of average well depth and
producing zone interval for many states. Values for five representative oil/
gas-producing states are summarized in Table 8.
From the ratio of the producing zone interval to the average well depth
(depth ratio, Am/m) given in Table 8, it appears that for the five states
shown, less than 1% of the total well drilling time is spent cutting through
the producing zone. Assuming that the average well diameter is 0.23 meters
and using a formation porosity and oil density of 0.2 and 600 kg/m3, respec-
tively, a value of 0.5 for the fraction of the oil in the rock that can be
considered as VOC, and the depth ratio from Table 8, the values of the first
bracketed quantity on the right-hand side of the equation for E have been cal-
culated and appear in Table 9 under the column heading "VOC per Well." The
well drilling time given in Table 9 is the result of dividing the average new
field well depth for the state by the average depth drilled per rig-day (117.3
m [385 ft]). Dividing the VOC per well by the drilling time, an average VOC
emission rate per day per producing well being drilled is obtained. If this
number is multiplied by the rate at which new field wells are being brought
into production in that state, the results would be the total state VOC emis-
sion rate from the producing zone cuttings. The average VOC emission rate per
* Assuming 2 days are required to relocate the drilling rig after a well dril-
ling assignment.
64
-------
TABLE 8. NEW FIELD DATA SUMMARY
State
Alabama
Arkansas
Colorado
Louisiana
Montana
Avg Well Depth,
m (ft)
3014 (9887)
1853 (6078)
1734 (5689)
3324 (10906)
2720 (8924)
Producing Zone,
A m (A ft)
5.2 (17)
6.7 (22)
9.1 (30)
6.7 (22)
7.9 (26)
Prod. Zone Interval (Am-
Avg Well Depth ' ^rn-
0.00172
0.00362
0.00527
0.00202
0.00291
TABLE 9. ESTIMATED VOC EMISSIONS FROM NEW FIELD WELL DRILLING
State
VOC per Well
(kg/well)
Average Well
Drilling Time
(days)
VOC Avg
Rate per Well
(kg/well/day)
Alabama
Arkansas
Colorado
Louisiana
Montana
51.7
66.9
91.5
67.0
78.8
25.7
15.8
14.8
28.3
23.2
2.0
4.2
6.2
2.4
3.4
day per producing well being drilled ranges from 2.0 kg/day for Alabama to 6.2
kg/day for Colorado.
The contribution of the second bracketed term to E cannot be calculated
at present since the leakage rate of oil/gas from the producing zone into the
drilling mud is unknown. The third bracketed term, which includes the con-
tribution to E of diesel fuel oil evaporation losses from oil-based mud, is
not often of significance since oil-based muds are used on only a small frac-
tion of wells drilled.
MODEL FOR PRODUCTION OPERATIONS
The emissions here are primarily fugitive and the equipment components
comprise valves, connections, pumps, compressors, meters, hatches, diaphragms,
and pits. The following model is applicable:
65
-------
c ,•<.«.,•„„ o,*« - v fComponenti fEmission
Emission Rate - I (Inv£ntory) (per component
kg/day No. of kg/day/
components component
The Emission Rates per Component for production operations have been de-
veloped by Rockwell under API sponsorship, to be issued as "Fugitive Hydro-
carbon Emissions from Petroleum Production Operations" (two volumes) by
W. S. Eaton, et al., 1980, by the API.
As part of this contract, sites in five new fields containing current oil
and gas production and drilling equipment were visited. The five sites were
located in the States of Montana, New Mexico, Oklahoma, Texas, and Wyoming.
Visits to these sites were made to document by means of 35-mm color slides the
equipment and equipment components currently in use for new oil and gas pro-
duction and drilling. Appendix B contains a brief description of each of the
total 300+ slides taken, with reference to the major equipment items appear-
ing on each slide.
For more complete and effective information transfer, the actual 300+
slides and a sound tape containing a narrative description of each slide have
been placed under separate cover as part of this report. They are part of
Appendix B, which is on file at the U.S. EPA Office of Air Quality Planning
and Standards, Research Triangle Park, NC.
Although the slides are representative of current oil and gas production
and drilling technology, the sites were not selected to be representative of
all new fields; however, they do reflect differences in current technology,
geography, and production methods. The equipment shown on the slides cannot
be considered that of a typical site or facility in a national sense. This
would have required an extensive in-depth survey far beyond the scope of this
project.
Application of the model to estimate VOC emissions from oil and gas pro-
duction and drilling equipment requires the combination of (1) production sur-
vey information, and (2) the number of components, provided that these can
be considered typical. Within the limited time and budget, we were unable to
analyze the slides for the number of components with respect to a major para-
meter, such as a well, or with respect to a major process unit.
Once the numbers of components for truly typical production and drilling
equipment on a nationwide basis have been identified, application of the new
field production and drilling survey information developed on this program
will lead directly to a meaningful estimation of VOC emissions associated with
an EPA region, state, county, or field.
Petroleum production storage tank emissions will not be included as part
of the production operation emission rates to be developed. The reason for
this is to avoid duplication of effort, since the EPA is sponsoring such work
with another contractor.
66
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO.
3. RECIPIENT'S ACCESSION-NO.
4 TITLE ANDSUBTITLE
5. REPORT DATE
Assessment of Oil Production Volatile Organic
Compound Sources
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
W.S. Eaton, G.R. Schneider, W. Unterberg, and
F.G. Bush, III
8. PERFORMING ORGANIZATION REPORT NO.
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Environmental Monitoring & Services Center
Rockwell International
2421 West Hillcrest Drive
Newbury Park, CA 91320
10. PROGRAM ELEMENT NO.
AUN1K
11. CONTRACT/GRANT NO.
68-03-2648
12. SPONSORING AGENCY NAME AND ADDRESS
Municipal Environmental Research Laboratory-Ci
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, OH 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final: January-September 1980
14. SPONSORING AGENCY CODE
EPA/600/14
15. SUPPLEMENTARY NOTES
Project Officer: Leo T. McCarthy, Jr. (201) 321-6630
16. ABSTRACT
An extensive description of oil and gas exploration and production drilling tech-
nology is presented. Emphasis has been placed on the makeup, use, and disposal of
drilling fluids. A simple model for assessment of VOC emissions accompanying drilling
is presented, along with an estimation of the potential VOC emissions associated with
drilling activities.
Emissions of volatile organic compounds (VOC) from oil production in new fields
were estimated, based on three types of information: [1] extent of new oil and gas
fields (those that started production after 1974) in the contiguous 48 states; [2]
drilling techniques used for oil and gas exploration and production wells (and their
VOC potential), with specific emphasis on the drilling fluids; and [3] equipment and
techniques for oil and gas production in new fields and their potential VOC sources.
This report was submitted in fulfillment of Contract 68-03-2648 by the Environ-
mental Monitoring & Services Center of Rockwell International under the sponsorship
of the U.S. Environmental Protection Agency. This report covers the period from
January 1980 to September 1980, and the work was completed as of September 1980.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COS AT I Field/Group
Oil Fields
Oil Wells
Gases
Gas Sampling
Volatiles
Volatile Organics
Air Pollution
Drilling Fluids
13B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
67
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
67
------- |