906R87103
DALLAS, TEXAS
CHAPTER 3
OIL AND GAS DAMAGE CASES
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CONTENTS
DAMAGE CASES 1
INTRODUCTION 1
Purpose of the Damage Case Review 1
Methodology for Gathering Damage Case Information 2
Information Categories 2
Sources and Contacts 3
Field Work 3
Test of Proof 4
Contents of Appendix C 5
Review By State Groups and Other Sources 5
Limitations of the Methodology and Its Results 5
Schedule 5
Several Oil- and Gas-Producing States Not Included in
Analysis 5
Method Did Not Necessarily Produce A Representative
Sample 5
Issues of Compliance May Not Be Fully Stated 7
Effects of Recent Oil Price Declines Could Affect Damage
Cases 7
Implications of Current Market Conditions 7
General Conclusions 8
Damages are caused by nonhazardous as well as hazardous
substances 9
Past practices can both cause and contribute to current
damages 10
State standards vary widely in scope and content 11
Implementation and enforcement of state requirements is
seriously deficient 12
Structure of This Chapter 13
Overview of Conditions Within Zones 13
Discussions of Issues 14
ZONE1 15
ZONE 2 15
Operations 15
Types of Operators 15
Environmental and Development Context 16
Major Issues 17
Illegal dumping of brine, drilling mud, and tracing fluid 17
Damage to water wells after gas or oil well fracturing 19
Inappropriate land spreading requirements in West Viriginia 20
Illegal discharge of oil 21
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Abandoned wells 22
ZONES 23
ZONE 4 23
Operations 23
Types of Operators 24
Environmental and Development Context 25
Major Issues 25
Groundwater Contamination from Unlined Brine Disposal
and Reserve Pits 25
Use of Hazardous Chemicals in Workover Operations 26
Allowable Discharge of Drilling Mud Into Gulf Coast
Estuaries 27
Illegal Dumping In the Louisiana Gulf Coast Area 27
Illegal Dumping in Arkansas 29
Improperly Operated Injection Wells 31
Improperly Abandoned and Improperly Plugged Wells 31
ZONES 33
Operations 33
Types of Operators 33
Major Issues 33
Groundwater Pollution in Michigan 33
Illegal Dumping of Wastes in Ohio 35
Contamination of Ground Water From Injection and Annular
Disposal 36
Contamination of Ground Water From Reserve Pits 37
ZONE 6 39
Operations 39
Types of Operators 39
Environmental and Development Context 40
Major Issues 41
Poor Lease Maintenance 41
Pollution of Ground Water with Chlorides from Improperly
Abandoned Wells and Reserve Pits 42
Problems with Injection Wells 43
ZONE 7 45
Operations 45
Types of Operators 45
Environmental and Development Context 46
Major Issues 47
Discharge of produced water and drilling mud into bays and
estuaries of the Texas Gulf Coast 47
Leaching of reserve pit constituents 48
Ground water chloride pollution from injection wells 49
Illegal dumping 50
Improperly abandoned or improperly plugged wells 51
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ZONES 53
Operations 53
Types of Operators 53
Environmental and Development Context 54
Major Issues 55
Illegal dumping 55
Reclamation problems 56
Discharge of produced water into surface streams 56
ZONE 9 58
Operations 58
Types of Operators 58
Environmental and Development Context 59
Major Issues 59
Unlined Produced Water and Oilfield Waste Pit Contents
Leaching into Ground Water 59
Damage to Ground Water From Leaking Injection Wells 61
Contamination of Ground Water From Improperly
Completed Oil and Gas Wells 62
ZONE 10 64
Operations 64
Types of Operators 65
Environmental and Development Context 65
Major Issues 65
Discharge of brines and oily wastes to ephemeral streams 65
Damages from disposal of drilling wastes in ponds 67
ZONE 11 68
Operations 68
Further development of reserves has been almost entirely curtailed
throughout Alaska since the prices of oil and gas have declined.
There were only 100 wells drilled in the State in 1985, none of them
exploratory. However, if world prices were to increase 69
Types of Operators 69
Environmental and Development Context 69
Major Issues 70
The North Slope 70
The Kenai Peninsula 74
•IV
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DAMAGE CASES
INTRODUCTION
Purpose of the Damage Case Review
The damage case study effort conducted for this report had several objectives, as
discussed below.
To Respond to the Requirements of Section 8002fin)fO: The primary objective
was to respond to the requirements of Section 8002(m) of RCRA which requires EPA to
identify "Documented cases that prove or have caused danger to human health and the
environment from surface runoff or leachate." In interpreting this passage, EPA has
emphasized the importance of strict documentation of cases by establishing a "test of proof'
(discussed below) that all cases were required to pass before they could be included in this
report. In addition, EPA has emphasized development of recent cases that illustrate
damages created by current practices under current State regulations. Historical damages
that occurred under prior engineering practices or under previous regulatory regimes have
been excluded unless such historical damages illustrate health or environmental problems
that the Agency believes should be brought to the attention of Congress now.1 The overall
objective for the documented cases has been to illustrate clear links of cause and effect
between waste management practices and resulting damages, and to identify cases where
damages have been most significant in terms of human health or environmental impacts.
To Provide An Overview of The Nature of Damages Associated With Oil and Gas
Exploration. Development, or Production Activities: In the course of accumulating damage
cases, EPA has acquired a significant amount of information on cases that do not pass the
formal test of proof mentioned above. Although references to these cases are excluded
1 The primary example of this is the problem of abandoned wells, discussed at length under Region
1, below. The abandoned well problem results for the most part from inadequate past plugging practices
that have since been improved under State regulations, yet associated damages to health and the environment
are continuing.
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from this report and from Appendix III, the information gathered has served as useful
background in developing the overview discussions presented here, and in supporting the
risk assessment reported in Chapter V of this report.
Methodology for Gathering Damage Case Information
The methodology for identifying, collecting, and processing damage cases was
presented in draft form in the Technical Report published on October 31, 1986.
Modifications to that draft methodology have been minimal.
Information Categories
As stated in the Technical Report, the damage case effort attempted to collect the
following types of information on each case:
1. Characterization of specific damage types: For each case, the environmental
medium involved is listed (ground water, surface water, or land), along
with the type of incident and characterization of damage involved. Although
the Technical Report included "suspected damage" as a category, no case
has been included where no documented damage could be demonstrated.
Where significant suspected damages exist in addition to documented
damages, they are referenced. Types of potential health or environmental
damages of interest are shown on Table 1.
2. The size and location of the site: Sites are located by nearest town, county,
and any other available environmental factors. Where significant
hydrogeological or other pertinent factors are known, they are included;
however, this type of information has been difficult to gather for all cases.
3. The operating status of the facility or site: All pertinent factors or the site's
status (active, inactive, in process of shutdown, etc.) have been noted.
4. Identification of the type and volume of waste involved: While the type of
waste involved has been easy to define, volumes often have not. They have
been included wherever possible.
5. Identification of waste management practices: For each incident, the waste
management practices associated with the incident have been discussed in
context.
6. Identification of any pertinent regulations affecting the site: State
regulations in force across the oil- and gas-producing States are discussed at
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length in Appendix A. Since it would be unwieldy to attempt to discuss all
pertinent regulations in relation to each site, each documented case includes
a section on Compliance Issues that discusses significant regulatory issues
associated with each incident as reported by sources or contacts.2 In some
cases, interpretations were necessary.
7. Type of documentation available: All documentation available for each case
has been included in Appendix C to the extent possible. For a few cases,
documentation is extremely extensive and space has permitted only the most
pertinent listings to be included. All information gathered is, however,
available in EPA files.
Sources and Contacts
As stated in the Technical Report, no attempt was made to compile a complete
census of current damage cases. States f/om which cases were drawn are listed on Table
2. As evident from the table, resources did not permit gathering of cases from all states
listed in the Technical Report: States for which some information was gathered but from
which documented damages cases are noj presented are listed separately.
Within each of the States, every effort was made to contact all available source
categories listed in the Technical Report^ Because time was extremely
limited, the effort relied principally on information available through relevant State and local
agencies, and on contacts provided through public interest or citizens' groups. In some
instances, cases were developed through contacts with private attorneys directly engaged in
litigation. Because these nongovernmental sources often provided information on incidents
of which State agencies were unaware, such cases were often undocumented at the State
level. State agencies were, however, provided with review drafts of case write-ups and
were encouraged to provide comments.
Field Work
Virtually all of the data used here was gathered through field work or through
follow-up to that field work. For each State, researchers first contacted all State agencies
that play a significant role in the regulation of oil or gas operations and set up appointments
^ All discussions, including particularly the compliance sections of each case study, have been
reviewed by State officials and by any other sources or contacts that provided information on a case.
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Table 1
Type of Damage of Concern to This Study
1. Human Health Effect? (acute and chronic): While there are some instances where
contamination has resulted in cases of acute adverse human health effects, such cases
are difficult to document. Levels of pollution exposure caused by oil and gas operations
are more likely to be in ranges associated with chronic carcinogenic and non-carcinogenic
effects.
2. Environmental Effects: Impairment of natural ecosystems and habitats, including
contaminating of soils, impariment of terrestrial or aquatic vegetation, or reduction of the
quality of surface waters.
3. Effects on wildlife: Impairment to terrestrial or aquatic fauna; types of damage may include
reduction in species' presence or density, impairment of species health or reproductive
ability, or significant changes in ecological relationships among species.
4. Effects on livestock: Morbidity of mortality of livestock, impairment in the marketability of
livestock, or any other adverse economic impact on livestock.
5. Impairment of other natural resources: Contamination of any current or porteneial source
of drinking water, disruption or lasting impairment to agricultural lands or commercial crops,
impairment of potential or actual industrial use of land, or reduction in current or potential
use of land.
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for field visits. At the same time, contacts and appointments were made where possible
with local citizens' groups and private attorneys in each State. Field work was done from
December 1986 through February 1987. During the field work actual documentation was
gathered and as many additional contacts were made as possible.
Test of Proof
All cases were classified as to whether or not they met the formal test of proof first
described in the October 1986 Technical Report. Three tests were used; cases were
considered to meet the documentation standards of 8002(m)(C) if they met one or more of
them. These tests were to some extent judgmental; a case was considered to meet the test
of proof on the basis of one or more of the following:
1. Scientific investigation: A case could meet the test of proof if damages were
found to exist as part of the findings of a scientific study. Such studies
could be extensive formal investigations supporting litigation or a State
enforcement action, or they could, in some instances, be the results of
technical tests (such as monitoring of wells) if such tests were (a) conducted
with State-approved quality control procedures, and (b) revealed
contamination levels in excess of an applicable State or Federal standard or
guideline (such as a drinking water standard or water quality criterion).
2. Administrative ruling: A case could meet the test of proof if damages were
found to exist through a formal administrative finding, such as the
conclusions of a site report by a field investigator, or through existence of
an enforcement action that cited specific health or environmental damages.
3. Court decision: The third way in which a case could meet the test of proof
was if damages were found to exist through the ruling of a court or through
an out- of-court settlement.
As noted above, cases that failed to meet the test of proof were not discarded, but
were retained to serve as additional background to the report. No cases that failed the test
of proof are listed in Appendix C or referenced specifically in the text of this report.
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Contents of Appendix C
For each test-of-proof case, Appendix C presents a summary write-up covering all
of the above information. Summary tables listing the numbers and types of cases
developed appear at the beginning of that Appendix.
Review By State Groups and Other Sources
All agencies, groups, and individuals who provided documentation or who have
jurisdiction over the sites in any specific State were sent draft copies of the material
presented in Appendix C. Their comments were incorporated to the extent possible;
judgments on which comments should be included were made by EPA.
Limitations of the Methodology and Its Results
Schedule
The time period over which the field work occurred was short. In addition, much
of the field work was arranged or conducted over the December 1986/January 1987 holiday
period, when it was often difficult to make contacts with State representatives and private
groups. To the extent that resources permitted, follow-up visits were made to fill gaps.
Nevertheless, coverage of some States listed in the October Technical Report had to be
omitted entirely, and coverage in others (particularly Oklahoma) was limited.
Several Oil- and Gas-Producing States Not Included in Analysis
Aside from the States that originally were intended to be covered, some of the oil
and gas producing States were omitted entirely from coverage. This issue was covered in
the Technical Report: States actually visited accounted for a significant percentage of U.S.
oil and gas production (refer to Table 1).
Method Did Not Necessarily Produce A Representative Sample
Although every attempt was made to produce representative cases, the study cannot
assert that its cases are in fact a statistically representative record of damages in each State.
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Aside from scheduling and budgetary limitations alluded to above, there are a number of
practical reasons why this is so.
First, record keeping varies significantly among States. A few States, such as
Ohio, have unusually complete and up-to-date central records of enforcement actions and
complaints. More often, however, enforcement records are incomplete and/or distributed
throughout regional offices within the State. Schedules were such that only a few
offices—usually only the State's central offices—were visited by researchers.
Furthermore, their ability to collect files at each office was limited by the time available on
site (usually one day, but never more than three days) and by the ability of each State to
spare staff time to assist the research. The number of cases found at each office and
amount of material gathered was influenced strongly by these constraints.
Second, in some States data on known damage cases has often been sealed by the
courts in response to requests by defendants, usually oil companies. This is typical
practice, for instance, in Texas. In some cases the records of well-publicized damage
incidents are almost entirely unavailable for review. Impoundment conceals the scientific
and administrative documentation of the incident as well as the nature and size of the
settlement. While it would be theoretically possible to open these records through a formal
request through the courts, this was not done because (1) it would have been extremely
difficult to identify the cases of interest (precisely because records are unavailable) and (2)
it would have taken many months for the records to be obtained even if the request were
granted.
A third general limitation in locating damage cases is that oil and gas activities in
some parts of the country are in remote, unpopulated, and (therefore) unstudied areas. The
Overthrust Belt in Wyoming and the North Slope in Alaska are examples. In these areas,
not only is there no significant population present to experience adverse health effects,
access to sites is physically difficult, often limited by restrictions imposed by the companies
active in the areas (this is especially true on the Alaskan North Slope), therefore making it
difficult to witness environmental damages sustained.
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Issues of Compliance May Not Be Fully Stated
While every effort was made to put each case into accurate regulatory context, the
discussions contained under "Compliance Issues" may not always present a complete
picture of all applicable compliance issues. There are several reasons for this:
• The update of the review of State regulations presented in Appendix A was
conducted simultaneously with the damage case effort. Its results were
therefore not available in time to be fully incorporated into the write-ups.
• Compliance issues were generally developed through interviews with State
officials, lawyers, and interested citizens' groups. Although these parties
had the opportunity to review and comment, time for this comment was
itself limited and errors and omissions may have been made by reviewers.
• Compliance issues reviewed focused almost entirely on specific
requirements affecting oil and gas operations. Other more general
environmental or public health statutes may in fact have jurisdiction in some
cases, but—being State-specific—could not be fully anticipated by EPA
researchers and may have escaped the attention of State and local reviewers.
Effects of Recent OH Price Declines Could Affect Damage Cases
The effects of the recent oil price decline on the nature and extent of damages now
and in the future cannot be fully analyzed. No systematic attempt was made within the case
study write-ups contained in Appendix C to deal with these issues. To some extent,
current damages may reflect negative effects caused by the price decline: one example is the
increase in improperly abandoned or improperly plugged wells caused by bankruptcies.
On the other hand, current damages may not reflect future conditions once prices increase:
increased drilling levels may be accompanied by increased damages from drilling
operations, and so forth. While this issue is inherently speculative, it is discussed to the
extent possible in relation to particular categories of damage cases.
Implications of Current Market Conditions
Oklahoma and Texas have been affected perhaps more adversely by the current
decline of oil and gas prices than any other area of the country except Alaska (Zone 11).
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Although production is still extensive and will continue, recent economic losses have been
heavy.
The current situation affects potential environmental damages in several ways. On
the one hand, problems associated with improper well abandonment or plugging have
increased (often because of bankruptcies), marginally profitable companies appear to have
cut down on environmental compliance expenditures, and the States' resources available
for enforcing existing rules and regulations have declined. These forces tend to increase
the potential for environmental damages. On the other hand, the slowdown in drilling and
development has decreased the amount of wastes that might otherwise be generated by
drilling activity, producing perhaps a temporary decrease in the environmental impacts
associated with certain waste streams, such as in the Deep Anadarko Basin where deep
exploration has fallen off because it is so capital intensive.
As elsewhere, impacts of currently depressed prices affect smaller operators more
than the major companies. Continued market constraints can be expected, however, to
significantly decrease expensive deep exploration and production projects.
General Conclusions
As is evident from the cases presented below, health and environmental damages
caused by oil and gas operations appear to be significant, widespread, and in need of
correction. The most obvious impacts are on natural resources and the environment.
Human health impacts also exist, but these tend, by their nature, to be harder to document.
In many cases, there is convincing circumstantial evidence that serious health effects, such
as cancer and other fatal diseases, have been caused or are potentially caused by oil and gas
activities.
On the basis of the research done for this study, the following general conclusions
can be drawn.
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Damages are caused by nonhazardous as well as hazardous
substances
The clearest division that can be drawn among the cases is between damages caused
by disposal (legal or illegal) of produced water, and damages caused by disposal of all
other categories of wastes.
Although produced water may contain many toxic substances known to be soluble
in water (for instance, oil, heavy metals and organic compounds such as benzene), and
therefore can, in some instances, be considered hazardous under the definitions of RCRA,
most produced water causes damage because of its chloride content. Chloride
concentrations in produced waters vary widely—from a few parts per million (ppm) to over
100,000 ppm in some cases—but damages are not necessarily proportional to brine
concentration. EPA's drinking water standard for chlorides is only 250 ppm, and while
drinking water is, of necessity, consumed at levels higher than this standard in many parts
of the country, even comparatively low-chloride brines can contaminate water supplies
enough to render them useless. Livestock can in practice be watered at levels two and three
times higher than the 250 ppm human consumption standard, but this use too is fairly
easily damaged. The third major category of produced-water-related damage is
contamination of soils or surface waters, which can destroy vegetation, aquatic organisms,
or agricultural productivity. For some productive purposes, such as agriculture, this type
of damage may be virtually permanent. In other cases (such as fish kills) it can be reversed
relatively quickly, perhaps over a period of a few years.
The other categories of potentially damaging wastes include drilling muds (which
may often contain brine, toxic heavy metals, and chemical additives) and a wide range of
chemicals used in completing wells, maintaining production, and reworking old sites.
Many of these substances are clearly hazardous by one or more RCRA definitions (they
may be toxic, corrosive, or ignitable) but health and environmental concern centers
primarily on their toxicity.
It has been comparatively easy to document damages caused by brines because the
damages in question are readily measurable, both scientifically and economically. It was
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difficult, on the other hand, to document damages caused by toxic chemicals and metals.
This was true for a number of reasons. First, toxic effects often take many years to
manifest themselves as cancers or other chronic diseases; when they eventually do it is
usually impossible to link individual cases to specific environmental exposures. Second,
toxic contamination may occur simultaneously with chloride contamination; when this
happens, the chloride contamination, being acute, tends to become the central fact of the
case, dominating damage characterization, case documentation, and response.
Past practices can both cause and contribute to current damages
Health and environmental damages caused by oil and gas extraction projects cannot
be fully corrected by addressing only current operations. One of the most important
conclusions to be drawn from the cases presented here is that improper closure and
abandonment of oil and gas sites causes, or significantly contributes to, current damages.
In some cases, damages are caused entirely by inactive sites. In other cases, inactive sites
exacerbate problems caused by current operations, increasing the scale of damage and
confusing the assignment of responsibility and liability.
The clearest example of this is improper or inadequate plugging or abandonment of
wells. It is estimated that there may be as many as 1.2 million abandoned production
wells in the U.S.3In most states, plugging requirements, if they exist at all, are
comparatively recent. Even where plugging requirements do exist, they are often
inadequate to prevent damage from occurring. In heavily developed areas such as the
Permian Basin, which have been under intensive development for many decades, literally
thousands of wells have been left improperly capped, often forming direct conduits
between the surface, drinking water aquifers, and producing zones. In some cases brines
under artesian pressure leak directly to the surface. In other cases, liquids are forced up by
artificial pressure from secondary recovery or disposal wells. Where this occurs it is
difficult to assign liability—wells may have been improperly closed for any number of
reasons, including bankruptcy of the operator. The situation is exactly similar to post-
3 USEPA. EPA Activities Related to Sources of Ground-Water Contamination. Office of Ground-
Water Protection. 1987.
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closure problems at hazardous wastes sites.
The other major type of post-closure problems is burial of reserve pit wastes. The
toxic compounds that may be found in these pits (which may include a wide variety of
production-related chemicals and other wastes in addition to drilling muds) can contaminate
ground water years after a site is closed. Examples of this type of problem have been
found in California and Alaska, where development of previously remote areas has been
adversely affected by wastes left by petroleum development.
State standards vary widely in scope and content
Although EPA recognizes the need to adjust controls over oil and gas operations to
be responsive to local economic and geographic factors, current variations in state practices
are unnecessarily wide. Some states' rules are comprehensive in scope, technically
adequate in their design, and clear in their specific requirements. Other states' rules are,
unfortunately, limited in scope, technically inadequate to cope with local conditions, and
extremely vague in their requirements. They may also be so unrealistic as to invite
noncompliance, creating dramatic disparities between nominal and actual practices.
Technical differences in state requirements can also be signficant, an example being
the mechanical integrity testing of injection wells. Differences in test protocols can be
significant enough to make it theoretically possible for a well that fails a performance test in
one state to be considered fit for use in another.
Many states are in the process of upgrading their environmental requirements, but
defects in previous regulatory programs have contributed heavily to past
problems—problems that, as pointed out above, often contribute to current damages. In
addition, lax regulations in the past have sometimes created a climate of leniency that will
further complicate enforcement in the future.
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Implementation and enforcement of state requirements is seriously
deficient
The single most important cause of health and environmental damages from oil and
gas operations is failure of states to fully implement and aggressively enforce the rules that
are nominally in effect. There are many reasons for this. Some are inherent in the nature
of the oil and gas industry itself. Others are, unfortunately, the responsibility of the states
and private industry.
The inherent problems of controlling the health and environmental impacts of the oil
and gas industry should not be underestimated. The industry is large, old, and
geographically very extensive. Operations often occur in remote areas where it may be
difficult to set up effective waste management programs. The work is also difficult and
physically dangerous. In such circumstances, environmental controls are inevitably less
urgent than completing projects safely and maintaining production. All these factors make
regualtory enforcement logistically difficult, labor intensive, and expensive. Finally,
attempts to develop comprehensive environmental standards are comparatively recent, and
as stressed above, past practices and current problems are often interlinked. Regulatory
programs must deal with these in addition to their current responsibilities.
These difficulties do not entirely account for or in any way excuse the damages
revealed by the current study, however. Shortcomings in states programs and in voluntary
industry compliance are in urgent need of correction.
State regulatory programs are, as a rule, seriously underfunded and understaffed.
The major responsibilities of state inspectors in key states are often incommensurate with
the resources available to carry them out. In Texas, for example, 173 state inspectors are
required to supervise approximately 200,000 producing sites, 18,000 injection facilities,
and personally witness the closing and plugging of an average of 40,000 wells per year. In
Louisiana, 12 inspectors are responsible for 80,000 production wells and 4,000 injection
facilities; six of the available 12 positions are currently vacant.
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Many State regual|ory agencies face conflicting incentives and responsibilities. In
several States, responsibility for promoting and controlling oil and gas activities lie within
the same agency. In many cases, revenues for regulating agencies come from direct or
indirect taxes on petroleum operations. The conflicts inherent in such arrangements are
obvious. They undermine the credibility of enforcement in the eyes of the public and create
an atmosphere of leniency that encourages substandard compliance from less scrupulous
operators.
In some States, economic reliance on oil industry revenues increases public
tolerance of environmental damages. It may also tend to discourage citizens from
complaining about damages, either out of cynicism or for fear of job reprisals. In extreme
cases, illegal practices are carried out in blatant disregard of rules, often by small
independent operators, but sometimes also by the major companies. The more diversified a
State's economy, however, the more broad the concern over health and environment issues
is likely to be.
Structure of This Chapter
Overview of Conditions Within Zones
The first subsection in the discussion of each zone presents an overview of
significant conditions within the zone. Topics include:
• Operations: A brief characterization of the zone's oil and gas activity,
including key descriptive statistics for 1985. As noted above, since the
recent drop in oil prices has been a determining force in the marketplace, its
specific effects on current operations in each zone are noted.
• Characterization of operators: The nature and extent of damages are in some
instances related to the type of operators active in a zone—major oil
companies, large, mid-sized, and small independents.
• Environmental an
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Discussions of Issues
Within each zone, damage cases are discussed on an issue-by-issue basis.
Individual cases are used as examples of broad patterns; when mentioned, they are
referenced by the case numbers used in Appendix C.
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ZONE 1
No significant oil and gas activity. No damages cases were collected.
ZONE 2
Zone 2 includes New York, Pennsylvania, Delaware, Maryland, New Jersey,
Virginia, West Virginia, Kentucky and Tennessee. Most of these States have minimal oil
and gas production. Though damage cases were collected for West Virginia and
Pennsylvania, most of the cases presented here came from West Virginia.
Operations
In the Appalachian Basin, which includes the production areas of Pennsylvania and
West Virginia, hydrocarbon production is generally marginally economic. Operations are
often promotional, low-budget efforts, frequently using low quality materials. Sufficient
funds for proper maintenance of production sites are often inadequate, and there is a
general lack of awareness of potential environmental liabilities among operators.
Although the absolute amount of oil produced in the Appalachian zone is small in
comparison with the rest of the country, wells in the zone produce a high proportion of
high chloride brine in relation to product. In West Virginia in 1985,1,839 new wells were
completed at an average depth of 4,270 feet. Only 18 exploratory wells were drilled in that
year. In Pennsylvania, 4,627 new wells were completed in 1985 to an average depth
2,287 feet; 59 exploratory wells were drilled in that year. The number of completed wells
was almost double the annual number drilled from 1979 through 1984, but the number of
exploratory wells was down almost 50 percent from 1984 levels.
Types of Operators
Oil and gas production in West Virginia is dominated by small operators, some
well-established, some new to the industry. Since the majority of extraction is
economically marginal, operators are extremely susceptible to market fluctuations, and are
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increasingly likely to compromise environmental performance in order to maintain
profitability. Current depressed conditions also tend to discourage proper abandonment
practices as wells are taken out of production. Prices also affect the ability of the State
regulatory agencies to enforce existing rules, which are funded by declining collections of
severance tax.
Pennsylvania's activity is similar. Operators include a mix of small and medium-
sized independents.
Environmental and Development Context
The oil development areas of West Virginia typically lie among elongated parallel
ridges separated by narrow valleys. The land has moderate to steeply graded hjlls and
mountains, making erosion from drill sites a significant and continuing problem. Runoff
from disturbed drilling areas causes loss of topsoil and elevated sediment loads in streams
and rivers. Enforcement of post-drilling restoration of the land surface is often neglected.
In West Virginia, surface rights are separate from mineral rights, and much of the
population lives in rural areas where average incomes are low by national standards. In the
permitting process for development of a new well, the signature of the surface owner is not
required and usually not obtained though a landowner may raise objections during a two
week comment period after a drilling application has been submitted. The surface owner
can obtain a hearing on oil and gas activities on his or her land only after the drilling has
taken place and some type of damage has been sustained. Very often the surface owner
signs a consent that waives all rights to any kind of compensation for damages. Since
many rural landowners do not have access to natural gas, when they do sustain
unreasonable damages from oil or gas activities they often sue for a lifetime supply of free
natural gas in lieu of a cash settlement. Thus, many damage cases in West Virginia do not
reference specific technical facts on damages sustained.
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West Virginia has no spacing rules for oil and gas wells unless the well is to be
drilled deeper than 6,000 feet. As a result, the site for drilling may be within a few
hundred feet of a residential water well. These water wells located in close proximity to oil
and gas drilling operations are often permanently damaged when the oil or gas well is
fractured, allowing for the migration of fracturing fluid, sand, and hydrocarbons into
residential water supplies.
In Pennsylvania the major oil and gas fields are located in rural areas in the
northwest part of the State. The land includes steep hills and mountains, appalachian
plateaus and narrow valleys. Erosion is a problem, as it is in West Virginia. Site
restoration is usually difficult and has not been required in the past. Aquifers are shallow,
and downvalley soils are often coarse and unconsolidated, allowing surface waters to
percolate readily to the ground water.
Major Issues
Illegal dumping of brine, drilling mud, and fracing fluid
Damage from illegal disposal of the range of wastes associated with drilling and
production is by far the most common type of problem in West Virginia. Results of illegal
discharge include fish kills, vegetation kills, and death of livestock from drinking polluted
water. Discharged fluids include oil, brines of up to 180,000 ppm chlorides, drilling fluids
containing detergent and bentonite mud, and fracing fluids that can have a pH of as low as
3.0 (highly acidic).
Illegal discharges take many forms, including draining of saltwater holding tanks
into creeks or streams, breaching of reserve pits into streams, siphoning of pits into
streams, or dumping of vacuum truck contents into fields or streams.
Enforcement is made very difficult due to inadequate State inspection and
enforcement manpower and the remote location of many drill sites. Most dumping
incidents come to light through complaints from landowners or anonymous informers.
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West Virginia's zero-discharge rule is generally thought to be unrealistic because of
the marginal economic condition of the oil industry in the State and the high expense of
developing alternative forms of disposal such as injection wells. As a practical matter,
marginal operators have the choice between paying a small fine for illegal dumping (when
and if they are caught), disposing of waste at commercial facilities, or constructing their
own injection wells.
Allegheny Land and Mineral Company of West Virginia operates a gas well # A-
226 on the property of Ray and Charlotte Willey. The well is located in a corn field
where cattle are fed in winter. Adjacent to the well is a stream known as the Beverlin
Fork. The well is located less than 1,000 feet from the Willey's residence. Allegheny
Land and Mineral also operates another gas well above the residence known as the #A-
306, located on property owned by the Willeys. Allegheny Land and Mineral has
maintained open reserve pits and a waste ditch running into Beverlin Fork. The ditch has
served to dispose of brine, oil, drip gas, detergents, fracturing fluids and produced
chemicals. Employees of the company told the Willeys that fluids in the pit were safe for
their livestock to drink.
The Willey's cattle drank the fluid in the reserve pit, became poisoned, causing
abortions, birth defects, weight loss, contaminated milk and death. Hogs were also
poisoned resulting in infertility and pig still-births. The soil on the farm was
contaminated causing a decrease in crop production and quality. The water table and
groundwater of the farm were contaminated, polluting the water well from which the
Willeys drew their domestic water supply. The value of the real estate was diminished as
a result of these damages to the land. The Willeys incurred laboratory expenses in having
testing done on livestock, soil, and water. The Willeys were awarded a cash settlement in
court of a total of $3,000. (WV 18)
On February 23, 1983, a complaint was filed by Tom Ancona, a fur trapper,
concerning a fish kill on Stillwell Creek. Another complaint was also filed anonymously
by an employee of Marietta Royalty Co. A trail of dead fish, frogs and salamanders was
followed up to a drilling site operated by Marietta Royalty Co. A syphon hose was found
draining the drilling waste pit into a tributary of Stillwell Creek. Acid levels at the pit
were a pH of 4.0, enough to shock and kill aquatic life according to WV District Fisheries
Biologist Scott Morrison. Samples and photographs were taken. Above the syphon site
no dead aquatic life was found. Marietta Royalty Co. was taken to court and fined a total
of $1,000 plus $30 in court costs. (WV20)
The long-term environmental impacts of chronic, widespread illegal dumping
include elevated salt levels in soil.
In Pennsylvania, dumping of oil and gas wastes prior to 1985 violated the State's
general water quality criteria, but the regulations were rarely enforced because of the
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general belief that the wastes were not harmful (due in part to the RCRA §3001 which
specifically exempts drilling fluids and produced waters from any federal regulation).
During this time, however, the State Fish and Game Commission did find stream
degradation in relation to numerous incidents involving one company:
S.W. Jack Drilling Co. violated State regulations regarding disposal of wastes.
The incidents took place at different locations, and involved discharge of drill cuttings,
fracing fluids, muds, fluids, and surfactants into several creeks and streams. In all cases
there was damage to the surface water. In specific instances the inspector noted other
damages. Pierce Farm #4 incident resulted in a kill of "...at least three hundred fish,
including native brook and brown trout that inhabited the Moss Run watershed." Kinter
Lease incident threatened fish in Little Mahoning Creek which is a "...high pressure trout
stream stocked by the Fish Commission." (PA 02)
The long term environmental impacts of chronic, widespread illegal dumping
include loss of aquatic life in surface streams and soil salt levels above those tolerated by
native vegetation. At current depressed prices, the incentives for illegal dumping remain
strong.
Damage to water wells after gas or oil well fracturing
There is no minimum distance established for separating oil or gas wells from
drinking water wells. Surface owners have little discretion over where an oil or gas drilling
site is to be located on their land, and sitings near domestic water wells are not uncommon.
During the fracing process, fractures can be produced allowing migration of brine, fracing
fluid, and hydrocarbons to a nearby water well. When this happens the water well is
permanently damaged; a new well must be drilled or an alternative source of drinking water
found. West Virginia has no automatic provision requiring drillers to replace water wells
lost in this way; owners must replace them at their own expense or sue the driller. There is
currently no initiative within West Virginia to design a statewide rule to correct this
situation. Where there is contamination of a fresh water source, State regulations presume
an oil or gas drilling site is responsible if one is located within 1000' of the water source.
Cabot Oil and Gas drilled, fractured, and completed an unspecified number of
production wells in late 1981. These wells were drilled in close proximity to several
domestic water wells (within 1000'). As a result of the drilling activity, the well water
for several residences was contaminated and could no longer be used for domestic
purposes. Four families sued Cabot Oil. Real estate values for the properties held by the
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families were reduced, as was agricultural productivity from their land. The case was
settled out of court for an undisclosed amount. (WV 02)
In 1982, Kaiser Gas Co. drilled a gas well on the property of Mr. James
Parsons. The well was fractured using a typical fracturing fluid or gel. The residual
fracturing fluid migrated into Mr. Parson's water well, drilled to a depth of 416ft. (The
gas well is located less than 1000 ft. from the water well.) By 1984, the water well was
unfit for domestic use and an alternate source of water had to be found. Well water was
analyzed and found to contain high levels of fluoride, sodium, iron, manganese. The
water had a hydrocarbon odor indicating the presence of gas. Dark and light gelatinous
material (fracturing fluid), was found along with white fibers. (WV 17)
Similar cases have occurred in Pennsylvania.
Civil suit was brought by 14 families living in the village of Belmar (the whole
village) against a Meadville-based oil drilling company, Norwesco Development
Corporation, in June 1986. Norwesco had drilled more than 200 wells near Belmar.
Though Norwesco claimed it was not responsible for contamination—from old, long
abandoned wells—the Pennsylvania Department of Environmental Resources (DER) sided
with Belmar residents agreeing that the contamination was from the drilling operation.
All families relying on the groundwater for their water lost their water supply. Ground
water in Belmar had been "pristine" prior to the drilling operation of Norwesco. Not only
were residents not able to drink or bathe using the groundwater, but they could not use the
water for washing clothes or household items without causing permanent stains. The
water from the contaminated wells would, "...burn your eyes in the shower, and your skin
is so dry and itchy when you get out." Plumbing fixtures were also pitted by the high
TDS and Cl levels. Families would have to buy bottled water for drinking and have to
drive, in some cases, as far as 30 miles to bathe. In early 1986, DER ordered Norwesco to
provide Belmar with an alternative water supply that was "adequate in quality and
quantity" to what the Belmar residents lost when their wells were contaminated. In
November 1986 Norwesco offered cash settlement of $275,000 to construct new water
system for village, and provision of temporary water supply. (PA 08)
Inappropriate land spreading requirements in West Viriginia
Land spreading, the mixing of waste drilling fluids with soils on the well site itself,
is legal in West Virginia. Muds containing up to 25,000 ppm chlorides are allowed to be
spread on the land; this concentration is considerably higher than is permitted for land
spreading in other States, and several times greater than native vegetation can tolerate.
Land spreading therefore frequently results in the destruction of arable land. Waste fluids
may kill surface vegetation where directly applied; salts in the wastes can also leach into
surrounding soil, affecting larger plants and trees. Seepage into shallow ground water is
also a potential problem.
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In early 1986 Tower Drilling land-applied the contents of a reserve pit to an area
100 ft. by 150 ft. All vegetation died in the area where pit contents were directly applied
and several trees adjacent to land application area were dying because of the leaching of
high levels of chlorides. Complaint was made by a private citizen. Land-applied drilling
fluid contained very high chloride levels, and soil was measured as having 18,000 ppm
chlorides. (WV13)
Illegal discharge of oil
The northwestern area of Pennsylvania has been officially designated as a
hazardous spill area in 1985 by the U.S. Environmental Protection Agency because of the
large number of oily waste discharges that have occurred there. Even though spills are
accidental releases, and thus do not constitute wastes routinely associated with the
extraction of oil and gas under the sense of the §3001 exemption, "spills" in this area of
Pennsylvania appear to represent deliberate, routine, and continuing illegal discharge of
waste oil.
Willful breeching of pits, opening of tank battery valves, and improper oil
spearation has resulted in an unusually high number of sites discharging oil directly to
streams. Despite the new 1985 regulations, these discharges appear to be continuing. The
issue was originally brought to the attention of the State through a Federal investigation of
the 500,000 acre Allegheny National Forest that discovered 500 separate spills.
These discharges have affected stream quality, fish population, other related aquatic
life, and in some instances human health.
USEPA declared a four county area (including Mckean, Warren, Venango, and
Elk counties) "a major spill area" in the summer of 1985. The area is the oldest
commercial oil producing region in the world. Chronic low-level releases have occurred
in the region since earliest production and continues to this day. EPA and other agencies
(e.g. US Fish & Wildlife, Pennsylvania Fish & Game, Coast Guard) were concerned that
continued discharge into the area's streams has already and will in the future have major
environmental impact. The area is dotted with thousands of low level producing wells
(with high ratio produced water), as well as thousands of abandoned wells and pits. In the
Allegheny Reservoir itself, divers spotted 20 of 81 known improperly plugged or
abandoned wells, seven of which were leaking and have since been plugged. There is
concern that many others are also leaking. The Coast Guard surveyed the forest for oil
spills and brine discharges, identifying those of particular danger to be cleaned
immediately, by government if necessary. In the Allegheny Forest alone USCG
identified over 500 sites "where oil is leaking from wells, pits, pipelines or storage tanks.
In fifty-nine cases, oil was discharging directly into streams; 217 sites showed evidence of
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past discharges and were on the verge of leaking again" into the Allegheny Reservoir. Oil
field wastes have had detrimental effect on the environment, "...lethal effect on trout
streams and [have] damaged timber and habitat for deer, bear and grouse. On Lewis
Run,... 52 sites have been identified and the stream supports little aquatic life." "Almost
all streams in the Allegheny Forest have suppressed fish population as a...direct result of
pollution from oil and gas." Monitoring of water wells noted that methane gas from an
adjacent natural gas field had migrated into local drinking water supplies, and had also
percolated into the basement of the park superintendant's home. The water well was
closed down and the home was temporarily evacuated. (PA 09)
Abandoned wells
Because Pennsylvania has had an active oil industry for longer than any other State,
the number of abandoned wells is large. Well plugging has been required since 1955, but
enforcement has evidently been loose and the State has not had the resources to plug wells
itself. The current general drilling rule, passed in 1985, requires a $2,500 bond to cap dry
wells, but problems associated with older wells continue. (See also longer discussion
related to Zone 7.)
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ZONE 3
No significant oil and gas activity. No damages cases were collected.
ZONE 4
Zone 4 includes Arkansas, Louisiana, Mississippi, Alabama, and Florida.
Attention in the damage case effort was focused on Arkansas and Louisiana—the two
major producers of the zone.
Operations
Operations in Arkansas are predominantly small to mid-sized independent
operations in mature production areas. A significant percentage of production comes from
stripper wells, which produce high volumes of associated brine. Most production occurs
in the southern portion of the State and is very similar to production in northern Louisiana.
The average depth of a new well drilled in 1985 was 4,148 feet. One hundred
twenty-one exploratory wells were drilled in that year, and 1,055 new wells were
completed.
Louisiana has two distinct production areas. The northern half of the State is
dominated by marginal stripper production from shallow wells in mature fields.
The southern half of Louisiana has experienced most of the State's development
activity in the last decade. There has been heavy, capital intensive development of the Gulf
Coast area, where gas is the principal product. Wells tend to be of medium depth;
operations are typically located in or near coastal wetland areas on barge platforms or small
coastal islands. Operators dredge canals and estuaries to gain access to sites. Reserve pits
are constructed out of the materials found on coastal islands, mainly from peat, which is
highly permeable and susceptiable to destruction from reserve pit fluids. Reserve pits on
barges are self-contained, but can be discharged in particular areas if wastes are below
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specified limits. If they are above these limits they must be injected or stored in (unlined)
pits on coastal islands.
The average depth of a new well drilled in northern Louisiana in 1985 was 2,713
feet; along the Gulf Coast it was 10,150. In the northern part of the State, 244 exploratory
wells were drilled and 4,033 were completed. In the southern part of the State, 215
exploratory wells were drilled and 1,414 were completed.
Types of Operators
In Arkansas, operators are generally small to midsized independents, including
some established operators and others new to the industry. Because production comes
mostly from stripper wells, operators tend to be financially vulnerable and extremely
susceptible to market fluctuations. This situation provides a strong incentive for illegal
dumping, improper abandonment and plugging of wells, and neglected reclamation of drill
sites.
Northern Louisiana's operators, like those in Arkansas, tend to be small to
midsized independents. They share the same economic vulnerabilities and incentives for
noncompliance with environmental procedures. In addition, however, Louisiana's more
marginal operations may be particularly stressed by the new Rule 29B, which requires
close of all onsite produced water disposal pits by 1989. Estimated closing costs per pit is
$20,000.
Operators in southern Louisiana tend to be major companies and large
independents. They are less susceptible to fluctuating market conditions in the short term,
and more likely to be more responsible in discharging their environmental responsibilities.
On the other hand, projects in the south are larger than in the north and are located in more
sensitive areas.
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Environmental and Development Context
The Louisiana Gulf Coast is composed mostly of wetland. Surface material is
usually highly porous. Although unlined brine pits will not be allowed after 1989 under
the State's new rule (29B), the use of unlined reserve pits is still accepted.
Major Issues
Groundwater Contamination from Unlined Brine Disposal and
Reserve Pits
Unlined brine disposal pits have been used in Louisiana for many years, and are
only now being phased out under Rule 29B. Past practice has, however, resulted in
damages both to groundwater and to human health.
In 1982, suit was brought on behalf of Dudley Romero et al. against operators
of an oil waste commercial disposal facility run by PAB Oil Co. The plaintiffs
complained that their groundwater wells were contaminated by wastes dumped into open
pits in the PAB Oil Co. facility, rendered them unusable. Oil field wastes are dumped
into the waste pits for skiming and separation of oil from the remaining oil field wastes.
The pits are unlined but meet the State impermeability standards. The plaintiffs water
wells are downgradient, drilled to depths of 300'-500'. Problems with water wells dates
from 1979. Extensive analysis on the probability of well contamination coming from
PAB Oil Co. site. There was also analysis on surface soil contamination. Soil Testing
Engineers, Inc. determined that it was hypothetically possible for the wastes in PAB Oil
Co. pits to reach and contaminate Romero's water wells. Surface sampling around
perimeter of PAB Oil Co. site found high concentrations of metals. Resistivity testing
showed that plumes from the pits did lead to the water well. Borings that determined the
substrata makeup suggested that it would be possible for wastes to contaminate the
Romero groundwater within the time that the facility has been in operation "if the
integrity of the clay cap has been lost (as by deep excavation somewhere within it)." The
pit was 12' deep and within range to percolate into the water bearing sandy soil and
capable of migrating to the aquifer within the time of facility operation. Plaintiffs
complained of sickness, nausea and dizzyness, and a loss of cattle. (LA 67)
The ground in this area is unusually porous, allowing pits to leak quickly and
wastes to migrate relatively rapidly. Waste constituents potentially leaching into ground
water from unlined pits include arsenic, cadmium, chromium, copper, lead, nickel, zinc,
and chlorides.
Claude H. Gooch and Patricia Richard Gooch filed suit against Conoco, Inc.,
seeking damages of $934,000 for damages caused by the blowout of a gas well that was
previously plugged and abandoned. The blowout sent gas through fault zones to the land
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surface, where it could be ignited by a match held to the ground. The gas was also
determined to be a potential hazard for contamination of drinking water wells in the
immediate area, as well as in the residents' home, where gas accumulation could reach
such a level that it could explode. (LA 87)
Use of Hazardous Chemicals in Workover Operations
Workover operations may require the use of chemical solvents to disolve and clean
bore holes in order to maintain well productivity. The workover fluid wastes come under
the State's classification as a Nonhazardous Oilfield Waste (NOW) and, therefore, is
exempt from the handling and disposal requirements for Louisiana's hazardous wastes.
Despite this classification, workover wastes often contain constituents that are both acutely
and chronically toxic to humans. Exposure to these chamicals, such as carbon disulfide,
can cause severe health damage to the exposed individual.
Carbon disulfide is classified as a hazardous waste under the Federal Resource
Conservation and Revcovery Act because of its danger to human health. Yet, like the
Federal government, Louisiana treats wastes from oilfield operations differently regardless
of whether there are hazardous constituents in the oilfield waste stream. Louisiana has
determined carbon disulfide to be nonhazardous when it is a constituent of a waste stream
from oilfield operations. This chemical has both acute and chronic toxic effects and can
cause severe health problems to persons who are exposed, especially those who are not
properly protected from contact.
Kirk Cormier, while working for BM Oil Company, was regularly exposed over
a three year period (1983-86) to the chemical solvent carbon disulfide during workover
operations. Carbon disulfide was used to remove parafin in order to clean the bore hole.
During this period Mr. Cormier, without any protective gear (including respirators,
gloves, protective clothing or shoes) handled carbon disulfide. Mr. Cormier would often
be standing in "pools" of the workover fluid as it was being poured down the well.
Purged workover fluid as a Nonhazardous Oilfield Waste (NOW) was dumped onto the site
where Mr. Cormier worked adding to the dangerous liquid he was exposed to.
Neurologists believe Mr. Cormier has begun to exhibit the common symptoms
of carbon disulfide poisoning identified with chronic exposure to the chemical. Most
apparent are the symptoms affecting his nervous system and brain such as severe mood
swings (irritability and manic depression) and loss of motor coordination. (LA 105)
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Allowable Discharge of Drilling Mud Into Gulf Coast Estuaries
Under existing Louisiana regulations, drilling muds from onshore operations may
be discharged into estuaries of the Gulf of Mexico. These estuaries are often valuable
commercial fishing grounds. Since the muds can contain high levels of toxic metals,
bioaccumulation of these metals in shellfish or finfish can cause significant potential human
health threats:
In 1984, the Glendale Drilling Co. was drilling from a barge at the intersection
of Taylor's Bayou and Cros Bayou, and discharging drilling cuttings and mud into the
bayou adjacent to and active oyster harvesting area and State oyster seeding area. At time
of discharge oyster harvests were in progress. The Water Pollution Control Division
inspector noted that there were two separate discharges occuring from the barge and a low
mound of mud was protruding from the surface of the water beneath one of the discharges.
Woods Petroleum had a letter from the Louisiana Department of Environmental Quality
authorizing them to discharge the drilling cuttings. While no damage was noted at time
of inspection, there was great concern expressed by the Louisiana Oyster Growers
Association, the Louisiana Department of Wildlife and Fisheries, Seafood Division and
some parts of the Department of Water Pollution Control Division of the Department of
Environmental Quality that the discharge of muds and cuttings with high content of
metals may have long term impact on the adjacent commercial oyster fields and the State
oyster seed fields in nearby Junop Bay. Metals precipitate from the discharge, settling in
progressively higher concentrations in the bayou sediments where the oysters mature.
The bioaccumulation of these metals by the oysters can have an adverse impact on the
oyster population and could also lead to human health problems if contaminated oysters
are consumed. The Department decided in this case to direct the oil company to stop the
discharge of drilling cuttings and muds into the bayou, such practices are usually allowed
and can be terminated only on a case-by-case basis. In this case, Department of
Environmental Quality ordered that a drilling cutting barge be used to contain the
remainder of the drilling cuttings. The Company was not ordered to clean up the mound
of drilling cuttings that they had already deposited in the bayou. (LA 20)
Despite the potential for human health impacts, there is no initiative under way as of
this time to curtail this practice on a general basis. The alternative would be to require
every offshore drilling barge to use a closed mud containment system, with all wastes
contained in onboard tanks. This would, however, be significantly more costly.
Illegal Dumping In the Louisiana Gulf Coast Area
By far the majority of damage cases recorded in the Louisiana involve illegal
dumping or inadequate facilities for containment of wastes generated by operations on the
Gulf Coast. Damage can be extensive:
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Two Louisiana inspectors inspected a swamp adjacent to KEDCO Oil Co.
facility to assess flora damage based on a Notice of Violation issued to KEDCO 3/13/81,
and WPC Log #2-8-81-21. LA 38 described the KEDCO facility and the type of damage
that had prompted the Department of Natural Resources, to issue Notice of Violation.
The damage was, in part, due to a pipe protruding from the pit levee to discharge brine
into adjacent canal which emptied into cypress swamp. The discharge of brine had
probably been occuring for some time due to the amount of harm to the trees in the
cypress swamp. Analysis of a sample collected by a Mr. Martin, the complainant who
expressed concern over the brine discharge into the canal he used to obtain water for his
crawfish pond, showed salinity levels of 32,000 ppm. To assess the damage the
inspectors on April 15, 1981 made an effort to measure the extent of damage to the trees
in the cypress swamp. After surveying the size of the swamp they randomly selected a
compass bearing and surveyed a transect measuring 200'X20' through the swamp. They
counted and then classified all trees in the area according to the degree of harm they were
suffering. Inspectors found that in the swamp that they surveyed "...an approximate total
area of 4,088 acres of swamp was severely damaged." Within the randomly selected
transect, they classified all trees according to the degree of harm. Out of a total of 105
trees, 73 percent were dead, 18 percent were stressed, and only 9 percent were living. The
inspectors' report noted that "although the transect ran through a heavily damaged area,
there were other areas much more severly impacted. Therefore, it [was] concluded, based
on the data collected and firsthand observation, that the [percentages of damaged trees
recorded]...are a representative, if not conservative, estimate of damage over the entire
affected area" (LA 45)
Most of the damage incidents collected involved small operations run by
independent companies. Some incidents, however, involved major oil companies:
Exxon Co. USA, operates its Common Tank Battery #1 at the Deer Island Oil
anda Gas Field, in a fresh water marsh. Four different inspections were made in 1986 in
regard to the discharge of wastes from the pit levee and other areas of site. A May 1986
inspection had noted problems with runoff from the site platform into the bayou. While
this appeared to be repaired by the time of the August inspection, there were still
problems with greasy, rust sludge from the high and low pressure separator and glycol
tower and circulating pump, which posed a potential runoff problem. There were also
indications of discharge from several pits. Final inspection (10/16/86) indicated that
while some of the oil contaminates had been cleaned from the surface surrounding the
pits, there was still oil in puddles around the site. The inspector noted contaminated
sediment and other surface damage to flora in the area. Stained soil with oily wastes and
produced water discharged into the freshwater marsh were having an adverse effect on the
flora in the area. The inspector also noted that there was an "area void of living
vegetation," and that the area is "incapable of supporting vegatation due to contamination
from oil, brine or possibly other contaminants." (LA 07)
Some documented cases include detailed descriptions of damage to agricultural
crops:
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Dr. Wilma Subra analyzed sugar cane fields adjacent to a production site (which
included a saltwater disposal well) in New Iberia Parish run by D.T. Caffery. The
analysis was conducted between July of 1985 and November of 1986, and included reports
of salt concentrations at various locations in the sugar cane fields along with descriptions
of accompanying damage. The site had various areas that were barren and contained what
appeared to be sludge. The facility is up gradient from the sugar cane fields and it was
surmised that the salt brine was discharged onto the soil surface and that the plume spread
downgradient, thereby affecting the sugar cane fields. In July 1985 Dr. Subra noted that
the cane field, though in bad condition, was predominately covered with sugar cane.
There were, however, weeds or barren soil covering a portion of the site. The patch of
weeds and barren soil matched the area of highest salt concentrations, as measured in
November 1986. In the area where the topography suggested brine concentrations would
be lowest, the sugar cane appeared healthy. Field investigation and soil sampling in
November of 1986 found the field to be nearly barren, with practically no sugar cane
growing. Measured concentrations ranged from a low of 1,403 ppm to 35,265 ppm at the
edge of the field adjacent to the oil operation. (LA 64)
Although most of the damage is associated with disposal of brines, other types of
oil field wastes have been known to create significant damage:
Chevco-Kengo Services, Inc. operates a disposal facility near Abbeville LA,
transporting saltwater and other wastes using vacuum trucks.. Following complaints in
1984, an inspection of the site found that a truck washout pit was emptying oil field
wastes into a roadside ditch flowing into nearby coulees. Neighbors were concerned that
such discharge was entering their groundwater supply, damaging their agricultural fields
and crawfish ponds. Civil suit was brought against Chevco-Kengo Services, Inc., asking
for a total of $4 million in property damages, past and future crop loss, and exemplary
damages. Plaintiffs also alleged that there was extensive damage to crawfish, rice, and
human health. Dr. Wilma Subra collected samples of soil and water. High metals
content from the wastes, especially from the area near the facility and in the adjacent rice
fields, indicated a possibility that wastes from the facility were, indeed, the source of the
damage. The case was settled out of court for an undisclosed amount of money. (LA 90)
Illegal Dumping in Arkansas
The majority of damage incidents found in Arkansas are related to chronic illegal
dumping of produced water and oil from production units. Damages typically include
pollution of surface streams with high levels of chlorides and oil, contamination of soil
with high chloride levels and oil, and documented or potential contamination of ground
water with elevated levels of chlorides found in native brines or produced waters, and
damage to vegetation (especially forest and timberland).
An oil production unit operated by Mr. J.C. Langley was discharging oil and
brine in large quantities onto the property of Mr. Melvin Dunn and Mr. W. C. Shaw.
The oil spill caused severe damage to the property, interfered with livestock on the
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property and delayed construction of a planned lake. Mr. Dunn had spoken repeatedly
with a company representative (pumper) operating the facility concerning the oil spill,
but to no avail. Mr. Dunn then hired an attorney in order that corrective action be taken.
Complaint was made to ADPCE, the operator was informed of the situation and the
facility was brought into compliance. However, damage from the spill was not corrected,
and it is not known if the operator cleaned up the damaged property. Property of Mr.
Melvin Dunn and MR. W. C. Shaw was polluted with surface runoff of oil and brine.
Oil and brine runoff from broken and leaking pipes of J. C. Langley's production unit
interfered with their livestock and delayed construction of a planned lake. (AR 07)
On September 20, 1984, a complaint was filed with ADPCE concerning the
discharge of oil and brine in and near Smackover Creek from production units operated by
J. S. Beebe Oil Account. It ws found that saltwater was leaking from a saltwater disposal
well located on the site. Beebe wrote a letter stating willingness to correct the situation.
On November 16, 1984, the site was investigated again, and it was found that pits on
location were now being used as the primary disposal facility; were noe overflowing and
leaking into Smackover Creek. It was noted that the pits were below the river level when
heavy rains occured. One pit was being siphoned over the pit wall, while waste from
another pit was flowing onto the ground through an open pipe. The floors and walls of
the pits were seeping. Beebe was ordered to shut down production, correct the situation
and was fined $10500. It is not known if the fine was collided or if production was
actually shut in. (AR 10)
The State of Arkansas is under severe resource constraints for policing this type of
illegal practice. The situation is made more acute by the lack of authority of several relevant
departments in the State or Federal government to close down violators, even with repeat
offenders.
In 1983 and again in 1985, James M. Roberson, an oil and gas operator, was
given drilling surface access for areas in the Sulphur River Wildlife Management Area
where the surface rights were owned by the Arkansas Game and Fish Commission. Mr.
Roberson repeatedly violated the agreements contained in the surface use permits as well
as State and Federal regulations, allowing for release of oil and brine into the wetland
areas of Sulphur River and Mercer Bayou from a leaking saltwater disposal well and
illegal brine disposal pits. One drill site was wrongfully located in a campground.
Access roads are wider and longer than proposed, disrupting and blocking normal wetland
water circulation patterns. One road was illegally built across a special waterfowl rest
area severely limiting the benefit to migratory waterfowl. Oil and saltwater damage was
documented in the study of area by Hugh A. Johnson, Ph.D. His study mapped chloride
levels around each wellsite and calculated area of damage. The highest chlorides recorded
in the wetlands was 9,000 ppm, native vegetation starts to be stressed from exposure to
250 ppm. Significant areas around each wellsite have dead or stressed vegetation due to
saltwater exposure. Significant damage has been sustained by the Sulphur River Wildlife
Management Area through discharge of oil and brine into the wetlands and construction of
roads, causing restricted water circulation in wetlands. A campground operated by the
SRWMA has been used by the operator as a drillsite, rendering the campground unusable
for recreational purposes. A road built across the Henry Moore III Waterfowl Rest Area
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has limited its effectiveness as a resting and feeding habitat for all species of migratory
waterfowl that winter in Arkansas. It is feared that continued discharges of brine and oil
in this area will threaten the last remaining forest land in the Red River bottoms.
(ARM)
It is assumed that the Arkansas Oil and Gas Commission (AOGC) could shut down
operations like this, but there is an apparent lack of cooperation between the AOGC and
such groups as the Arkansas Game and Fish Commission (AGFC) in these situations (see
also Appendix A: Review of State Laws and Regulations).
Improperly Operated Injection Wells
Improper operation of injection wells raises the potential for long-term damage to
ground-water supplies, as the following case from Arkansas illustrates.
On September 19, 1984, Mr. James Tribble made complaint to Arkansas
Department of Pollution Control and Ecology concerning saltwater which was coming up
out of the ground in his yard, killing his grass and threatening his water well. There are
many oil wells in the area and waterflooding is a common enhanced recovery method at
these wells. Upon inspection of the wells nearest to his residence, it was discovered that
the operator, J. C. McLain, was injecting saltwater into an unpermitted well. The
saltwater was being injected into the casing, not into tubing, where it could migrate into
the freshwater zone. A pit at the same site was near overflowing. On follow-up
inspection, the violations had been corrected. Saltwater being injected into the casing of a
saltwater disposal well migrated into the vacinity of Mr. James Tribble's residence and
came up out of the ground onto his grass. The saltwater killed his grass and, if it
continued to migrate, would contaminate his water well. No fine was levied and no
provision was made for reclaiming damage sustained by Mr. Tribble. (AR 12)
Policing of injection wells is made difficult by lack of State resources; in this
marginally economic oil recovery area, the potential exists for many unreported incidents
similar to that cited above.
Improperly Abandoned and Improperly Plugged Wells
Damage from improperly plugged and abandoned wells is known to occur in
Louisiana.
Crow Farms, Inc., operator of Angelina Planatation, initiated a $7 million civil
suit against operators of active and abandoned oil test wells, oil production wells, and an
injection well, for causing progressive loss of agricultural revenue from brine
contamination to 1.7 square miles of rice, soybeans, and rye. Analysis of site concluded
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that it will take 27 years to restore the soil and a longer period to restore the aquifer. The
40,000 acre farm is 20 miles from Natchez MS. At least seven wells are involved,
including two active oil production wells, both operated by Smith, Wentworth and
Coquina, and five abandoned oil test wells drilled by Hughes & New Oil Co. Extensive
study by Groundwater Water Management, Inc. concluded that Crow Farms, Inc., used
irrigation wells contaminated by brine water from the oil producing formation. This
brine traveled up poorly or improperly plugged wells or down the annulus of producing
wells, leaking into the fresh water aquifer used for irrigation, thereby contaminating the
aquifer with chloride levels beyond the tolerance levels for rice. Extensive testing was
conducted to show that the brine in the aquifer was responsible for damage on the
plantation. This included chemical "fingerprinting" of brines to confirm that brines in the
irrigation water originated as brines in the oil producing formations.
Crow Farms spent in excess of $250,000 to identify the source of the brine
contamination. Records of the case state: "Surface casings may not have been properly
cemented into the Tertiary clays underlying the alluvial fresh water aquifer. If these
casings were not properly cemented, brine could percolate up the outside of these casings
to the fresh water aquifer at an oil or gas well test location where improper abandonment
procedures occurred. Any brine in contact with steel casings will rapidly corrode through
the steel wall thickness gaining communication with the original bore hole." (LA 65)
This case underscores both that brine damage to agricultural lands from improperly
abandoned wells can be extensive, and that the costs of conclusively identifying the source
of contamination are large. Policing of newly abandoned wells and the discovery of older
leaking wells is made extremely difficult because of shortages of both enforcement funds
and manpower at the State level.
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ZONE 5
Zone 5 includes the Michigan, Ohio, Iowa, Indiana, Wisconsin, Illinois, and
Missouri. Damage cases were investigated in Michigan and Ohio.
Operations
Michigan produces both oil and gas from limestone reef formations at sites scattered
throughout the State at a depth of 4,000 to 6,000 feet. Oil and gas development is
relatively new in this area, and most production is primary (that is, as yet it involves no
enhanced or secondary recovery, such as waterflooding). Exploration in Michigan
possibly the most intense currently under way anywhere in the country. The average depth
of new wells drilled in 1985 was 4,799 feet. In that year 863 wells were completed, 441
exploration wells.
By contrast, Ohio has far less exploration. It produces gas and some oil primarily
from mature production areas in the eastern portion of the State. Activity is developmental
rather than exploratory, with only 78 exploratory wells drilled in 1985 out of a total of
6,297 wells completed. The average depth of a new well in 1985 was 3,760 feet.
Types of Operators
Operators in Michigan include everything from small independent companies to the
major oil companies. In Ohio, operators are mostly small to mid-sized independents, but
some major companies still hold significant leases.
Major Issues
Groundwater Pollution in Michigan
All the damage cases gathered in Michigan are based on case studies written by the
Michigan Geological Survey, which regulates oil and gas operations in the State. All these
cases deal with ground water pollution. While the State has documented damages in all
cases, sources of damages are not always evident. Usually several potential sources of
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contamination are listed and the plume of contamination is defined by monitoring wells.
Documented damage has occurred because of the use of unlined reserve or disposal pits,
but most of the cases involve disposal of produced waters.
Often, however, characterization of the brine and pollution constituents can be done
using so-called "stiff diagrams" (elsewhere referred to as "fingerprinting") to prove that
oilfield brine was the source of contamination. For example:
In June 1983, a water well owned by Mrs. Geneva Brown was tested after she
had filed a complaint to the Michigan Geological Survey. The test results showed
chloride concentration of 490 ppm. Subsequent sampling from a neighbor's water well,
Mrs. Dodder, in August showed that her well measured 760 ppm chloride. There are total
of 15 wells in the area surrounding the contaminated water wells. Only five of the wells
are still producing, recovering a combination of oil and brine out of the Dundee
Limestone. The brine is separated from the crude oil on site and disposed of back into the
producing formation through the F. & L. Leach #1 Brine Disposal Well. The source of
the pollution was evidently the H.E. Trope, Inc. crude separating facilities and brine
storage tanks located upgradient from the contaminated water wells. Monitoring wells
were installed to confirm the source of the contamination. Sample results located two
plumes of chloride contamination ranging in concentration from 550 to 1,800 ppm that
were traveling on a southeasterly direction downgradient from the brine storage tanks and
crude separator facilities owned by H.E. Tope. The plumes have already reached the
several of the monitor wells and contaminated the residences well of G. Brown and M.
Todder on 155th St. Stiff diagrams were used to confirm the similarity of the
constituents of the formation brine and the chloride contamination of the affected water
wells. (MI 05)
Ground-water contamination in the State has also been caused by injection wells;
the same stiff diagrams can be used to confirm the origins of brines in these cases as well,
as shown by the following case.
In April 1980, residents of Green Ridge Subdivision, located in Section 15,
Laketon Township in Muskegon County, complained of bad tasting water from their
water wells. Well were sampled by the local health department revealed elevated chloride
concentration in some wells. Because of the close proximity of the Laketon Oil Field, an
investigation was started by the Michigan Geological Survey. The Laketon Oil Field
consist of dry holes, producing oil wells, and a brine disposal well (Harris Oil Corp.
Lappo #1PN 26328). Oil wells produce from the Traverse-Dundee Limestone and produce
a mixture of oil and brine. The brine is separated and disposed, by gravity, back into the
producing formation. After reviewing monitor well and electrical resistivity survey data,
it was concluded that the source of the contamination was the Harris Oil Corp. Lappo #1
brine disposal well. (MI 06)
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Significant damage to ground water under the drill site can occur even where
operators take special precautions for drilling near residential areas.
Drilling operations at the Burke Unit #1, permit #30080, caused the temporary
contamination of two domestic water wells, and longer-lasting contamination of a third
well closer to the drilling site. The operation was carried out in accordance with State
regulations and special site restrictions required for urban areas, including Rig engines
equipped with mufflers, steel mud tanks for drilling wastes, lining of earthen pits that
may contain salt water and the placement of a conductor casing to a depth of 120 feet to
isolate the well from the fresh water zone beneath the rig. The contamination resulted
from the handling of highy concentrated brine at the drilling location. The location is
underlain by permeable surface sand and with bedrock depth at less than fifty feet. The
contamination occured when a working pit used to contain the material flushed from the
mud tanks and the cuttings remained in the unlined pit for 13 days before removal. This
allowed sufficient time for contaminants to migrate into the fresh water aquifer. The
source of contamination was the working pit for Burke #1 oil well or a leak of unknown
size from the tank battery. When the Burke #1 well was completed, the mud tanks were
flushed into the working pit. Seepage may have occured through the lined pit bottoms and
sidewalls during the 13 day period before mud and cuttings were removed. Also a leak
from the brine storage tank was reported to have occured before the contamination was
detected in the water wells. One shallow well was less than 100 feet directly east of the
drilling pit area and 100 to 150 feet southeast of the brine leak site. Chloride
concentrations in this well measured from 750 (9/5/75) to 1,325 (5/23/75) ppm. By late
August, two of the wells had returned to normal while the third well still measured 28
times its original background concentration. (MI 04)
Illegal Dumping of Wastes in Ohio
Ohio is making an aggressive effort to gain compliance from oil and gas operators
and is trying to maintain complete and up-to-date records. The State has recently banned all
saltwater disposal pits; overall, there is substantial support for an active oil and gas
compliance effort.
Illegal dumping is, however, a significant problem in Ohio, as elsewhere. There
are still instances of deliberate illegal disposal practices.
Kemgas, Inc., was fracturing a production well (well #95) when the well blew
out. The well was allowed to blow or vent for 12 1/2 hours, discharging oil drilling
mud, fracing fluid, brine, and gas. Since the area had been previously reclaimed, there
was no pit to contain the waste, so it spilled over the well site and into the adjacent creek
(Little Sandy Creek). The field inspector for DNR noted oil stains along 2 1/2 miles and
a fish kill along 1/2 mile of Little Sandy Creek. (OH 01)
Cases of similar disregard for rules is seen in relation to brine disposal:
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Equity Oil & Gas Funds, Inc., operates well #1 at Engle Lease, Howard
Township, Knox Co. An Ohio DNR official inspected the site on April 5, 1985. He
found no saltwater storage tank or vault, and high concentrations of brine were being
discharged from a plastic hose leading from tank battery into a culvert that emptied into a
creek. The inspector took photos and samples. Both brine and oil and grease levels were
of sufficient magnitude to cause damage to flora and fauna. The inspector noted that a
large extent of soil along the culvert had been contaminated with oil brine. The
suspension order indicated that the "violations present an imminent danger to public
health and safety and are likely to result in immediate and substantial damage to natural
resources." The operator was required to "restore the disturbed land surface and remove the
oil from the stream in accordance with Section 1509.072 of ORS..." (OH 07}
In another case:
Zenith Oil & Gas Co. operated Well #1 in Hopewell Township. Zenith was
issued a suspension order in March of 1984 after inspectors discovered brine discharges
onto the surrounding site from a pit breech and pipe leading from the pit. A Notice of
Violation had been issued in February 1984, but the violations were still in effect
3/20/84. An inspection of an adjacent site also operated by Zenith Oil & Gas Co.
discovered a plastic hose extending from one of the tank batteries discharging brine into a
breeched pit and onto the site surface. Another tank was discharging brine from an open
valve directly onto the site surface. In both cases it was apparent that brine discharges
were bineg willfully released. Not only was there concern for the high concentration of
chloride in the brine but there was also concern for the lead which was nearly 2 1/2 times
and mercury which was 925 times the EPA drinking water standards. The suspension
order stated that the discharge was, "...causing contamination and pollution..." to the
surface and subsurface soil and in order to remedy the problem the operator would have to
restore the "disturbed" land. (OH 12)
Despite Ohio's intensive effort to control illegal disposal, the State's compliance
budget is limited, and officials expect illegal disposal practices to continue. The problem is
made more acute by the current low price of oil and the marginal nature of many oil and gas
operations in the State.
Contamination of Ground Water From Injection and Annular Disposal
Unlike most States, Ohio still allows annular disposal of brine or produced waters.
This practice is not allowed in other States because of its potential for ground water
contamination; high chloride contents tend to corrode casings, creating holes that allow
migration of waste brine into ground water. To avoid this, Ohio requires the operator to
conduct radioactive tracer surveys to determine if brine is actually being deposited in the
correct formations. Tracer surveys are more expensive than conventional mechanical
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integrity tests; only 2 percent of all tracer surveys were actually witnessed by inspectors, as
required, in 1985.
Failures of permitted annular disposal operations commonly occur because of
corrosion of the casing.
The Donofrio well (permit #3642) is a production oil well with an annular
disposal hookup fed by a 100 bbl brine storage tank. In December, 1975, shortly after
completion of the well, contamination of the Donofrio residential water well was
reported. One month after the well contamination was reported, several springs on the
Donofrio property showed contamination from brine and oil. On January 8,1976, OEPA
investigated the site and reported evidence of oil overflow, lack of diking, and the presence
of several brine storage pits. Nine years after the first report of contamination, a court
order to disconnect the annular disposal lines and to plug of the well was issued. In April
1986, the casing recovered from the annular disposal well showed that its condition ranged
from fair to very poor. The casing appeared to be thin in several places and to have a lot
of rust and scale. Six holes were found in the casing. The disposal well was then
plugged. (OH 38)
The alternative to annular disposal is underground injection in Class n wells, which
operate under Federal guidelines and standards. Class II disposal is, however, more
expensive than annular disposal; because many of the State's operatorions are economically
marginal, a change in requirements would be difficult to police.
Contamination of Ground Water From Reserve Pits
Ohio does not have a statewide rule to require liners in reserve pits. Liners have
recently been required on a case-by-case basis in the northeastern portion of the State,
where freshwater aquifers are overlain with higly permeable material, and are therefore
especially vulnerable. Damage case incidents resulting from unlined reserve pits, with
subsequent migration of contaminants into ground water, are scattered throughout the
State.
An unnamed oil and gas company contaminated the well that served a house and
bam owned by Mr. Bean, who uses water for his dairy operations. When barium was
found in the well water, the Ohio Department of Agriculture documented that wells
supplying water for domestic and dairy use became contaminated from oil field waste in
October of 1982. Water samples from Mr. Bean's well show concentrations of chlorides,
barium, iron, sodium, and other residues above the USEPA's Secondary Drinking Water
Standards. Milk produced at the Bean farm was found to contain high levels of barium at
0.63 mg/1 A new well was drilled, but it also became contaminated. In September 1984,
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Mr. Bean's water wells were still showing signs of contamination from the same oilfield
wastes. (OH 49)
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ZONE 6
Zone 6 includes North and South Dakota, Nebraska, and Kansas. All of these
States have oil and gas production, but for this study Kansas was the only State visited for
damage case collection. Discussion is limited to that State.
Operations
Kansas has two principal hydrocarbon production areas. The first is the Giant
Hugoton gas field in the southwest corner of the State (also known as the Panhandle
Region), one of the largest gas fields in the world. Most production in this field is from
mature areas. Recent reductions in spacing requirements for wells have increased well
density in the field, with a subsequent increase in developmental drilling activity. There
has also been some recent exploration of deeper horizons in the Hugoton area, where oil
deposits have been found.
The second area of Kansas' production is in mid- to eastern Kansas, where spotty
marginal stripper operations produce high ratios of produced water to oil.
The average depth of a new well drilled in Kansas in 1985 was 3,770 feet. Six
thousand twenty-five (6,025) new wells were completed in that year, and 1,694
exploratory wells were drilled.
Types of Operators
Operators in Kansas include the full range of companies, from the majors to small
independents. The Hugoton area is dominated by mid-sized to large independents. Spotty
oil production in the mid to eastern portion of the State is dominated by small independent
producers.
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Environmental and Development Context
The southern portion of Zone 6 is underlain by limestone, shale, sandstone,
conglomerate, siltstone, and coal. Kansas has large expanses of agricultural land; the west
portion of the State is relatively flat, the east and southeast are gently rolling. Native
vegetation consists of grasslands, with some shrub and grassland combined.
With the exception of a few major metropolitan centers, the State is only sparsely
populated. For this reason, discovery and documentation of damages from oil and gas
activities is difficult.
Kansas contains several special groundwater management districts. These have
been set up to more intensively manage the vital and vulnerable ground-water resources, so
important to the agriculture industry. Oil and gas activities are partially responsible for the
historic degradation of ground-water resources in these districts. In the Burtton
Groundwater Management District, for example, portions of the ground water contain
2,000 to 4,000 ppm chlorides.
In response to the ground-water degradation problem, the Kansas Corporation
Commission has a "Lease Maintenance" section of rules governing oil and gas activities.
These spell out good housekeeping practices for drilling sites, along with penalties for their
violation. "Lease Maintenance" rules are implemented to minimize impacts to groundwater
from brine spills associated with production activity.
According to officials from the Kansas Department of Health and the Environment,
the use of liners for reserve pits is necessary for ground water protection in the western
third of the State, where the Ogallala aquifer is vulnerable, and in the central section, where
the Arkansas River flows.
The majority of surface landowners in Kansas own their land's mineral rights as
well.
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Major Issues
Poor Lease Maintenance
There have been documents instances in Kansas of damage associated with poor
lease maintenance and use of illegal pits. These commonly result in contamination of soil
and surface water with high levels of chlorides as well as long-term pollution of ground
water with chlorides.
Temple Oil Company and Wayside Production Company operate a number of oil
production leases in Montgomery County. The leases were operated using illegal salt
water containment ponds, improperly abandoned reserve pits, unapproved emergency salt
water pits,and improperly abandoned salt water pits. In addition, operation of the sites
was generally very sloppy resulting in numerous oil and saltwater spills. Documentation
of these incidents starts in 1977 when adjacent landowners began to complain about soil
pollution, vegetation kills, fish kills and pollution of freshwater streams due to oil and
saltwater runoff from these sites. Complaints were received by the Conservation
Division, Kansas Department of Health and the Environment, Montgomery County
sheriff and Kansas Fish and Game. A total of 39 violations on these leases were
documented between 1983-1984. Private landowners filed complaints as early as 1981.
The leases also contain a large number of abandoned, unplugged wells, posing a threat to
ground water. Water sampled from a 4 1/2 foot test hole between a freshwater pond and
creek on the Fowler's lease showed ground water with Cl cone, of 65,500 ppm. Water
samples taken from pits on the owner's leases (the Fowler's and others) showed Cl cone.
ranging from 5,000 to 82,000 ppm. The Kansas Corporation Commission made an
administrative order in 1984, fining Temple and Wayside a total of $80,000. Only
$25,000 was collected and the operators could reapply for licenses to operate in Kansas in
36 months. It took the KCC at least five years to bring an end to the blatant disregard for
the rules and regulations governing oil and gas operations in Kansas. In five years,
significant environmental damage was sustained by the areas near these leases. (KS 01)
On January 31, 1986, the Kansas Department of Health and the Environment
inspected the Reitz lease in Montgomery County, operated by Marvin Harr of El Dorado,
Arkansas. The lease contained an unpermitted emergency pond, containing water which
had 56,500 ppm chlorides. A large leaking area was observed on the south side of the
pond, allowing the flow of salt water down the slope for about 30 feet. The company
was notified and asked to apply for a permit and install a liner as the pond was constructed
of sandy clay and sandstone. The operator was directed to immediately empty the pond
and backfill if a liner were not installed. On Feb. 24 the lease was reinspected and the
emergency pond was still full and actively leaking. It appeared that the lease had been
shut down. A "pond order" was issued requiring the company to drain and backfill the
pond. On April 29, the pond was still full and leaking. A fine of $500 was imposed and
it was ordered that the pond be drained and backfilled. Water samples from pit show Cl
concentrations of from 30,500 ppm (4/29/86) to 56,500 ppm (1/31/86). Leakage from the
pit showed chloride concentrations of 17,500 ppm (2/24/86). The Kansas Department of
Health and the Environment stated that "...the use of the pond,...has caused or is likely to
cause pollution to the soil and the waters of the State. (KS 08)
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Such incidents are a recognized problem in Kansas; as noted above, recently the
Kansas Corporation Commission added new "lease maintenance" rules in their oil and gas
regulations. The question of concern is how stringently these rules will be enforced,
especially, as these cases show, in the light of the evident reluctance of some operators to
comply even when faced with repeated orders for corrections. Smaller operators appear to
be the most reluctant to comply.
Pollution of Ground Water with Chlorides from Improperly
Abandoned Wells and Reserve Pits
Chloride pollution of ground water is a pervasive problem in Kansas, and has been
for a long time. It results in large part from improperly plugged and abandoned wells and
reserve pits. Damage can be extensive.
At the Gary Leslie farm, considerable salt pollution of groundwater is evident.
Natural springs on the farm have become salty, causing vegetation kills and salt pollution
of soil. Located on the farm is the Leslie #1, a well drilled by Western Drilling Inc. The
Leslies believe this well to be the source of salt pollution of their groundwater because
some days after plugging, the top plug slipped an unknown distance downhole. After
slippage a rock was dropped downhole and a splash was heard some seconds later.
Another possible source is the abandoned reserve pit used to drill the Leslie #1, as drilling
in this area requires penetration of the Hutchinson Salt member, during which 200 to 400
cubic feet of rock salt is dissolved and discharged into the reserve pit. The ground in the
area consists of highly unconsolidated soils which would allow migration of pollutants
into the groundwater. The Leslies were not provided relief by the Kansas Corporation
Commission (KCC), so they filed suit in civil court, and won their case for a total of
$11,000 from the oil and gas operators for damages sustained to the groundwater.
Saltwater at the top of the Leslie #1 had conductivity of 5,050 umhos. Conductivity of
spring water equaled 7,250 umhos. "Very saline water" was noted by the KCC as
coming out of the springs. It was also noted that conductivity of 2,000 nmhos will
damage soil, precluding growth of vegetation. (KS 03)
Problems also occur when improperly plugged wells are located in areas being
developed as secondary recovery projects. After pressuring the formation for secondary
recovery, brine can migrate up improperly plugged wells, causing extensive ground water
pollution.
In 1961, Gulf and its predecessors began secondary flooding operations in the
East Gladys Unit in Sedgwick County. During secondary recovery, water is pumped into
a target formation at high pressure, enhancing oil production. This pumping of water
pressurizes the formation, allowing for brine to come to the surface through unplugged or
improperly plugged abandoned wells. When Gulf began their secondary recovery in this
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area, it was with the knowledge that a number of abandoned wells existed and could lead
to escape of saltwater into groundwater. Three improperly plugged wells in close
proximity to the Gladys unit were the source of groundwater pollution resulting in the
destruction of fresh groundwater on the property of Gerald Blood who runs a peach orchard
in the area. The saltwater forced up through the pressuring of the Gladys field flowed into
the unplugged wells and into the groundwater below the surface. Salt water gradually
migrated into the groundwater from which he draws irrigation water and water for his
residence. Pollution of irrigation wells was first noted by Gerald Blood when in 1970, a
truck garden was killed by irrigation with salty water. As the pollution continued to
migrate in the aquifer, it contaminated two more irrigation wells in the mid-1970s. By
1980, the pollution had contaminated the irrigation wells used to irrigate a whole section
of Mr. Blood's land and adjacent landowners began to have saltwater pollution in their
wells at this time. Mr. Blood lost a number of peach trees as a result of the
contamination of his irrigation well, and lost the use of his domestic well. (KS 14)
Problems with abandoned reserve pits are illustrated in the following case.
Between February 9 and 27, the Elliott#l was drilled on the property of Mr.
Lawrence Koehling. While drilling, the Hutchinson Salt member was penetrated,
dissolving 100-200 cubic feet of salt which was disposed of in the reserve pit. The
reserve pit lies 200 feet away from a well used by Mr. Koehling for his ranching
operations. Within a few weeks of the drilling of the Elliott #1, Mr. Koehling's nearby
well began to pump water containing the saltwater drilling fluid. As confirmed by the
KCC, the saltwater plume would eventually pollute the Koehling's domestic water well
and the water wells on a farmstead over a mUe downstream. The drilling company was
not fined for pollution of groundwater, and Mr. Koehling received no compensation for
damages sustained. Water samples from the Koehling livestock water well show chloride
concentrations of 900 and 950 ppm. Background concentrations of chloride would be in
the range of 100-150 ppm. Due to the seepage of reserve pit fluids containing high levels
of salt, the groundwater on the Koehling ranch has been polluted with salts, chlorides
reaching 950 ppm in the freshwater aquifer. It is anticipated by the KCC that the
saltwater plume will continue moving, thus polluting the Koehling domestic water well
and the water well utilized by a farmstead over one mile downstream from the Koehling
ranch. It is also stated by the KCC that other wells drilled in the area using unlined
reserve pits would have similarly affected the groundwater. (KS 05)
Problems with Injection Wells
Injection is one of the most important methods of disposal for brines in Kansas and
elsewhere. Proper design and maintenance of injection facilities is therefore highly
important. If injection wells are allowed to be constructed in unsuitable formations,
damages can resulted.
In the Smolan-Salemsburg area, 44 injection wells were injecting into the
Hutchinson Salt Member of the Wellington Formation, commonly called the Lost
Circulation Zone. Through injection of oilfield brine, this salt member was being
dissolved. As a result, highly salty water was intruding into the Smokey Hill River
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through outcropings, making it unusable during low-flow stages, and the Wellington
aquifer has sustained significant salt contamination. The Smokey Hill River is the water
supply source for several communities in northeast Kansas. Several residents in the area
have lost their domestic water wells due to the salt pollution, and have lost trees and
plants as a result of irrigating with the salty water. The dissolving of the salt member
also caused subsidence and sinkholes to appear in the area, creating the potential for
further collapse of subsurface. In 1983-1984, the KCC ordered that injection into the
Hutchinson Salt Member be discontinued. Exemptions were granted to several operators
for the continuance of injection into the salt formation. (KS 04)
Problems also occur as a result of improper testing and maintenance, as illustrated
by the following case.
On July 12, 1981, the Topeka KDHE received a complaint from Albert
Richmeier, a landowner operating an irrigation well in the South Solomon River valley.
His irrigation well had encountered salty water. An irrigation well belonging to an
adjacent landowner, L. M. Paxson, had become salty in the fall of 1980. Oil has been
produced in the area since 1952, and since 1962, secondary recovery has been used. Upon
investigation by the Kansas Department of Health and the Environment (KDHE), it was
discovered that the cause of the pollution was a saltwater injection well nearby. Upon
receipt of the saltwater complaint, a casing profile caliper log was run which revealed
numerous holes in the casing of the injection well. The producing formation, the Kansas
City-Lansing, requires as much as 800 psi at the wellhead to inject the brine to create a
profitable enhanced oil recovery project. After attempts at repair, the operator, Petro-
Lewis, decided to plug the well. (KS 06)
Both of these cases illustrate generic problems of the UIC program as delegated to
any State. These cases, however, suggest that inspection and enforcement resources are
needed.
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ZONE 7
Zone 7 includes Oklahoma and Texas, both being large producers of oil and gas.
As of December 1986, Texas ranked as the number one producer in the U.S. among all oil
producing States. Due to scheduling constraints, research on this zone concentrated on
Texas, and most of the damage cases available come from that State.
Operations
Oil operations in Texas and Oklahoma began in the 1860s and are among the most
mature and extensively developed in the U.S. These two States include virtually all types
of operations, from large scale exploratory projects and enhanced recovery projects to
marginal small scale stripper operations. In fact, Zone 7 includes the great majority of the
country's stripper well production. Because of their maturity, many operations in the area
generate significant quantities of associated produced water.
Although the zone is heavily affected by current price declines, development
remains active. In 1985, 9,176 new wells were completed in Oklahoma, along with 385
exploration wells. In Texas in the same year, 25,721 wells were completed on shore,
along with 3,973 exploration wells. The average depth of wells in the two areas is
comparable: Oklahoma 4,752 feet; Texas, 4,877 feet. Because the scale and character of
operations varies so widely, cases of environmental damage from this zone are numerous
and varied, and are not limited to any particular type of operation.
Types of Operators
Major operators are the principal players in exploration and development of deep
frontiers and capital-intensive secondary and tertiary recovery projects. As elsewhere, the
major companies have the best record of compliance with environmental requirements of all
types; they are least likely to cut corners on operations, tend to use high quality materials
and methods when drilling, and are generally responsible in handling well abandonment
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obligations. On the other hand, the scale and technical difficulty of their operations may
mean that their projects pose considerable potential for environmental damage.
Smaller independent operators in the zone have a significantly poorer environmental
record. Being more susceptible to fluctuating market conditions, they may have a greater
incentive to compromise environmental performance in the interest of maintaining
profitability. They may lack sufficient capital to purchase first quality materials and employ
best available operation methods. Smaller operators are more likely than the majors to
neglect abandonment obligations.
Environmental and Development Context
This zone is large and thinly populated. Much of the population is in rural areas.
Many oil and gas production sites are located in remote areas that are physically difficult to
reach, making inspection and enforcement difficult.
The West Texas Permian Basin area has limited fresh water resources, and as a
result is particularly vulnerable to adverse impacts of groundwater and surface water
pollution associated with improperly plugged abandoned wells.
The Texas Gulf Coast, another significant production area, is a wetlands area with
extensive wildlife—shore birds and aquatic life. Disposal of brine and drilling fluids
directly into tidally affected estuaries and bays is legal, increasing the potential for adverse
impacts on environmental resources.
Landowners have control over mineral rights in about 50 percent of the privately
owned land in the zone. Surface and mineral rights are severed in the remaining 50
percent. Since the zone has been dependent on oil and gas development for a significant
percentage of its economic growth and stability for such a long time (since the nineteenth
century), residents of the zone have become accustomed to the environmental problems
associated with oil and gas development, and appear, in many cases, to be willing to
tolerate a certain level of adverse environmental impacts. In addition, since such a large
proportion of the population is employed, directly or indirectly, by the oil industry, there is
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a widely-acknowledged reluctance to complain about environmental damage. On the one
hand there is fear of job-related reprisals, on the other there is frustration and a certain
cynicism about actions being taken against firmly-entrenched economic interests.
Major Issues
Discharge of produced water and drilling mud into bays and estuaries
of the Texas Gulf Coast
Texas allows the discharge of brine and muds into tidally-affected estuaries and
bays of the Gulf Coast from nearby onshore development. This practice has, however,
produced cases of environmental damage both from discharges that are legal under Texas
Railroad Commission rules as well as from discharges that appear to be inconsistent with
TRC rules.
Cases in which legal discharges have created damage include:
In Texas, oil and gas producers operating near the Gulf Coast are permitted to
discharge produced brine into surface streams if they are found to be tidally affected.
Along with the brine, other chemicals and organic constituents are discharged, including
lead, zinc, chromium, barium, and may contain water soluble polycyclic aromatic
hydrocarbons or PAH's which are known to accumulate in sediment producing liver and
lip tumors in catfish and affect mixed function oxidase systems of mammals, rendering a
reduced immune response. Study of sediment in Tabbs Bay, receiving discharge from
oilfield brine production as well as discharges from upstream industry (Houston Ship
Channel), indicates severe degradation of the environment by PAH contamination.
Sediments contained no benthic fauna, and because of wave action, the contaminants were
continually resuspended allowing chronic exposure of contaminants to the water column.
It is concluded by the U.S. Fish and Wildlife Service that shrimp, crabs, oysters, fish and
fish-eating birds in this location have the potential to be heavily contaminated with
PAH's. (TX 55)
Brine discharges contain a high ratio of calcium ions to magnesium ions, a
condition which has been found to be lethal to common Atlantic croaker, even when total
salinity levels are within tolerable limits. In a bioassay study, this fish was exposed to
various ratios of calcium to magnesium, and it was found that in 96 hour LC50 studies,
mortality was 50 percent when exposed to calcium-magnesium ratios of 6/1, the natural
ratio being 1/3. Nearly all of oil field brine discharges on file with the Army Corps of
Engineers in Galveston contain ratios exceeding the 6/1 ratio established in the LC50
test. (TX 31)
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Until very recently, the TRC allowed discharge of produced water into Petronilla
Creek, parts of which are 20 miles inland and clearly not tidally affected. Here too,
damages have been found:
For over fifty years, oil operators (including Texaco and Amoco) have been
allowed to discharge produced brine into Petronilla Creek, a supposedly tidally-influenced
creek. Discharge areas were as much as 20 miles inland and contained fresh water. In
1981 the pollution of Petronilla Creek became an issue when studies were done that
documented the severe degradation of the water and damage to native fish and vegetation.
All freshwater species of fish and vegetation were dead due to exposure to toxic
constituents in discharge liquid. Portions of creek were black or bright orange in color.
Heavy oil slicks and oily slime were observable along discharge areas. Impacts were
observed in Baffin Bay, where the creek empties, Petronilla Creek is the only freshwater
source for Baffin Bay which is a nursery for many fish and shellfish in the Gulf of
Mexico. Sediments in Baffin Bay show elevated levels of toxic constituents found in
Petronilla Creek. For the next five years the Texas Deparrtment of Water Resources and
Texas Parks and Wildlife along with environmental groups worked to have the discharges
stopped. The creek was shown to contain high levels of chromium, barium, oil, grease,
and EPA priority pollutants, naphthalene and benzene. Oil operators argued that a "no
dumping" order would put them out of business because oil production in this area is
marginal. In 1986, the TRC ordered a halt to discharge of produced brine in Petronilla
Creek. (TX 29)
Long-term environmental impacts associated with this type of discharge are
unknown, due to lack of suitable documentation and analysis. Bioaccumulation of heavy
metals in the food chain of estuaries could potentially affect human health through
consumption of crabs, clams, and other food stocks harvested off the Texas Gulf Coast.
Alternatives to coastal discharge do exist. They include underground injection of
produced water and drilling fluid, use of produced water and reserve pit fluid tanks, and
placement of spent drilling muds in commercial facilities. Evidence suggests that so long
as market conditions remain depressed, operators will continue to push for permits
allowing this type of discharge of brines and muds. The TRC does not at this time have
any plans to preclude further discharges of this nature.
Leaching of reserve pit constituents
Leaching of reserve pit constituents into ground water and soil continues to be a
major problem in Zone 7. Reserve pit liners are generally not required in Texas and
Oklahoma. When pits are constructed in permeable soil, the potential exists for migration
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of reserve pit constituents into ground water and soil. Although pollutant migration may
not always occur during the active life of the reserve pit, problems can occur after closure
when dewatered drilling mud begins to leach into the surroundings. Pollutants typically
include chlorides, sodium, barium, chromium, and arsenic.
On November 20, 1981, the Michigan-Wisconsin Pipe Line Company began
drilling an oil and gas well on the property of Ralph and Judy Walker. Drilling was
completed on March 27, 1982. Unlined reserve pits were used at the drilling site. After
two months of drilling, the water well used by the Walkers became polluted with elevated
levels of chloride and barium. The Walkers were forced to haul fresh water from Elk City
for household use. The Walkers filed complaint with the OCC, investigation was
conducted and all drilling mud was ordered removed from the reserve pit. The OCC then
dismissed the case, as the Walkers had not proven that the reserve pit had polluted their
well. The Walkers eventually retained a private attorney and sued Michigan-Wisconsin
for damages to their groundwater due to migration of reserve pit fluids into the freshwater
aquifer. The Walkers won their case. (OK 08)
In 1973, an oil well was drilled on the property of Dorothy Moore. As is the
common practice, the reserve pit was dewatered and the remaining mud was buried on site.
In 1985-1986, problems from the buried reserve pit waste began to appear. The reserve
pit contents are seeping into a nearby creek and pond. The surrounding soil had very high
chloride content. Extensive erosion is evident, a common problem with high-salinity
soil. Oil slicks are visible in the adjacent creeks and ponds. No monitoring wells have
been drilled to test the groundwater. (OK 07)
Lining of pits does not appear to be a particularly effective solution to this generic
problem, since after the pit is closed the contents are bulldozed and buried, almost certainly
destroying the integrity of the liner. Injection of reserve pit contents after completion of
drilling would preclude long-term migration of pollutants. A more costly alternative would
be to use a closed system while drilling, with portable tanks used in place of a reserve pit;
contents would then eventually be disposed of in a central commercial facility. The use of
such alternatives is not under way in either State in Zone 7, and would likely be unpopular
with the industry, particularly under current economic conditions.
Ground water chloride pollution from injection wells
Zone 7 contains a high number of injection wells used both for disposal of
produced water and for enhanced or tertiary recovery projects. This high number of wells
creates the potential for pollution of ground water through casing leaks.
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The Devore #1, a saltwater injection well located on the property of Verl and
Virginia Hentges, was drilled in 1947 as an exploratory well. Shortly afterwards, it was
permitted as a saltwater injection well. The injection formation, the Layton, was known
to be capable of accepting 80 barrels per hour at 150 psi. In 1984, George Kahn acquired
the well and The OCC granted an exception to Rule 3-305, Operating Requirements for
Enhanced Recovery Injection and Disposal Wells, and permitted the well to inject 2000
barrels per day at 400psi. Later in 1984, it was becoming evident that there was saltwater
migration from the intended injection zone of the Devore #1 to the surface. Saltwater had
polluted the groundwater used by the Hentges on their ranch, and saltwater was polluting
Warren Creek, a freshwater stream, used by downstream residents as the only source of
fresh water. Saltwater discharged to the soil had caused vegetation kills and soil
pollution. OCC required a workover be done on the well, but pollution continued. After
workover of well was completed to remedy leakage, migration of saltwater continued, and
the OCC allowed the operator to continue to dispose of saltwater in the well. Hentges
then sought private legal assistance, and filed a lawsuit against George Kahn, the
operator, for $300,000 in actual damages and $3,000,000 in punitive damages. The
lawsuit is pending. (OK 06)
Considerable inconsistency exists from State to State with respect to the operation
and testing of injection wells. Although the Federal government sets minimum standards
for operation and testing of underground injection, States that have primacy have
considerable latitude in the implementation of the program. Potential exists for the use of
inadequate materials, attempts to inject at pressures above what the receiving formation can
tolerate (resulting in fractures within the formation that can allow waste to migrate to the
surface or to ground water), and inadequate testing of casing integrity. Policing of oil and
gas activities has been reduced in Zone 1 because of reduced collections of production-
related ad valorum and severance taxes.
Illegal dumping
Illegal dumping is common in Zone 7 because of the diversity of operators involved
and the high level of oil and gas production. Hlegal dumping can occur in many forms,
including breaching of reserve pits, emptying of vacuum trucks into fields and ditches, and
draining of produced water onto the land surface. Damage to surface soil, vegetation, and
surface water usually results.
Esenjay Petroleum Co. had completed the L.W. Bing #1 well at a depth of 9,900
ft. and had hired T&L Lease Service to clean up the drillsite, on May 16, 1984. During
cleanup, the reserve pit, containing high chromium drilling mud, was intentionally
breached allowing drilling mud to flow into a tributary of Hardy Sandy Creek. The
drilling mud was up to 24 inches deep along the north bank of Hardy Sandy. Drilling
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mud had been pushed into the trees and brush adjacent to the drill site. Spill was reported
to the operator and TRC, and on May 20, cleanup was in progress. Because of high
levels of chromium, warnings were issued by the Lavaca-Navidad River Authority to
residents and landowners downstream of the spill as it represented a possible health hazard
to cattle watering from the affected streams. The River Authority also advised against
eating the fish from these waters due to the high chromium levels in the drilling mud.
(TX21)
On September 15, 1983, TXO Production Company began drilling its Dunn
Lease Well No. B2 in Live Oak County. On October 5, 1983, employees of TXO
intentionally broke the reserve pit levee and began spreading drilling mud downhill from
the site, towards the fence line of property owned by the Dunns. By Oct. 9, the mud had
entered the draw which flows into two stock tanks on the Dunn property. On November
24 and 25, dead fish began to be observed on the stock tank. On Dec. 17, Texas Parks
and Wildlife documented over 700 fish killed in the stock tanks on the Dunn property.
Despite repeated requests, TXO has not cleaned up the drilling mud and polluted water
from the Dunn property. Lab results from TRC and Texas Department of Health indicate
that the drilling mud was high in levels of arsenic, barium, chromium, lead, sulfates,
other metals and chlorides. In February 1984, the TRC stated that the stock tanks
contained unacceptable levels of nitrogen, barium, chromium and iron, and that the
chemicals present are detrimental to both fish and livestock. The Dunns water their cows
at this same stock tank. TRC came out with a memorandum stating that the fish had
died due to a cold front moving through the area, in spite of the fact that extensive
analysis of the soil, sediment and water in and around the stock pond contained high
levels of harmful substances. Ultimately, TXO was fined $1,000, and TXO and the
Dunns reached a cash settlement of damage claims. (TX 22)
Improperly abandoned or improperly plugged wells
Although damage created by improperly abandoned or improperly plugged wells is
not immediately associated with the extraction of oil and gas, wastes (generally native
brines) leaking from such wells do cause significant environmental damage in Zone 7.
The issue is essentially a upost-closure"-related problem. Damages can be direct, such as
through artesian flows of brine from deep geological strata to the surface (this happens
frequently in West Texas in the area of the Coleman Junction in the Permian Basin). They
can also be indirect, through upward migration of fluids injected under pressure in
neighboring disposal or secondary recovery wells.
The problem is particularly severe because oil development in the area is old and
many thousands of wells in the area were abandoned before any regulatory plugging
requirements were put in place. In addition, current plugging requirements are often
ignored or loosely enforced. Some 40,000 wells are closed each year in Texas, and under
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ZONE 8
Zone 8 includes Idaho, Montana, and Wyoming. Idaho has no commercial
production of oil or gas. Montana has moderate oil and gas production. Wyoming has
substantial oil and gas production, and accounts for all the damage cases discussed in this
section.
Operations
Significant volumes of both oil and gas are produced in Wyoming. Activities range
from small, marginal operations to major capital- and energy-intensive projects. Oil
production comes from both mature fields producing high volumes of associated water or
brine as well from newly discovered fields, where oil/water ratios are still relatively low.
Gas production comes from mature fields as well as from very large new discoveries in the
Overthrust Belt. These new fields contain hydrogen sulfide (F^S), a highly lethal,
naturally occurring constituent of some natural gas. This F^S production requires special
processing plants, two of which have been constructed and are in operation in the
Overthrust Belt.
Although the average new well drilled in Wyoming in 1985 was about 7,150 feet,
exploration in the State tends to be into strata as deep as 18,000. The make-up of mud for
deep drilling is complex and requires many chemical additives not needed for more shallow
drilling; muds are therefore more complex and potentially more harmful to the environment.
In 1985,1,735 new wells were completed in Wyoming, and 541 exploratory wells
were drilled. Although exploration is currently at a low point, if economic conditions were
to improve significantly, substantial new exploration and drilling would follow.
Types of Operators
Because of the depth and technical difficulty of drilling on the Overthrust Belt, and
the capital intensive nature of secondary and tertiary recovery projects, many operations in
the State are conducted by the major oil companies. These companies use first quality
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materials, are likely to implement environmental controls properly during drilling and
completion, and are generally responsible in carrying out their well abandonment
obligations. Small independent operators do account for some oil and gas production in the
State, and are inherently more susceptible to fluctuating market conditions. These
operators are much more likely than the majors to increase profitability at the expense of
environmental protection. Between these two groups are many mid-sized independent
operators, whose performance on environmental matters may be between the other two.
Environmental and Development Context
Wyoming contains both high desert and high-elevation, pristine wilderness. Both
have severe climates and are environmentally fragile. Much of the State has yet to be
explored intensively for oil and gas deposits. Both State officials and Federal Bureau of
Land Management officials have expressed concern over potential future development in
still-untouched areas, especially in the western highlands, which contain a majority of the
State's high-quality surface water.
Many aspects of the industry's operations are, at present, only loosely regulated.
Operators are allowed, for instance, to discharge produced water directly into dry stream
beds and surface water. Containment of produced water in unlined pits is common, even
though this practice is illegal in most other States.
Much of Wyoming's land is owned by the Federal government, and is subject to
different rules than apply to private landowners. According to State officials of the
Department of Environmental Quality, exploration and production operations on Federal
lands are better managed than those on private land due to the presence of oversight by the
Bureau of Land Management and the U.S. Forest Service.
Wyoming's population is largely rural with only a few small population centers.
The State ranks 49th in population, ahead of Alaska. Environmental damages related to oil
operations are therefore unlikely to affect populations or create human health impacts.
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Furthermore, since most of the activity is in physically remote areas, identification and
documentation of damages is difficult and documentable cases are therefore rare.
Major Issues
Illegal dumping
Wyoming DEQ officials believe that illegal dumping of wastes is the most pervasive
environmental problem associated with oil and gas operations. Cases come to light largely
through anonymous tips, sometimes from employees of companies involved in illegal
dumping. Enforcement is difficult because money and manpower are scarce and the areas
to be patrolled are large and remote.
Altex Oil Company has operated an oil production field for several decades just
east of Rozet, Wyoming. An access road runs through the area which for years was used
as a drainage for produced water from the oil field operations. In August of 1985, an
official with WDEC collected soil samples from the road ditch to ascertain chloride levels
as it was observed that trees and vegetation along the road were dead or dying. Samples
showed chloride levels as high as 130,000 ppm. The road was chained off in October of
1985 to preclude any further dumping of produced water. (WY 03)
In early October, 1985, Cities Service Oil Company had completed drilling at a
site northeast of Cheyenne on highway 85. The drilling contractor, Z&S Oil
Construction Company was suspected of illegally disposing of drilling fluids over a mile
away on the Pole Creek Ranch. An employee of Z&S had given an anonymous tip to a
County detective. A stake-out of the illegal operation was made with law enforcement
and WDEQ personnel. Samples and photos were taken of the reserve pit and the dump
site. Vacuum trucks were witnessed draining reserve pit contents down a slope and into a
small pond on the Pole Creek Ranch. After sufficient evidence had been gathered, arrests
were made and the trucks impounded. The state sued Z&S and won a total of $10,000.
Owners of Z&S were given a criminal record. (WY 01)
With current depressed oil and gas prices, the incidence of illegal dumping could
continue to increase. DEQ believes that independent operators may be responsible for most
of it, though there have been instances where a major company has been involved in illegal
dumping activities.
During the week of April 8, 1985 field personnel at the Byron/Garland field
operated by Marathon Oil Company were cleaning up a storage yard used to store drums
of oilfield chemicals. Drums containing discarded chemicals were punctured and allowed
to drain into a ditch adjacent to the yard. Approximately 200 drums containing 420
gallons of fluid were drained into the trench. The chemicals were demulsifiers, reverse
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demulsifiers, scale and corrosion inhibitors and surfactants. Broken transformers
containing PCBs were leaking into soil in a nearby area. Upon discovery of the condition
of the yard, Wyoming Department of Environmental Quality ordered clean-up procedures
to begin. Groundwater monitors were installed, and monitoring of nearby Arnoldus Lake
was begun. The state filed a civil suit and won a $5000 fine and $3006 in expenses for
lab work. (WY 05)
The legal method for disposal of reserve pit fluids and mud (through dewatering of
the pit, usually by land application, and burial of muds and cuttings) is not unusually
costly. Illegal dumping appears to be happening not because costs of proper disposal are
unreasonable, but because the easy opportunity for illegal practices exists and because
inspection and enforcement is difficult due to limited State funds.
Reclamation problems
Although Wyoming's mining industry has rules governing reclamation of sites, no
such rules exist covering oil or gas operations. As a result, reclamation on privately owned
land is often inadequate or entirely lacking, according to State officials. By contrast,
reclamation on Federal lands is believed to be consistently more thorough, since federal
leases specify reclamation procedures to be used on specific sites. WDEQ officials state
that this will be of continuing and growing concern as the State continues to be opened up
to oil and gas development.
No documentation was available to this study on reclamation problems; WDEQ
officials have photographs and letters from concerned landowners, but no developed cases.
The issue is at least partially related to drilling waste management, since improper
reclamation of sites often involves inadequate dewatering of reserve pits before closure. As
a result of this inadequate dewatering, reserve pit constituents, usually chlorides, are
alleged to migrate up and out of the pit, making revegetation difficult. The potential also
exists for migration of reserve pit constituents into groundwater.
Discharge of produced water into surface streams
Because much of the produced water in Wyoming is relatively low in chlorides,
several operations are allowed to discharge produced water directly into dry stream beds or
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live streams. The practice of constant discharge of low-level pollutants can, however, be
harmful to aquatic communities in these streams. Residual hydrocarbons contained in
produced water appear to suppress species diversity in live streams.
This case involves analysis of the macrobenthos community (fish) done on a
stream receiving produced water discharges from oilfield production. The study was
undertaken to determine the effect of chronic, low-level discharge of oilfield effluent into a
stream, and the resulting effect on the aquatic community in the stream. Several western
states permit discharge into surface waters of oil wastewater from refinery or crude oil
production operations. These western states are also receiving increased pressure to
develop new oil reserves on public lands containing valuable natural resources. Inadequate
information is available for the states to set discharge limitations for the protection of
aquatic resources from chronic oil contamination. During the study, samples were taken
upstream from the discharge, and downstream. Species diversity, community structure
were studied. Water analysis was done on upstream and downstream samples. The study
found a decrease in species diversity downstream from the discharge, further characterized
by total elimination of some species and drastic alteration of community structure. The
downstream community was characterized by only one dominant species, while the
upstream community was dominated by three species. Total hydrocarbon concentrations
in water and sediment increased 40 to 55 fold below the discharge of oilfield-produced
water. The authors of the study stated that "based on our findings, the fisheries and
aquatic resources would be protected if discharge of oil into fresh water were regulated to
prevent concentrations in receiving streams water and sediment that would alter structure
of macrobenthos communities." (WY 07)
The authors of the above case state, "Based on our findings, the fisheries and
aquatic resources would be protected if discharge of oil into fresh water were regulated to
prevent concentrations in receiving stream water and sediment that would alter structure of
macrobenthos communities." Alternatives would be disposal of produced water through
subsurface injection or on-site disposal in brine pits. Both are common in Wyoming.
There is, however, currently no initiative in the State to prohibit discharge of produced
water into dry or live streams. Both major and independent operators take advantage of
this allowable practice.
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ZONE 9
Zone 9 includes the States of Nevada, Utah, Arizona, Colorado, and New Mexico.
All five have some oil and gas production, but New Mexico's is the most significant. The
discussion below is limited to New Mexico.
Operations
Although hydrocarbon production is scattered throughout the State, most comes
from two distinct areas within New Mexico: the Permian Basin in the southeast corner, and
the San Juan Basin in the northwest corner.
Permian Basin production is primarily oil, and it is derived from several major
fields. There are numerous large capital and energy intensive enhanced recovery projects
that include extensive use of CO2 flooding. The area also contains some small fields in
which production is derived from marginal stripper operations. This is a mature production
area which is unlikely to see extensive exploration in the future. The Tucumcari Basin to
the north of the Permian may, however, experience extensive future exploration if
economic conditions improve in the future.
The San Juan Basin is, for the most part, a large mature field that produces
primarily gas. Significant gas finds are still made, however, including many on Indian
Reservation lands. As these are opened to oil and gas development, exploration and
development of the basin as a whole will continue, and possibly increase.
Much of the State has yet to be explored for oil and gas. The average depth of new
wells drilled in 1985 was 6026 feet. The number of new wells was 1,747, with 281
exploratory wells.
Types of Operators
The capital- and energy-intensive enhanced recovery projects in the Permian Basin,
as well as the exploratory activities under way around the State, are conducted by the major
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oil companies. Overall, however, the most numerous operators are small and medium-
sized independents. Small independents dominate marginal stripper production throughout
the Permian area. Production in the San Juan Basin is dominated by mid-sized independent
operators.
Environmental and Development Context
The land forms and geologic features dominating this zone are consolidated rock,
mostly lying flat and at or near the land surface. The zone's topography is extremely
varied, and—with the exception of the areas supporting alpine meadows and Douglas pine
and fir forests—evaporation exceeds precipitation throughout. Common vegetation
includes creosote bush, Arizona pine, Juniper and pinyon pine, sagebrush, and a variety of
different shrubs and grasses.
As in any western State, oil and gas activities often occur in remote, sparsely
populated areas, making documentation of environmental damage difficult. New Mexico is
a relatively poor State, having one of the lowest per capita incomes in the country. Perhaps
unique among the oil-producing States, much of the land believed to be potentially
promising for oil and gas development is owned by various Indian tribes within the
reservations, which comprise a significant percentage of New Mexico's area. The tribes do
not have clear guidelines for dealing with non-Indian companies, making development of
their oil and gas reserves difficult. In one instance, the Navajos have not entered into an oil
and gas lease agreement with non-Indians since 1975, precluding the development of their
lands during the last boom.
Major Issues
Unlined Produced Water and Oilfield Waste Pit Contents Leaching
into Ground Water
New Mexico, unlike most other States, still permits the use of unlined pits for
disposal of brines and reserve pit wastes. These can produce significant contamination of
ground water.
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One damage case developed in this State is in actually a summary of a study
conducted in 1985 in an attempt to demonstrate the hydrocarbons and chlorides found in
produced water in the San Juan Basin do indeed migrate out of unlined produced water pits
and into the ground water table.
In July 1985, a study was undertaken in the Duncan Oil Field in the San Juan
basin to analyze the potential of unlined produced water pit contents, including
hydrocarbons and aromatic hydrocarbons, to migrate into the groundwater. The oil field is
situated in a flood plain of the San Juan River. The site chosen for investigation was
similar to at least 1500 other nearby production sites in the flood plain. Test pits were
dug around the disposal pit on the chosen site. These test pits were placed above gradient
and down gradient of the disposal pit, at 25 and 50 meter intervals. A total of 9 test pits
were dug to a depth of 2 meters and soil and groundwater samples were obtained from each
test pit. Volatile aromatic hydrocarbons were found in both the soil and water samples of
test pits down gradient, demonstrating migration of unlined produced water pit contents
into the groundwater. Damage can be summarized as contamination of shallow
groundwater due to leaching from an unlined produced water disposal pit. Benzene was
found in concentrations of 100 ppb, above New Mexico Water Quality Control
Commission standards of 10 ppb. Concentrations of ethylbenzene, xylenes and larger
hydrocarbon molecules were found. No contamination was found in test pits placed above
gradient from the disposal pit. Physical signs of contamination were also present
including black, oily staining of sands above water table and black oily film on the water
itself. Hydrocarbon odor was also present. (NM02)
As a result of this study, the use of unlined produced water pits was limited to wells
producing no more than five barrels per day of produced water. While this is an
improvement over the previous rule, which did not limit volume of produced water
disposed of in this manner, there still exists great potential for contamination of ground
water with hydrocarbons and chlorides in this zone. Over 20,000 unlined pits are still in
existence in New Mexico.
Evidence of damage from this practice is shown in such instances as the following.
Lee Acres landfill is located two miles E-SE of Farmington, N.M. It is owned
by BLM. The landfill is composed of four unlined liquid-waste lagoons or pits. Since
1981, a variety of liquid wastes associated with the oil and gas industry have been
disposed of here including produced water, septage and volatile organic compounds. Use
of the pits ceased on 4/19/85. 8,800 cubic yards of waste were disposed of prior to
closure. Site is 20 acres in size. Leachate from the unlined waste lagoons contaminated
several water wells in the Lee Acres housing subdivision located downgradient from the
landfill. Extensive water analysis has been done on the pits and the contaminated water
wells. High levels of Na, Cl, Pb, Cr, benzene, toluene, xylenes, chloroethane and
trichloroethylene were found in pits. High levels of chlorides and VOCs were found in a
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downgradient monitoring well. One domestic well was sampled extensively and found to
contain extremely high levels of chloride and elevated levels of chlorinated VOCs,
including trichloroethane. Except for benzene, the contamination found in this well
(Reynold's well) are not characteristic of the contaminants generated by a nearby refinery.
The State has ordered BLM to provide public water to residents affected by the
contamination, develop a groundwater monitoring system, and investigate types of
drilling, drilling procedures, and well construction methods. BLM Submitted a motion to
stay the order so as to include Giant Oil Co. and El Paso Natural Gas in cleanup
operations. The motion was denied. The case is pending, and may end up in court. (MM
05)
Damage to Ground Water From Leaking Injection Wells
One case discovered in New Mexico involves a leaking injection well that has
caused extensive economic and environmental damage, yet is still in operation with the
permission of the New Mexico Oil Conservation Division.
A saltwater injection well, BO-3, operated by Texaco, is used for brine disposal
for the Moore-Devonian oil field in SJE. New Mexico. Injection occurs at about 10,000
ft. The Ogallala aquifer, overlying the oilfield, is the sole source of potable groundwater
in much of southeastern New Mexico. The BO-3 was found to have contributed to a
saltwater plume of contamination in the Ogallala nearly one mile long and containing
chloride concentrations of up to 26,000 ppm. Texaco argued that the saltwater plume
was the result of leachate of brines from unlined brine disposal pits, now banned in the
area. Texaco still uses the BO-3 well, unaltered, as a disposal well for oilfield brines in
spite of a lawsuit in which they paid a cash settlement to a rancher for damages incurred
due to the leaks and subsequent groundwater contamination from BO-3. The rancher
sustained damage to crops after irrigating with water contaminated by the saltwater plume
in the Ogallala aquifer. In 1973, an irrigation well was completed on the ranch of Mr.
Paul Hamilton. In 1977, the well began producing water with chlorides of 1,200 ppm.
His crops were severely damaged and the farm property was foreclosed on. There is no
evidence of crop damage prior to 1977. Mr. Hamilton's hydrologist proved that if old
pits in the vicinity previously used for saltwater disposal had caused the contamination,
high chloride levels would have been detected in the irrigation well prior to 1977. It was
proven in court that the BO-3 injection well adjacent to his property had leaked some 20
million gallons of brine into the groundwater, causing chloride contamination of the
Ogallala aquifer from which he irrigated. Mr. Hamilton won a cash settlement from
Texaco for damages sustained by the leaking injection well. The well is still in
operation. (NM 01)
The well in question was pressure tested several times during the course of the trial,
during which the plaintiff's hydrologist discovered that this injection well would have been
classed as a failed well using the State of Texas's criteria for pressure testing of injection
wells. Presumably the well would have been shut down if it had failed New Mexico's
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pressure testing requirements, but in this case the damage was extensive enough that it
appears unusual that the State did not use discretionary authority to close down the
operation.
Contamination of Ground Water From Improperly Completed Oil and
Gas Wells
Improperly completed wells can leak hydrocarbons into aquifers and cause
contamination of public drinking water supplies.
The Flora Vista Water Users Association operates a community water system
that serves 1500 residents and small businesses. The system began operation in 1983
with two wells, each capable of delivering 60-70 gallons per minute. In 1980, Manana
Gas, Inc. drilled the Mary Wheeler No. 1-E, and began producing natural gas and oil on a
production site less than 300 feet from one of the Flora Vista water wells. In 1982, the
Manana well produced 39,584 million cubic ft of gas and 1,022 barrels of oil. In 1983,
one Flora Vista water supply well was contaminated with oil and grease, apparently by
the Manana Gas well, and was taken out of service. After extensive testing and
investigation, the New Mexico Oil Conservation Division concluded that the Manana Gas
well was the source of oil and grease contamination of the Flora Vista water well. Water
analysis done on water wells affected as well as on five monitor wells. Analysis shows
hydrocarbon contamination of groundwater. Pumping tests were also done to ascertain
source of pollution. Although the gas well lies down gradient from the water well, it
was demonstrated that pumping of the water well drew the oil and grease upgradient, thus
contaminating the water well. Water now has to be purchased from the town of Aztec
and piped to Flora Vista in an existing pipeline. There is no indication in reports that the
production well responsible for this contamination has been shut down or reworked to
prevent further contamination of groundwater. (NM 03)
This type of contamination of ground water has a long history in this State (as
elsewhere).
Lea County has been an area of major hydrocarbon production for a number of
decades. Oil field contamination of fresh water sources became apparent as early as the
1950s. Contamination of the fresh water aquifer has resulted from surface pit seepage and
leakage from production and injection well casings. Over 120 domestic water wells in the
town of Hobbs have been contaminated so extensively as to preclude further use of the
well for domestic or irrigation purposes. Residents have been using bottled water for a
decade or more as a result of the contamination. Leakage from oil wells has been so great
in some areas as to allow ranchers to produce oil from the top of the Ogallala aquifer
using windmill pumps attached to contaminated water wells: approximately 400.000
barrels have been pumped off the top of the Ogallala to date, although production is
decreasing due to repair of large leaks in adjacent oil production wells. Damages include
extensive, permanent contamination of groundwater with high levels of chlorides and a
variety of organic compounds. Groundwater is the only source of drinking water in the
area. Over 100 domestic water wells have documented contamination in the town of
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Hobbs. The potential for casing leaks on oil wells and injection wells remains high due
to the high chloride content of the native brine co-produced with the oil. (High chloride
levels in water corrode well casing.) It is therefore assumed that the contamination is
continuing. (NM 04)
As is seen in cases such as this, extensive contamination may often become
accepted by local residents, as here where use of bottled water is routine.
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ZONE 10
Zone 10 includes Washington, Oregon, and California. Of the three, California has
the most significant hydrocarbon production; Washington and Oregon have only minor oil
and gas activity. Damage cases were therefore gathered only from California.
Operations
California has a diverse oil and gas industry, ranging from stripper production in
very mature fields to deep exploration and large enhanced recovery operations. Southern
California and the San Joaquin Valley are dominated by large capital- and energy-intensive
projects; for example, operators are increasing the use of steam recovery by injection to
enhance production in southern San Joaquin Valley fields where "heavy gravity" oil is
extracted—an expensive, but, in this case, necessary technique. Exploration and
development in the new coastal fields is also capital intensive.
California's most mature production areas are in the lower San Joaquin Valley and
the Sacramento Basin. The San Joaquin produces both oil and gas—the new coastal fields
produce mostly oil, but some gas. The Sacramento Valley produces mostly gas.
Waste disposal is an important concern. Although two practical methods are
available, injection and percolation, both are considered problematic by environmental
departments in the State. Operators have been increasing the number of Class II and V
injection wells to reinject brines and other oil field wastes. Class II wells serve a dual
purpose, being used both for disposal of oil field wastes and for enhanced recovery; Class
V wells are used only for waste disposal, and are subject to more relaxed environmental
performance standards. Percolation, the other principal method of waste disposal, is used
primarily in the San Joaquin area, where brines are discharged to ephemeral streams and
later diverted into central percolation sumps.
The average depth of new wells drilled in California in 1985 was 4,176 feet. One
hundred sixty-six exploratory wells were drilled in that year, and 3,413 completed.
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Types of Operators
Operators in California range from small independents to major producers. The
majors dominate capital- and energy-intensive projects, such as coastal development and
large enhanced recovery projects. Independents tend to operate in the mature production
areas dominated by stripper production.
Environmental and Development Context
Oil and gas development in California occurs in diverse areas. The San Joaquin
Valley has a dry climate with rolling hills. After the winter rainfall, streams are
intermittent. The California Fish and Game Commission has identified the area as a
sensitive habitat for species classified by both the State and Federal Governments as rare
and endangered. The increasing amount of agriculture in the region uses irrigation water
brought from the north by aqueduct, though there is some use of ground water and surface
water from the Kern River. Oil operations are located in both populated and unpopulated
areas.
The coastal oil development area is classed as chapparel; it is wetter than the eastern
area, and has steeper hills. Oil operations in the Sacramento Valley take place on the
valley's agriculturally intensive floor. Since this farming draws ground water for
irrigation, there is increasing concern about the safety of oil-related injection wells.
California's southern oil region also lies along the coastal plain where population is
dense.
Major Issues
Discharge of brines and oily wastes to ephemeral streams
In the San Joaquin Valley, the State has long allowed discharge of oily brines to
ephemeral streams, from which it is later diverted into central sumps for disposal through
evaporation and percolation. Infiltration of brines into aquifers is assumed to occur, but
official opinion on its potential for damage is divided. The Department of Oil and Gas
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takes the position that the aquifers are naturally brackish, and thus have no beneficial use
for agriculture or human consumption. A report for the Water Resources Council Board,
however, suggests that brines may percolate into useable ground-water structures.
Groundwater in the study area has been categorized according to geotypes and
compared to brine waters in sumps that came from production zones. Research has found
that sumps in Cymric, McKittrick and Midway Valleys, Elk Hills and Buena Vista Hills,
and Buena Vista Valley fields responsible in part for ground water brine. Officers of the
California Dept, Fish & Game often find entrapped animals in the oily deposits in the
streams. While recent research has not investigated groundwater damages per se, their
study suggests obvious potential for damages relating to the groundwater. It has been
estimated that about 570,000 tons of salt from petroleum brines were deposited in 1981,
or a total of 14.8 million tons since 1900. The California Water Resources Board
suspects that a portion of the salt has percolated into the groundwater and has degraded it.
(CA 21)
Aside from concerns over chronic contamination to aquifers, this practice can cause
acute damage to wildlife when wastes mixed with natural runoff exceed the holding
capacity of the ephemeral streams. The combined volume may then overflow the
diversions to the sump areas, continue downstream, contaminating soil and endangering
sensitive habitat The oil and gas industry contends that it is rare for any wastes to pass the
diversions set up to channel flow to the sumps, but the California Department of Fish and
Game believes that it is a common occurrence.
Produced water in the Crocker Canyon area flows downstream to where it is
diverted into Valley Waste Disposal's large unlined evaporation/percolation sumps for oil
recovery (cooperatively operated by local oil producers). In this instance, discovery of a
significant spill was made over month after it occurred. The incident, caused probably by
heavy rainfall exceeding disposal facilities capacity and eroding sumps, allowed produced
water mixed with oil to flow into the valley beyond the disposal facility into a habitat
occupied by several endangered species (blunt-nosed leopard lizard, San Joaquin Kit Fox,
Giant Kangaroo Rat). According to the State's report, there were "116 known wildlife
losses: including 80 mammals, 11 Giant Kangaroo Rats, and two doves. The count of
dead animals was estimated at only 20 percent of the actual number of animals destroyed
because of the delay in finding spill, allowing poisoned animals to leave the area before
dying. Vegetation was covered with waste throughout the spill area. This was not
considered an isolated incident; the California Water Resources Control Board noted during
its investigation, "...deposits of older accumulated oil, thereby indicating that the same
channel had been used for wastewater disposal conveyance in the past prior to the recent
discharge. Cleanup activities conducted later revealed the buildup of older oil was
significant." The companies implicated in this incident were fined $100,000 and were
required to clean up the area. They did, however, deny responsibility for the discharge.
(CA 21)
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Damages from disposal of drilling wastes in ponds
Current damages have occurred through long term migration of drilling related
wastes from old waste sites. The problem is similar to that of abandoned wells in that the
risk occurs in the "post-closure" phase. Incidents such as presented below suggest the
potential of drilling-related wastes (in this case probably workover fluids) to cause health
damage years after closure of a pit.
Acid petroleum sludge and drilling muds during the 1940s were disposed of into
"earthen ponds" in what was then a remote part of Fullerton Hills. While the report
issued on the area does not specify exactly what acids were used, acids were typically used
to remove paraffin and waxy build up from a production well and during a workover
operation. The report did not specify the exact constituent makeup of the waste steam
though the wastes were most likely workover fluids. The area began to be developed for
residential use in the late 1970s and soon after the California Department of Health
Services responded when residents complained of health problems they were experiencing.
A controlled health survey of the residents mainly assessing air inhalation demonstrated
elevated health problems, though the report found that the relationship between the
McColl site and health degradation was unclear. For soil and water exposure, it estimated
that problems could occur with direct contact with wastes both on-site and off-site,
though no actual analysis was conducted of such direct exposure. (CA 01)
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ZONE 11
Zone 11 includes Alaska and Hawaii. Hawaii has no oil or gas production, but
Alaska is second only to Texas in oil production.
Operations
Alaska's oil operations are divided into two entirely separate areas, the Kenai
Peninsula and the North Slope. Because of the area's remoteness and harsh climate,
operations in both areas are highly expensive and energy-intensive. For the purposes of
damage case development, and indeed for most other types of analysis, operations in these
two areas are distinct. Types of damages identified in the two areas have little in common.
Activities on the Kenai Peninsula have been in progress since the late 1960s, and
gas is the primary product. Production levels are not nearly as significant as on the North
Slope. Only a relatively small amount of brine is produced in Kenai operations, and for the
most part, this is legally discharged to the ocean. The primary wastes of concern on the
Kenai are drilling muds, related chemicals, and gas condensate.
North Slope operations occur primarily in the Prudhoe Bay area, with some smaller
fields located nearby. Average drilling depth is about 8,150 feet. Production has been
under way since the trans-Alaska pipeline was completed in the mid 1970s; activities are
even more capital- and energy-intensive than they are on the Kenai Peninsula. Much of the
oil recovery in this area is now becoming marginal; enhanced recovery through water
flooding is on the increase. Some production units were shut-in between December 1986
and February 1987, while damage case development was in progress.
Waste management on the North Slope is unusual in several respects. First,
transportation costs are such that ail materials hauled to the area are permanently deposited
there once they are no longer useful. This includes disposal of foam and timber for drilling
pad construction, empty metal drums previously containing chemical additives, as well as
waste oil, chemicals, and general trash. It also includes all muds and production-related
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chemicals such as corrosion inhibitors and biocides. Produced waters are disposed of by
injection below the permafrost.
Further development of reserves has been almost entirely curtailed throughout
Alaska since the prices of oil and gas have declined. There were only 100 wells drilled in
the State in 1985. none of them exploratory. However, if world prices were to increase
significantly (to about $2Q/bbl). Alaska would be one of the chief beneficiaries and oil and
gas development would resume on a significant scale. Generation of associated waste
stream volumes, especially reserve pit fluids, would rise dramatically over current levels.
Types of Operators
There are no small, independent oil or gas operators in Alaska because of the high
capital requirements for all activities in the region. Operators in the Kenai Peninsula
include Union Oil of California and other major companies. Major producers on the North
Slope are ARCO and Standard Production Company. Because of their size and visibility,
these large companies have both the incentive and the ability to maintain high environmental
standards. On the other hand, Alaska is remote, sparsely populated, and expensive to
develop, providing both the opportunity and the incentive to cut costs where possible. This
is particularly true on the North Slope, where physical access is extremely difficult, and
where the major operators maintain security gates on the haul road owned by the State of
Alaska. Restricted access complicates environmental enforcement and has severely limited
scientific evaluations of the effects of oil activities by both government and private
scientists.
Environmental and Development (Context
The Kenai Peninsula is a wetlands area, with shallow groundwater often only a few
feet from the surface. Soils are generally unconsolidated sands and gravels. There is
abundant wildlife. Both birds and game fish are highly important to the area as a sporting
attraction; the Kenai River is one of the most heavily fished sport-fishing streams in the
United States. Until recently the peninsula was sparsely populated, but settlement
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increased dramatically during the 1970s in response to the high general level of oil
development activity throughout the State. With an increase in population has come an
increase in awareness of possible environmental damages associated with oil and gas
development. The porous soils and high water table increase the likelihood that ground-
water contamination from oil and gas operations (such as from reserve pits and illegal
dumping) can spread to drinking water supplies. On the other hand, increased population
has permitted the development of centralized water supplies, lowering reliance in some
areas on individual home wells.
The North Slope is a wet coastal plain with numerous interconnected tundra ponds
and streams. It is underlain by permafrost of up to 2,500 feet thick. The spring "break-
up" or thaw occurs in June; at this time all surface water melts producing an area-wide
"sheet flow." The area is unfrozen for only about two months of the year, but is inhabited
by a large variety of shore birds and waterfowl feeding primarily on communities within
the tundra ponds.
Except for the permanent camps maintained by the production companies and a few
native settlements, there are no population centers on the North Slope. Because of the
permafrost, drinking water wells are non-existent and human health impacts from the
drilling operations through environmental pathways are not significant. Potential damages
involve disruptions of the extensive wildlife communities through discharge of reserve pit
fluids and other wastes to the tundra (above the permafrost).
Major Issues
The North Slope
Reserve Pits: Reserve pits on the North Slope are unlined and made of permeable
native sands and gravels. Very large amounts of water therefore unavoidably flow into and
out of these pits during break-up each spring in the phenomenon known as "sheet flow."
Discharge from pits directly onto the tundra is also permitted under regulations of the
Alaska Department of Environmental Conservation (ADEC) if minimum discharge
standards are met (see Chapter 3). Through these processes, ADEC estimates that 100
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million gallons of supernatant flow onto the tundra each year,4 potentially carrying with it
reserve pit constituents such as chromium, barium, chlorides, and oil. Scientists who have
studied the area believe this has the potential to lead to bioaccumulation of heavy metals and
possibly other contaminants in local wildlife. Despite the potential significance of this issue
both to the Prudhoe area and to possible future development in the Arctic National Wildlife
Refuge, no studies have been published to demonstrate or disprove this possibility, though
results from unpublished studies suggest that this can happen.
In 1983, a study of the effects of reserve pit discharges on water quality and the
macroinvertebrate community of tundra ponds was undertaken by the U. S. Fish and
Wildlife Service in the Prudhoe Bay oil production area of the North Slope, where
discharge to the tundra is a common disposal method for reserve pit fluid. The study
shows a clear difference in water quality and biological measures between reserve pits,
receiving ponds, distant ponds and control ponds. Receiving ponds had significantly
greater concentrations of chromium, arsenic, cadmium, nickel and barium than did control
ponds, and distant ponds showed significantly higher levels of chromium than did control
ponds. Chromium levels in reserve pits and in ponds near drill sites frequendy exceeded
EPA chronic toxicity criteria for protection of aquatic life. (AK 06)
In the summer of 1985, a field method was developed to evaluate toxicity of
reserve pit fluids discharged into tundra wetlands at Prudhoe Bay, Alaska. Results of the
study document acute toxicity effects of reserve pit fluids. Acute toxicity was shown at
all five reserve pits examined after 96 hours. Receiving ponds also had significantly
higher death/immobilization than control ponds after 96 hours. At drill site 1, after 96
hours, 100 percent of the Daphnia in the reserve pit had been immobilized or were dead,
as compared to the control pond which showed less than 5 percent immobilized or dead.
At drill site 12, 80 percent of Daphnia in reserve pit were dead or immobilized after 96
hours and less than 1 percent of control pond Daphnia were dead or immobilized.
(AK07)
In June 1985, five drill sites and three control sites were chosen for studying the
effects of drilling fluids and their discharge on fish and waterfowl habitat on the North
Slope of Alaska. Bioaccumulation analysis was done on fish tissue using water samples
collected from the reserve pits. Nearby and distant tundra ponds are contaminated with
reserve pit effluent including drilling mud, diesel fuel, waste chemicals and oil. Many
drilling fluid additives are known to be acutely or chronically toxic, including aromatic
hydrocarbons, bactericides, lignosulfonates, emulsifiers and metals. This study
documented the migration of reserve pit fluids from pits through discharge and seepage
into nearby and distant tundra ponds. Fecundity and growth were reduced in daphnids
exposed for 42 days to 2.5 percent and 25 percent fluid from some drill sites.
Bioaccumulation of Ba, Mo, Ti, Fe and Cu was documented in fish exposed to drilling
fluids for 96 hours. (AK 08)
Statement by Larry Dietrick to Carla Greathouse.
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Currently the most pressing environmental issue on the North Slope is the permitted
practice of road spreading of reserve pit fluids. This is commonly done when reserve pit
fluids do not pass a minimum quality test required in discharge permits under ADEC's
rules, raising the possibility that reserve pit contaminants are spread on an even wider area
than when discharged to the tundra.
Construction and subsequent erosion of reserve pits constitutes another potential
problem area. Pits are constructed of highly permeable native sand and gravel and there is
no feasible way to line them.5 If pits are not closed out at the end of a drilling season, they
may breach during "break-up" because of increased hydrostatic head on the pit walls
caused by the influx of high volumes of melt water. Reserve pit contaminants are then
released directly to the tundra. Flow of gravel during a pit breach can also choke or cut off
tundra streams, severely damaging or eliminating aquatic habitat.
The Awuna Test Well No. 1, 11,200 ft deep, is in the National Petroleum
Reserve in Alaska and was a site selected for cleanup of the NPRA by USGS in 1984.
The site is in the northern foothills of the Brooks Range. The well was spud on Feb. 29,
1980, and operations were complete on April 20,1981. A side of the reserve pit berm has
washed out into the tundra during spring break-up, due to the coarse material used in pit
and pad construction, allowing for reserve pit fluid to flow into the tundra. High levels of
chromium, oil and grease have leached into the soil down gradient from the pit. The high
levels of oil and grease may be from the use of Arctic Pack (85 percent diesel fuel) at the
well over the winter of 1980. The downslope soils were discolored and putrefied,
particularly in the upper layers. The well site is in a caribou calving area. The pad is
located in a runoff area allowing for erosion of pad and pit into surrounding tundra. Area
of vegetation kill due to reserve pit fluid exposure = 0.5 acres. Areas of drill pad may
remain barren for many years due to contamination of soil with salt and hydrocarbons.
(AK12)
Problems can also be encountered with the "freeze-back" method of reserve pit
closure. When drilling has been completed and a pit is to be closed, the common North
Slope practice is to dewater the pit, mound gravel over the remaining contents and allow the
contents to freeze permanently in place. Problems can arise when hydrocarbons have
contaminated the pit, since the contents will then not refreeze properly and can leach into
5 Oil companies assert that bentonite mud used in drilling seals reserve pits, thus preventing
leaching. However, although this may be true at the beginning of a pit's life, bentonite breaks down and
loses its sealing properties after one freeze-thaw cycle.
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the surrounding area.
The ADEC is attempting to revise current statutes regulating the construction and
integrity of reserve pits. ADEC is proposing a requirement to close pits at the end of each
drilling season; thus, liquid management plans (involving discharge to the tundra or road
spreading) would not be necessary and reserve pit fluids might be totally contained. The
Alaska Oil and Gas Commission requirements state that reserve pits may not be permitted
to leach further than 50 feet during the active life of the pit. It is, however, officially
acknowledged that 65 of the approximately 350 reserve pits on the North Slope are
currently seeping.
Inspection and enforcement are difficult on the North Slope due to shortages of
manpower and high expenses. Inspectors often require the use of a helicopter for
transportation and must be housed in costly man-camps while in the area. Until 1983, the
ADEC had little funding for enforcement or inspection on the North Slope. Prior to 1982,
according to officials in Fairbanks, there was little state regulation of North Slope activities.
Currently, through the acquisition of Federal Coastal Zone Resource Management funding,
ADEC can now support 36 "monitoring weeks" per year on the North Slope.
North Slope Salvage, Inc. (NSSI) operated a salvage business in Prudhoe Bay
during 1982 and 1983. During this time NSSI accepted delivery of various discarded
materials, including more than 14,000, 55 gallon drums, 900 of which were full or held
more than residual amounts of oils and chemicals used in the development and recovery
of oil. The drums were stockpiled and managed in a manner which allowed the discharge
of hazardous substances. The situation was discovered by ADEC in June 1983, and an
inadequate cleanup effort was mounted by NSSI after confrontation by ADEC.
Ultimately, ARCO and Sohio paid for the cleanup as they were the primary contributors
to the site. Cleanup was completed on August 5, 1983, after 58,000 gallons of
chemicals and water were recovered. It is unknown how much of the hazardous
substances were carried into the tundra, however, cleanup did not begin until July 2, well
after the completion of breakup for that year. The discharge consisted of oil and a variety
of organic substances known to be toxic, carcinogenic, mutagenic or suspected of being
carcinogenic or mutagenic. NSSI failed to report the discharge or initiate containment and
cleanup actions until they were confronted by ADEC field officers. (AK 10)
Oil Spills: Spills of crude oil and hydrocarbon products constitute another potential
source of long-term environmental damage. Although spills may not be "wastes" under the
§3001 exemption, and may be small in volume when compared to the total volume of oil
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and gas produced on the North Slope, impacts of oil spills in the Arctic are more long-term
and more far-reaching than in more temperate climates. Spills are endemic to all oil and gas
operations, and, especially in the harsh North Slope climate, certain levels of spillage can
be expected despite the vigilance of operators. In 1986, there were a total of 415 reported
spills comprising an estimated 1,565,054 gallons of crude oil; of that, 13,658 gallons, or
less than one percent, were reported as cleaned up.
From 1971-1975, a study was done for the Department of the Interior by
individuals from Iowa State University concerning waterbirds, their wetland resources and
the development of oil at Storkersen Point, Alaska. Contained in the study area was a
capped oil well (owner of well not mentioned). Adjacent to the well was a pond which
had been severely polluted during the drilling of this well. The area is classified as an
arctic wetlands. "The results of severe oil pollution are indicated by the destruction of all
invertebrate and plant life in the contaminated pond at the Storkersen Point well; the
basin is useless to water birds for food, and the contaminated sediments contain pollutants
which may spread to adjacent wetlands. Petroleum compounds in bottom sediments break
down slowly, especially in cold climates, and oil-loaded sediments can be lethal to
important and abundant midge larvae, and small shrimp-like crustaceans. Repopulation of
waters over polluted sediments by free-swimming invertebrates is unlikely because most
aquatic invertebrates will be subjected to contact with toxic sediments on the bottom of
wetlands during the egg or overwintering stage of their life cycle. Unfortunately, human-
induced change may create permanent damage before we can study, assess, and predict the
complications. First order damage resulting from oil development will be direct effects of
oil pollution on vegetation and wetland systems. Oil spills almost anywhere in this area
where slopes are gradual and drainage patterns indefinite, could result in the deposition of
oil in many basins during the spring thaw when melt water flows over the impermeable
tundra surface. Any major reduction of food organisms through degradation of preferred
habitats by industrial activity will be detrimental to local aquatic bird populations."
WATER BIRDS AND THEIR WETLAND RESOURCES IN RELATION TO OIL
DEVELOPMENT AT STORKERSEN POINT, ALASKA, United States Department of
the Interior, Fish and Wildlife Service, Resource Publication 129,1977. (AK 09)
The Kenai Peninsula
Reserve Pits: Reserve pit wastes are the principal source of potential environmental
degradation on the Kenai Peninsula (little brine is produced). At least several hundred
wells have been drilled in the area since the late 1960s and until recently there has been little
concern over the manner in which reserve pit wastes have been managed. In the last
several years, however, citizens have been increasingly concerned about the potential for
contamination of ground water caused by the use of unlined reserve pits and improper
closure of such pits. Because soils are unconsolidated and because many residents'
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drinking water wells extract water from near the surface (frequently from a few dozen feet
or less), residents are concerned that toxic materials are leaching into the wetland water
table. There is also the potential for wildlife damage through contamination of wetland
breeding, feeding, and support areas by heavy metals and chemicals associated with
reserve pit wastes.
Even though reserve pit wastes are not classified as hazardous by the State, since
1972 drilling operators have been required, under Alaska's solid waste rules, to dispose of
reserve pit wastes in a permitted landfill after the pits are closed. Annular disposal of muds
is also permitted, but this method can only accept a portion of the large volumes of muds
used in the area, estimated at between 35,000 and 50,000 bbls per well.6
Between 1972 and October 1985, the only k'censed land disposal facility in the area
was the Sterling Special Waste Site. This site has now been closed permanently after
prolonged controversy about the quality of its management and the possibility—based on
monitoring of local water wells—that it has contaminated local ground water.
The operation has had long history of substandard monitoring, having failed
during 1977 and 1978 to carry out any well sampling and otherwise having performed
only irregular sampling. This is in violation of permit requirements to perform quarterly
reports of water quality samples from the monitoring wells. Internal DEC memo [L.G.
Elphic to R.T. Williams, 2/25/76] noted "we must not forget...that this is the State's
first sanctioned hazardous waste site and as such must receive close observation during its
initial operating period." Permit for site was reissued in 1979 despite knowledge by DEC
of lack of effective groundwater monitoring. In July of 1980, DEC Engineer R.
Williams visited site and filed a report noting that the "operation appears completely out
of control" [R. Williams, "Inspection Trip Report: Kenai Peninsula Solid Waste Disposal
Facilities," DEC July 1980]. Monitoring well samples in excess of drinking water
standards include exceedences for iron, lead, cadmium, copper, zinc, arsenic, phenol, and
oil and grease. One private well showed 0.4 ppb 1,1,1-trichloroethane. Sterling School
well showed 2.1 ug/1 mercury. Both contamination incidents alleged to be caused by the
Sterling Special Waste Site; allegations unconfirmed by the DEC. (AK 03)
Although the Sterling Site had problems of its own, its logs suggest that far less
mud was being shipped to the site than should have been if all closed reserve pits had
followed State requirements. Over the period between July 1972 and October 1985, a total
6 A significant portion of the muds used in the Kenai may be lost to the formations through which
the well is drilled. Data on this possible loss was not available to this study.
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of 243,000 bbls of muds were logged into the 40 acre site; during the same period more
than two hundred wells were drilled on the Kenai. Considering the large volumes of mud
used in drilling operations on the peninsual, and even accounting for significant losses
within the formations, the Sterling Site appears to have received only a small percentage of
the waste that it should have. Even allowing for annular disposal of a significant portion of
the mud on site, large amounts of reserve pit wastes appear to have been illegally disposed
of during the entire period of operation of the Sterling Site. For example:
David Brown of Mar Enterprises (operator of Sterling Special Waste Site)
contracted to remove an estimated 50,000 bbls of muds from pit located on a site owned
by Union Oil. Brown's actual bill (June 10, 1981) indicated removal of only 15,823
bbls; rest was buried by Union Oil prior to arrival of vacuum trucks. This is documented
by a sequence of correspondence detailing arrangements between David Brown and Union
Oil to clean up waste from pits; correspondence indicates that after initial site inspection,
Union Oil illegally buried much of the mud to be removed—confirmed by correspondence
from ADEC to Union Oil, December 7,1981. (AK 03)
Since the closure of Sterling very little drilling has occurred on the Kenai, but there
is now no legal site in Alaska to which drillers can ship then- muds. If drilling were to
revive, it appears that there is no legal option available to oil companies for disposing of
their reserve pit wastes.
With the exception of the indirect evidence linking the Sterling Site with local well
contamination, there have been few documented instances of ground water contamination
by reserve pit wastes. This may be partly because the area is still relatively sparsely settled,
partly because wastes may not have had enough time to migrate, and partly because the
State lacks resources to monitor extensively in the area. Nevertheless, there is at least one
fully documented instance in which illegal disposal of wastes has resulted in substantial
economic and health damage.
This case involves a 45 acre gravel pit on Poppy Lane used since the 1970s for
disposal of wastes associated with gas development. It contains barrels of unidentified
wastes, drilling muds, gas condensate, gas condensate contaminated peat, abandoned and
useable equipment, diesel and chemical contaminated soil. Property belongs to Union Oil
Co., which bought it around 1968 (reportedly for $10). Dumping of wastes in this area
is illegal; reports of last observed dumping were in October 1985, as witnessed by
residents in the area. Illegal disposal of drilling and production wastes can lead to
migration of materials offsite to neighboring properties and drinking water wells. In this
case there has been demonstrated contamination of adjacent wells with organic compounds
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related to gas condensate (ADEC laboratory reports from October 1986 and earlier).
Health effects on residents of neighboring properties include nausea, diarrhea, rashes,
elevated blood metals levels in two residents (chromium, copper). Property values have
been effectively reduced to zero for residential resale. Fire on the site on July 8, 1981
attributed to combustion of petroleum related products; fire was allegedly deliberately set
by people illegally disposing of wastes, fire department was unable to extinguish. Soil is
contaminated with metals and organics. Fumes from organic liquids noticeable in
breathing zone on site (June 85). Worker nearly overcome with fumes from sampling
leachate (June 86). Case illustrates impacts of apparently common illegal disposal of
drilling muds and related production wastes throughout the Kenai peninsula. UNOCAL
has been directed on several occasions to remove gas condensate wastes from site. Case
has been actively under review by state since 1981. (AK 01)
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