Arctic Petroleum: Technology Development
CRS Report for Congress
Updated January 23, 2006
Bernard A. Gelb
Specialist in Industry Economics
Resources, Science, and Industry Division
M. Lynne Corn
Specialist in Natural Resources
Resources, Science, and Industry Division
Terry R. Twyman
Visiting Scholar in Economic Growth and Enterpreneurship
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Arctic Petroleum Technology Developments
Congressional debate over opening the coastal plain of the Arctic National
Wildlife Refuge (ANWR) on a portion of the North Slope of Alaska to petroleum
exploration and development is under way in the 109th Congress. Current law
prohibits such development in ANWR.
The North Slope is home to the two largest oil fields in North America and to
the largest U.S. oil field discovered in the last decade. The North Slope also is home
to a diverse, unique, and fragile ecosystem – resulting in extensive federal, state, and
local regulatory protection. Partly due to increased restrictions since the discovery of
Prudhoe Bay, operators have developed less environmentally intrusive ways to
recover arctic oil, primarily through innovations in several types of technology.
Seismic technology offers the exploration sector advanced analytical methods
that generate high resolution images of geologic structures and that help identify oil
and gas accumulations by looking for anomalies or hydrocarbon indicators in the
seismic data. Ice-based technology has been improved so as to better serve remote
areas during exploratory drilling and production. Computers now allow the
manipulation and interpretation of vast amounts of data, offering more precise well
locations, thereby reducing the number of wells needed to find hydrocarbon
Recent advances in drilling can reduce the footprint of petroleum operations in
arctic environments. New drilling bit designs, fluid formulas, and advanced forms
of drilling, such as extended reach, horizontal, and designer wells, permit drilling to
reach as far as five miles from a wellhead location and to drill around geological
barriers to find and develop hydrocarbon accumulations. Advances in drilling allow
less space for a drilling rig, and reduce volumes and weights of both equipment and
Production facilities are now more compact, with modules performing many
functions. A project goal of operators on the North Slope is zero discharge of solid
and fluid wastes. Production drilling techniques using slim hole technology, such as
coiled tubing and multilateral drilling, can contribute to smaller footprints, less
waste, and better recovery of hydrocarbons from each well.
Proponents of opening ANWR to energy development maintain that these
technologies substantially mitigate the effects on the environment of oil and gas
operations, and assert that the increase in domestically-produced energy would be
worth any minimal environmental impacts. Opponents counter that a facility of any
size would still be an industrial site and an intrusion on the ecosystem, and argue that
the need for gravel and scarce water, the permanent roads, ports, and airstrips that
would follow, and the unknown number of spills would destroy vegetation,
contaminate water resources, and interfere with wildlife.
Introduction and Overview..........................................1
Background and Scope..........................................1
Status of Exploration, Drilling, and Production Options................3
History of North Slope Petroleum Activities.............................5
Evolution of the Oil Industry on the North Slope.....................5
Prudhoe Bay Field.........................................6
Kuparuk River Field.......................................7
Exploration and Drilling: Lower-Impact Approaches.....................8
State of the Art for Determining Structure.......................9
2-D Seismic Data......................................9
3-D Seismic Data......................................9
Data Acquisition and Interpretation.......................10
State of the Art for Determining Type of Fluid..................10
Advanced Seismic Modeling............................10
State of the Art for Determining Reservoir and Source............11
Insulated Ice Pads.........................................12
Factors Limiting Use of Ice Technologies......................13
Exploration Technology Comparisons.............................14
Late 1980s Exploration Technology..........................14
Current Exploration Technology.............................15
Advanced Drilling Technology..................................15
Extended Reach Drilling (ERD) and Horizontal Well Drilling..17
Drill Bit Technology and Drilling Fluid Systems................17
Drilling Technology Comparisons................................18
Drilling Paradigm in the Late 1980s..........................18
Production Methods: Reduction in Physical Presence.....................20
Compact Facilities or Central Processing Facilities (CPF).............20
Zero Discharge of Solid and Fluid Wastes.........................20
Improved Production Drilling...................................21
Slim Hole Drilling........................................21
Coiled Tubing Drilling (CTD)...............................21
Comparison of Production Technology............................22
Production in the Late 1980s................................22
Current Production Technology..............................23
Gains from North Slope Experience..............................23
Exploration Within ANWR.....................................25
1983-1985 Oil and Gas Exploration Programs..................25
List of Tables
Table 1. Exploration and Drilling Technology...........................4
Table 2. Production Technology......................................5
List of Figures
Figure 1. Conventional and High Performance Wells Used in Drilling
Figure 2. Map of the 1002 area of the Arctic National Wildlife
Arctic Petroleum Technology Developments
Introduction and Overview
Background and Scope
Congressional concern over high oil prices, growing U.S. dependence on oil
imports, budgetary pressures, and maintenance of the Alaskan oil infrastructure has
revived discussion over possibly opening part of the Arctic National Wildlife Refuge
(ANWR) to oil and gas exploration and development. That part is a 1.5-million-acre
area called the “coastal plain” — the so-called 1002 area. Among the arguments put
forward by proponents of opening ANWR is that there would be a much smaller
surface impact, or footprint, from the petroleum industry’s presence compared with
procedures, operations, and equipment discussed in the 1987 Final Legislative
Environmental Impact Statement (FLEIS) on the Refuge prepared by the Department
of the Interior.1 Current law prohibits petroleum and gas development in ANWR.
Some environmental impact is unavoidable with industry activity. Searching
for oil and gas involves drilling into the earth with heavy equipment; and various
facilities and other activities are necessary to support such drilling. The downscaling
of petroleum equipment and operations and the advanced technological solutions to
exploration, drilling, and production difficulties have reduced these impacts,
however. Improved exploration and development technologies that have become
more widely available include advanced seismic data analysis, ice-based technology,
slim hole and high performance drilling techniques, and methods to reduce waste.
Such innovation also is a factor in addressing the economic obstacles to finding
and developing hydrocarbons. Technological advance has more than doubled
exploration success rates and markedly improved drilling and production
performance and efficiency. Petroleum industry worker productivity has increased2
and the industry indicates that the potential impact of oil and gas operations on the
arctic environment has decreased.3
1 U.S. Dept. of the Interior, Fish and Wildlife Service, U.S. Geological Survey, and Bureau
of Land Management, Arctic National Wildlife Refuge, Alaska, Coastal Plain Resource
Assessment, Report and Recommendation to the Congress of the United States and Final
Legislative Environmental Impact Statement (Washington, DC: 1987), 208 p.
2 U.S. Dept. Of Labor, Bureau of Labor Statistics. “Industry Productivity and Costs,”
[data/bls.gov/PDQ/servlet/SurveyOutputServlet] viewed on February 27, 2005.
3 See description of the Alpine field on page 7.
Of course, use of the new technologies in ANWR or elsewhere significantly
depends upon the nature of the requirements for exploration, development, and
production, and on oil prices.
The policy issue of whether ANWR should or should not be opened to oil and
gas development is not addressed in this report. For more information on ANWR
controversies and legislation, see CRS Issue Brief IB10136, Arctic National Wildlife
Refuge (ANWR): Controversies for the 109th Congress. Similarly, the report does not
discuss in detail possible effects on the biological environment of industry
operations, or the use of the new technologies in light of regulatory requirements for
pipeline construction, spill containment, and reclamation of exploration and
production sites.4 Discussion and analysis of some of these matters can be found in
CRS Report RL31278, Arctic National Wildlife Refuge: Background and Issues.
However, to put the technology developments — the focus of this report — in
perspective, the report’s initial section summarizes some of the concerns expressed
by opponents of development in the Arctic National Wildlife Refuge, as well as
some of the benefits of ANWR development offered by proponents.
Exploration and drilling technologies are discussed next, as exploration is the
first step toward commercial production of hydrocarbons. After successful drilling
of an exploration well or wells, there are a variety of technological options available
to the industry for starting the development of the discovery. Production
technologies that make it possible to effectively recover the hydrocarbons will
complete the technology discussion. The report also compares the procedures and
potential environmental effects described in the 1987 FLEIS report with today’s
available procedures and their possible impacts.
While it can be reasonably argued that advanced arctic petroleum technologies
substantially mitigate the environmental impact of oil and gas operations compared
with how North Slope Alaska oil was developed originally, it also is contended that
the use of natural resources such as gravel and water, the probability of spills, and the
loss of wilderness as a result of human intrusion are issues that technology advances
Gravel would be used in development of the 1002 area — at least for things
such as main pads, airstrips, and connecting roads. Mining the gravel might result
in local changes in topography; roads may have to be built to transport the gravel to
exploration and production sites; and there would be a direct loss of coastal plain
habitat due to secondary effects of gravel spray, dust deposition, and altered snow
melt and erosion patterns stemming from facility construction and gravel mining.
Very large quantities of water will have to be used for various activities, such as
drilling, ice road and ice pad construction, and support of camp facilities, including
human consumption. Water probably would have to be transported into the area.
4 Because most fields discovered on the North Slope are still producing, there is limited
experience with restoration measures. However, reclamation sites are being identified and
procedures, such as use of microorganisms and plants for cleanup, are being investigated.
The long-term effects of winter exploration, drilling, and production operations
are unknown. Summer erosion and melting of permafrost may due to the heat
generated near productions sites. Tundra may be destroyed around the perimeter of
insulated ice pads. Compaction, destruction, and delayed growth of vegetation may
occur around ice pad production sites. And even minor spills may cause some
destruction of vegetation, contamination of waters, and mortality of small food
organisms. Surface disturbances probably would be numerous, with production
facilities connected by a gathering network or a system of pipelines to an existing or
a future pipeline; and production and related equipment may have to be staged at
another location over the summer months, then transported to the field during the
winter. The use of ice roads may be limited by hilly topography.
On the other hand, oil and gas development of the Refuge, it is argued, could
yield possibly significant gains in energy security and economic benefits.
Development supporters contend that ANWR oil would reduce U.S. dependency
upon foreign petroleum, create jobs in Alaska and elsewhere in the United States,
generate tax revenues, extend the economic life of the Trans Alaska Pipeline System,
and possibly lower oil prices. These potential benefits are discussed and analyzed at
length in CRS Report RL31278, noted above, and in CRS Report RS21030, ANWR
Development: Economic Impacts.
Status of Exploration, Drilling, and Production Options
The petroleum industry has accelerated the introduction and use of new
technology for operations in the harsh Arctic environment since 1987, the year the
Department of the Interior released the FLEIS with its recommendation to drill in
ANWR. Tables 1 and 2 summarize the increasing availability of these technological
changes since 1987. Some technologies are reported to have gone from the
embryonic stage (white) to the mature stage (black). The shades of gray indicate that
technology is characterized by a continuum of application and integration by the
industry. Four of the now mature technologies were in early stages of
commercialization in 1987.
Explanation for Tables 1 and 2Embryonic and emergingtechnologies are those first supported
Technology Status in 1987 and Todayby scientific fundamentals and
theory, and then introduced to
Embryonic technologyindustry as technology. Transfer to
and initial testing of the technology
Emerging technologyby industry characterizes a growth
Growth technologytechnology. As the technology isused, it may or may not prove to be
Technology with a tracksuccessful to the industry. If the
recordtechnology is successful, repeated use
establishes a track record. In the
appropriate situations, mature
technologies become common operating procedures.
New exploration technologies (Table 1) give petroleum geologists a clearer
picture of underground structures and fluids before drilling begins, and thus reduce
the need for exploratory drilling. The use of ice roads during the winter and insulated
ice pads during the summer can reduce surface disturbance, and high performance
drilling can reduce surface footprint of industry operations and waste generation.
Table 1. Exploration and Drilling Technology
Technology 1987 2005 Improvement
Determination of Structure and Fluid
Advanced 2-D seismic data Fewer dry wells
3-D offshore seismic dataFewer wells or dry wells
3-D land seismic data
Determination of Fluid
Advanced seismic modelingFewer wells
Determination of Reservoir and Source
Advanced geologicalFewer wells and less waste
Data acquisition by satellites
Ice roads Roads thaw in the summer,
avoiding permanent damage to
tundra; less movement ofInsulated ice pads
Advanced Drilling Technology
High performance drillingSite size for drilling 25% smaller
(e.g., 65 acres at Prudhoe, 8.7 at
Kuparuk); gravel surface area for
production pads cut 76%.
Production technology that is more available than in 1987 (Table 2) requires
fewer workers, less land, and less waste than earlier production methods. Subsequent
sections discuss all of these technologies in greater detail.
Table 2. Production Technology
Technology 1987 2005 Improvement
Compact facilitiesControlled remotely with fewer
people, less land, and modules
can be reused
Zero discharge of solid andNo reserve pits; 95% recycling
fluid wastesof all associated wastes (office
Slim Hole drillingEquipment is smaller and less
waste is generated
Improved production drillingFewer wells, smaller units, less
use of drilling fluids, and less
drilling waste generated
Advanced production drillingSmaller drilling units
Sources for Tables 1 and 2: Discussion in the text.
History of North Slope Petroleum Activities
The North Slope is home to the two largest developed oil fields in North
America; and it has the largest oil field discovered in the United States in the last
decade. Logistical barriers posed by harsh environmental conditions — such as
extremely low temperatures, freezing and thawing of the tundra, and remoteness —
have limited but not prevented exploration, drilling, and production in this region.
Evolution of the Oil Industry on the North Slope
There has been interest in and geological exploration of the petroleum potential
of the 65,000-square-mile North Slope coastal plain — 11% of the land area of the
state of Alaska — since about 1906. Federal exploration of the North Slope can be
documented for 50 of the last 80 years, beginning in 1923; and industry exploration5
has been continuous since 1958. A description of the exploration that has taken
place within ANWR in particular is presented in the appendix to this report.
The possibility of petroleum in the subsurface was hinted at by the presence of
oil seeps and oil-stained rock at the surface. Mining claims were staked on the seeps
5 For maps of the North Slope areas under discussion, see
[http://www.wilderness.org/images/images-other/map_AK_NS_leases.jpg], and Fig. 1.1.1-1,
and Fig. 2.4.6-1 in the Final Alpine Satellite Development Plan Environmental Impact
Statement EIS, found at [http://www.alpine-satellites-eis.com/alpeis.nsf] on Feb. 15, 2005.
outside of ANWR in the early 1900s but never fully exploited. Oil seeps and oil-
stained rock also were found within the coastal plain of ANWR. From 1944 to 1953,
the Navy conducted a program in the Naval Petroleum Reserve #4, now the National
Petroleum Reserve-Alaska (NPRA). There, 37 wells were drilled to test 18 structure
types that appeared prospective for hydrocarbon accumulation. Three oil and seven
natural gas fields, all uneconomic, were discovered.6 Although uneconomic
quantities of petroleum were found, this federal exploration program supported the
conclusion that the North Slope had most of the elements of a major petroleum
province. The information from the federal exploration program combined with
subsequent economic studies indicated that profitable operations could be conducted
on the slope despite the remoteness and harshness of the area, and several companies
began North Slope exploration in 1958.
Three fields illustrate different methods of exploration and development in the
Arctic environment. Prudhoe Bay, discovered in 1968 with production starting in
1977, Kuparuk River, discovered in 1969 with production beginning in 1981, and
Alpine, discovered in 1994 and placed into production in 2000.
Prudhoe Bay Field. Prudhoe Bay is the largest known oil field in North
America. In 1968, reserves were estimated at 9.6 billion barrels of oil and 29 trillion7
cubic feet of natural gas. With advanced technology, estimated original reserves of
oil (taking into account past production) have increased to14 billion barrels.8 With
no current economic means of getting the natural gas to markets, there has been little
or no incentive to produce gas or pursue reserve estimation.
The subsurface hydrocarbon accumulation at Prudhoe Bay spans 125,000 acres.
Six central production facilities (CPF) are used to separate oil from the gas and
water. Extensive gravel roads branching off of a main gravel road 30 miles long and
30 feet wide connect the various development well pads. Waste treatment facilities
and an airstrip are included at the main operations center. A central power station
running on natural gas from the field provides all power to the facility.
Between 1977 and 1987, the field produced about 1.5 million barrels a day of
oil. All wells were vertical or directional wells. Production began to decline in 1989,
and the field was producing only about 680,000 barrels per day by early 1999. In
anticipation of the decline in production, the first production horizontal well was
drilled in November 1985. Horizontal wells generally have higher production rates
and produce greater quantities of oil and gas than conventional wells because the well
encounters more of the reservoir rock. Exploration is still occurring around the
Prudhoe Bay field, with exploratory wells drilled each year to test outlying potential
6 Morgridge, Dean L. and William B. Smith, Jr., Geology and Discovery of Prudhoe Bay
Field, Eastern Arctic Slope, Alaska in Stratigraphic Oil and Gas Fields – Classification,
Exploration Methods, and Case Histories,” American Association of Geologists Memoir 16
(1972), p. 489-501.
7 U.S. Dept. of Energy, Alaska Oil and Gas: Energy Wealth or Vanishing Opportunity? (Jan.
8 Alaska Dept. of Natural Resources, Division of Oil & Gas, 2004 Annual Report (Dec.
petroleum accumulations. Production from North Slope and fields in southwest
Alaska, once about two million barrels per day, now is about 900,000 barrels per day.
Kuparuk River Field. The second largest producing oil field in the United
States, the Kuparuk River unit (with satellite fields) is estimated to have had 2.9
billion barrels of reserves. It was deemed economic for development in 1977 after
completion of the Trans Alaskan Pipeline. It is producing about 160,000 barrels per
day, with estimated remaining reserves of 1.0 billion barrels.9
About 2,000 wells have been drilled to fully develop the Kuparuk River field;
all are directional or horizontal. Kuparuk’s three major field installations are central
production facilities, which include a water desalinization plant for use in production.
The salt is mixed with water that is produced during oil production, and this mixture
is injected into appropriate zones in the subsurface. Project goals were to reduce
costs and to reduce the environmental impact of industry activities. The landfill for
Kuparuk-associated solid wastes is 50 miles away, and hazardous wastes initially
were shipped 2,000 miles. Advances in recycling and a 95% reduction in
construction and waste material at Kuparuk River won the U.S. Environmental10
Protection Agency’s (EPA) Evergreen Award for Pollution Prevention in 1999.
Alpine Field. Alpine field, with initial reserve estimates of 365 million barrels
of oil, was discovered in 1994, but not declared commercial until October 1996 after
field work and delineation drilling were completed. The delineation effort included
six wells, all drilled in the winter. Reserve estimates increased to 429 million barrels
of oil as a result of data from the wells and a 3-D seismic survey. With the increase
in the estimated size of the reserves, 112 horizontal wells instead of 94 conventional
and directional wells were used to develop the field. Alpine started producing
approximately 40,000 to 50,000 barrels of oil per day in November 2000.
During construction of the two drilling pad sites, equipment (e.g., 4,800-ton
modules used for living quarters, power plants, and processing facilities) was stored
at the Kuparuk River field during the spring and summer, then moved to the Alpine
site by ice roads during the winter. The ice roads melted during the spring and
summer months with no evidence of long-term damage to the tundra.11 The drilling
pad sites and the central processing facilities are on two gravel pads linked by a
gravel runway/road. Operations at Alpine are similar to the operations on an offshore
platform for the warmer summer months of the year. More than 350 truckloads of
equipment are pre-positioned at Kuparuk River field during the winter months to
make Alpine self-sufficient. Drilling solids and fluids and other waste are ground up,
mixed with water, and injected underground.
9 Alaska DNR, 2004 Annual Report, Tables IV-1 and IV-3. The 2005 report was not
available at this writing.
10 U.S. Environmental Protection Agency, Region 10, “1999 Evergreen Award for Pollution
Prevention, ARCO Alaska - Kuparuk River Oil Field,” Environmental Fact Sheet, (Nov.
11 Beez Hazen, Northern Engineering & Scientific, “Use of Ice Roads and Ice Pads for
Alaskan Arctic Oil Exploration Projects,” NPR-A Symposium Proceedings (Anchorage, AK:
Apr. 1997) [http://aurora.ak.blm.gov/npra/sympos/html/paper3.html], viewed Jan. 10, 2005.
Now operated by ConocoPhillips, the field has continued to be actively
developed, with production rising to an average of about 120,000 barrels per day in
January 2005.12 In December 2004, the Bureau of Land Management and the Corps
of Engineers approved development of two satellite drill sites containing five drill
pads. About 28 miles of gravel roads will be added to the existing three miles of
roads to allow movement of equipment, supplies, and personnel.
Exploration and Drilling: Lower-Impact Approaches
Petroleum exploration starts with interpretation of geological and geophysical
data to predict hydrocarbon potential. The different possible interpretations of that
data lead to an estimate of the geologic risk. Then, the economic implications of
these interpretations, the economic risk, is evaluated by the company and an overall
risk is estimated before it is decided to drill an exploratory well.
Advanced techniques in seismic data interpretation allow a geophysicist to “see”
and to interpret the likely presence of hydrocarbons thousands of feet below the
surface. These highly quantitative techniques use advanced mathematical modeling.
With the technology available to them, they work toward avoiding the costs (and
environmental damages) of unnecessary wells during exploration for and production
of hydrocarbon fields.
The use of advanced exploration techniques has contributed to the more than
doubling of exploration success — the percentage of new field wildcat wells drilled
that find any amount of hydrocarbons — since the 1980s.13 Higher success rates
mean fewer wells drilled, and because there are fewer wells, there may be less impact
on the environment. However, especially in sparsely explored regions, exploration
carries a high risk of dry holes despite the advanced techniques. The process of
evaluating exploration is important because the most probable outcome of an
exploratory well is a well without sufficient quantities of economically recoverable
hydrocarbons. Quantifying this risk is a fundamental part of the petroleum business.
There are three common factors in ascertaining geologic risk. For petroleum to
be present, a structure is needed to concentrate hydrocarbons; reservoir rock is
needed to hold hydrocarbons; and source rock is needed to form hydrocarbons.
Geologists and geophysicists try to determine if these three factors are present. If
hydrocarbons are thought to occur in sufficient quantities, an exploratory well may
12 Kristin Nelson. “Alpine field hits one-day production of 128,363 bpd,” Petroleum News,
week of February 6, 2005.
13 The success ratio of new-field wildcat wells in 2004 was 47.5%, compared with an
average of 17.9% in 1980 to 1982. American Petroleum Institute. Basic Petroleum Data
Book, August 2005, Section III, Table 1.
The advanced techniques used to identify and characterize the geologic and
geophysical opportunities for commercial quantities of petroleum are described
below. These techniques help improve predictions of the potential for the presence
of the three factors: structure, reservoir, and source.
Exploration is the prospecting for accumulations of resources, but because it
goes beyond discovery in extending the known limits of the accumulation, it is a
much broader term than prospecting. Today, the oil and gas success rate in areas
with little data is 20%-25%, but historically, that success rate has been 10%.14 This
increase in the success rate is due to advanced technologies that have improved the
mapping of structure and identification of reservoir rock and has improved the
determination of finding hydrocarbons.
State of the Art for Determining Structure. Seismic data, either two
dimensional (2-D) or three dimensional (3-D), are the data most geophysicists in
petroleum companies use to interpret the subsurface structure and fluid type of
improved 2-D seismic data acquisition and interpretation techniques more accurately
identify subsurface features or structures. Data resolution resulting from better
designed seismic surveys and better models that interpret data make 2-D seismic data
viable in areas with little data and limited access. Today, almost all companies rely
on 2-D seismic for interpreting structure and for selection of exploratory well sites.
3-D Seismic Data. The first offshore 3-D seismic survey was acquired and
interpreted in 1975-1976, and, since then, the application of 3-D seismic techniques
has significantly improved success rates. Success rates as high as 47% to 70% have15
been recorded in offshore areas. The use of 3-D seismic data on land and in areas
with little data is growing, and the appropriate application of land 3-D seismic data
may lower exploration costs and improve data accuracy.
Costs have been lowered in offshore 3-D seismic acquisition, but costs on land
are up to 75% higher. Initially too expensive for small independent operators, 3-D
seismic data in offshore areas are now routinely used by independent operators in the
offshore areas of the United States and Europe. In 1989, only 5% of the wells in the
Gulf of Mexico were based on 3-D seismic data, and the cost for a 50-square-mile
14 Anthony B. Hayward, “Exploration Frontiers for New Century Determined by
Technology, Politics,” Oil and Gas Journal (Dec. 13, 1999), pp. 42-44; Charles Stabell and
Norman Sheehan, “Competitive Advantage in Petroleum Exploration,” Oil and Gas Journal
(Apr. 23, 2001), pp. 30-35.
15 E. O. Nestvold, “Overview – The Impact of 3-D seismic data on exploration, field
development, and production,” SEG Geophysical Developments Series, No. 5, American
Association of Petroleum Geologists and the Society of Exploration Geophysicists (1995),
survey was $8.0 million. For the same 50-square-mile survey, the cost was reduced
to $90,000 in 2000.16 3-D seismic surveys require more seismic crew members at the
survey site; consequently, 3-D seismic is more expensive and disruptive to the
environment than 2-D.
Data Acquisition and Interpretation. Difficulties in onshore seismic
acquisition and interpretation include ownership of the surface rights, physical and
geomorphological barriers, and difficulties in interpreting the data as a result of
attenuation or weakening of the data because the sound signal can be absorbed by the
upper layers of the Earth and is converted to heat instead of an echo. In Alaska, 3-D
seismic surveys have been acquired in the NPRA and in areas surrounding the
producing fields on state lands.
because seismic work results in the mapping of structure in the units of time that it
takes the sound echo to reach the surface. Converting the time recorded to the depth
from which that echo is generated involves integrating geological data from wells,
if available, and advanced processing and mathematical modeling. Characterizing
the type and properties of the reservoir rock and identifying fluid type, such as oil or
gas, is improving, but seismic data cannot yet routinely determine if a rock is a17
source of petroleum.
Recent advances in interpreting seismic data in permafrost regions enable the
use of winter-acquired seismic data. 3-D seismic acquisition in the 1002 area18 of
ANWR (see Figure 2) would not be hindered by ownership conflicts in many cases,
as most surface rights are owned by the federal and state governments. In addition,
northwestern ANWR is relatively flat with very few physical barriers.
State of the Art for Determining Type of Fluid. Seismic data not only are
used to interpret subsurface structures that have the potential to contain
hydrocarbons, but the technique also is routinely used to identify and estimate the
amount of hydrocarbons contained in reservoir rock.
Advanced Seismic Modeling. Acoustic waves or energy are sent through
the subsurface and the echos generated from rock intervals have velocities that are
interpreted from the seismic data. These velocities depend on the rock properties and
the type of hydrocarbon that fills the holes in the reservoir rocks. Gas and oil
generate different velocities that generally have a specific amplitude. The amplitudes
generated from a given fluid will have different strengths and can be used as
16 U.S. Dept. of Energy, Office of Fossil Energy, Environmental Benefits of Advanced Oil
and Gas Exploration and Production Technology (Oct. 1999). (Hereafter cited to as DOE,
Environmental Benefits of Advanced Oil and Gas Technology.)
17 John T. Smith. “Petroleum system logic as an exploration tool in a frontier setting,” The
Petroleum System - From Source to Trap, L.B. Magoon and W.G. Dow, eds., American
Association of Petroleum Geologists Memoir 60 (1994), pp. 25-49. This article also
describes the methodologies for determining the possibility of a source rock in a basin.
18 This portion of ANWR is named after §1002 in the Alaska National Interest Lands
Conservation Act (ANILCA, P.L. 96-487); the section required a study of the area.
hydrocarbon indicators (HI). HI can be detected in both 2-D and 3-D seismic data,
and can identify the type of fluid present. In addition, HI are used to predict the
thickness of the reservoir and hydrocarbon volumes.
In unexplored regions, identifying a hydrocarbon may be difficult because of
uncertainty of the significance of the echo velocities. Well data increase the
knowledge of the velocity differences of various rocks, and HI analysis may be used
with high degrees of success. HI analysis is commonly used in areas that have high-
resolution 2-D or 3-D seismic data to indicate the presence of petroleum.
Analysis of ANWR Oil Seeps: Oil seep data together with advanced modeling
techniques can ascertain the possibility of finding just oil, just natural gas, or both oil
and natural gas. Oils that have naturally risen to the surface (oil seeps) in the 1002
area have been analyzed and suggest that one rock formation is the most likely source
for oil in the 1002 area. However, none of the oils sampled at the surface is similar
to Prudhoe Bay oil. This formation is capable of generating oil and gas or just gas,
depending upon the depth to which it has been buried by younger rocks. The best
technology to use in exploration may be determined by the type of hydrocarbon.19
State of the Art for Determining Reservoir and Source. Advanced
geological models and satellite data provide geologists with improved techniques
with which to interpret data more completely and to reduce the number of
exploratory wells that may have to be drilled to find hydrocarbon accumulations.
Geologic Models. Geologic models, with the input of data from exploratory
wells, have improved the accuracy of predicting the distribution and types of
reservoir and source rocks in a given area. In addition, these models are used to
convey reservoir rock properties to engineers and geophysicists during field
development. Advances have been made in: computer power, speed, and accuracy;
remote sensing via airplanes and satellites; image-processing technology; and
satellite gravity and radar data. These technologies help geologists interpret surface
and subsurface data more completely; manage, visualize and evaluate larger volumes
of data simultaneously; and more accurately communicate the interpretations. The
tools commonly used today are global positioning systems (GPS), which accurately
locate data points, and geographical information systems (GIS), which manipulate
and display the data.
Satellite Data. Optical satellite imagery has been the dominant source of data
for identifying and mapping onshore geology since 1970, when the first Landsat
satellite was launched. Satellites can now “see” up to 20 feet below the surface of
the Earth. Additionally, early satellites required visible or near-infrared light to
collect data. Now, radar satellites emit energy at microwave frequencies, enabling
19 Anders, Donald E., Leslie B. Magoon, and Sister Carlos Lubeck. “Geochemistry of
Surface Oil Shows and Potential Source Rocks,” in Petroleum Geology of the Northern part
of the Arctic National Wildlife Refuge, Northeastern Alaska, Kenneth J. Bird and Leslie B.
Magoon, eds. U.S. Geological Survey Bulletin 1778, 1987.
them to acquire data under any atmospheric condition. Interpretation of light
frequencies from the surface of the Earth as measured by satellites may indicate oil
seeps and oil and natural gas seepage over undrilled hydrocarbon traps.
Ice-based technologies have reduced the need for permanent gravel roads in the
Arctic to move equipment and have allowed industry to conduct seismic operations
and to drill exploration wells in the winter with reduced impact on the physical
environment. Ice technologies substantially reduce the need for gravel structures
(with their high and long-lasting environmental impacts) at the exploration phase,
and may offer some advantages in the development and production phases as well.
However, use of ice technologies is constrained by the availability of fresh water,
hilly terrain, and rising winter temperatures.
Ice Roads. Ice road construction begins with the use of vehicles, called
Rolligons, with huge tires (and very low pressure on the ground) to transport and
stage equipment. Rolligons compact the ice crystals as they travel over the surface
of the frozen tundra, removing air and promoting further freezing of the ice. Snow
(collected along temporary snow fences) and fresh water are added to the surface to
increase the thickness of the ice. Also, ice chips are trimmed from frozen lakes to
increase the road thickness. A warming trend over the last 30 years has delayed the
start of ice road construction from mid-November to, usually, mid- or late December.
Insulated Ice Pads. Changing climatic conditions that have shortened the
time available for exploration have resulted in widespread use of insulated ice pads.
Drilling an exploratory well to 10,000 feet takes 90 to 140 days if no problems arise.
Problems can seriously delay exploration, as equipment may have to be demobilized
and transported to a storage area; and drilling operations would have to be completed
the following winter. Higher average temperatures from the Fall to the Spring on the
North Slope have restricted exploratory operations from over 200 days in the early
1970s to 75 to 110 days in recent years. Because of the economic and environmental
effects of short drilling seasons, industry attention in the 1990s focused on
lengthening drilling seasons — primarily through the use of insulated pads. A
drilling site is selected, a pad of ice is constructed toward the end of the winter and
covered with insulation over the summer months. Insulated ice pads about 400 feet
by 300 feet can be covered with wind-resistant insulating panels to preserve the drill
pad through the summer; the drilling rig is then moved to the insulated pad site the
following winter.20 A drilling season can then be increased by 50 to 70 days.21 But
even with this method, drilling seasons are shorter than they were 30 years ago.
If oil is not found in economic quantities, ice pads and roads are allowed to
melt, with little effect on plants under the ice. Where pads are maintained over a
20 British Petroleum Exploration Alaska built an insulated pad in March 1996 and,
reportedly, eliminated the time needed for demobilizing and mobilizing the rig. See M.J.
Stanley and Beez Hazen, “Insulated ice pad technology enables extended season drilling on
Alaska’s North Slope,” SPE Paper 35686, Society of Petroleum Engineers (1996).
21 DOE, Environmental Benefits of Advanced Oil and Gas Technology.
summer, environmental impact occurs if the tundra around the perimeter of the pad
thaws and is blocked from sunlight. In this case, the plants consume stored nutrients
completely and die. However, research is being conducted on designs to minimize
the perimeter impact. If economic quantities of oil are found, a gravel pad is
constructed to support long-term development and construction (and vegetation
underneath the gravel dies).
Factors Limiting Use of Ice Technologies. Several factors limit the use
of ice technologies. These include (a) the total amount of available fresh water, (b)
the distance from sources of fresh water, (c) the topography of the area, and (d) the
distance from staging areas.
The supply of fresh water is crucial to using ice technologies as melted saltwater
would kill underlying vegetation. The FLEIS noted that the supply of fresh water is
limited in the 1002 area and is confined to the surface and the shallow zone of soil
located above the impermeable permafrost layer.22 The Refuge receives an average
of six inches of precipitation annually. Most lakes are shallow and therefore freeze
solid in winter. A 1989 study found 255 lakes, ponds, and puddles within the 100223
area. Less than 25% were deeper than seven feet; only eight contained enough
unfrozen water to build a mile or more of ice road. A number of rivers and streams
exist in the 1002 area, and these, too, are usually shallow. Ice chips from lakes and
rivers can be used to supplement ice road construction. Each mile of ice road uses
an estimated one million gallons of liquid water that road builders typically transport
no more than 10 miles, as it may freeze before it is used. Water shortages might be
addressed with greater use of chipped ice scraped from lakes, and/or development of
new technologies using a desalination plant and a heated elevated pipeline.24
Ice road construction also may be limited by the area’s topography. Developed
areas on the North Slope (e.g., Prudhoe Bay, Kuparuk, and Alpine) are very flat,
facilitating ice technology, whereas the 1002 area is hillier, its drainage is better
established, and its vegetation is more woody than the wetland grasses that dominate
Prudhoe Bay and other developed areas. Foothills and the hilly portions constitute
45% and 22%, respectively, of the ANWR coastal plain. Where topographic relief
is high, the State of Alaska has allowed gravel roads in lieu of ice for safety reasons.25
Distance from developed areas or potential staging areas can also limit ice
technology. As noted, heavy equipment usually would be stored in the nearest
possible gravel staging areas, and once ice roads are finished, moved to the drill site.
If the distance for ice road construction is great, there will be delay in reaching the
drill site, thereby adding to costs. At the production phase, when still more
equipment must be moved, the cost of delay could rise further.
22 FLEIS, p. 13.
23 Internal FWS study by Steven Lyons, Chief Hydrologist, ANWR, cited in Wayt Gibbs,
“The Arctic Oil and Wildlife Refuge”, Scientific American (May 2001), pp. 62-69.
(Hereafter cited as Gibbs, “The Arctic Oil and Wildlife Refuge.”)
24 Gibbs, “The Arctic Oil and Wildlife Refuge.”
25 FLEIS, p. 18-19.
As noted above, solutions to these problems exist; if not (as in the case of
topographic limits on use of ice roads), gravel construction can be substituted.
However, if polar warming continues, use of ice technology may be limited still
further. Standards for cross-tundra travel are being changed to accommodate
industry needs, while still attempting to balance effects on tundra habitat.
Because it is regarded as a model of modern development, the history of the
Alpine field is relevant. Located along the border of the National Petroleum Reserve
-Alaska (NPRA), it is considered a model of “roadless” development because of the
short (three-mile) road connecting the two initial pads and the lack of connection
with the remainder of North Slope development, except in winter via ice road. As
noted earlier, however, the recent approval of five additional pads will add about 28
miles of gravel roads to the existing three miles, and create 1,845 acres of disturbed
soils. About 150 miles of roads would be built if the field is fully developed.26
In sum, ice technologies can significantly limit the footprints of development
in the exploration phase, especially in flat terrain, with corresponding benefits to
tundra vegetation. Experience at Alpine, however, suggests a somewhat more modest
mitigation role for ice technologies in development phases after exploration.
Exploration Technology Comparisons
Exploration today is much more efficient, with the use of advanced exploration
technology, than it was 20 years ago when the FLEIS was being prepared.
Late 1980s Exploration Technology. In its 1987 FLEIS, the Department
of the Interior assumed that additional surface geological work, or field studies,
probably would occur in ANWR in the summer months prior to exploratory drilling.
Access would be by helicopter, and actual ground time would be only a few hours.
The FLEIS assumed that additional seismic exploration, which would occur in
the winter, would take place to obtain more detailed information on subsurface
geology,. Use of equipment that generates sound waves by vibrating the earth
probably would be the preferred method, and DOI raised the possibility of requests
for authorizations to conduct 3-D seismic surveys. It also anticipated a large number
of seismic crews, because different companies would want to obtain data in different
areas using different acquisition parameters and techniques. Movement of equipment
was assumed to take place on ice roads crudely built by packing snow by all terrain
vehicles. Ice roads would be constructed of packed snow thick enough to protect the
vegetation mat. At that time, the Alaska Department of Natural Resources required
A single drilling season, from onset of construction through testing and
demobilization, was expected to be approximately 170 days. One moderately deep
26 Department of the Interior, Bureau of Land Management, Alpine Satellite Development
Plan Environmental Impact Statement. See Figure 2.4.6-1, Volume 3, Alternative F,
Preferred Alternative, and p. S-8, S-19, S-30 of Summary, at [http://www.alpine-satellites-
eis.com/], visited on Dec. 13, 2004.
well (less than 10,000 feet) could be drilled in one season. A well deeper than
10,000 feet would require two seasons. If two seasons were required, year-round
drilling or a second demobilization and mobilization would be required to continue
drilling the following season.
Drill pads were anticipated by DOI to be constructed of ice, excavated material,
gravel-foam-timber, or other possible combinations. A pad would be large enough
to hold a rig, camp, and facilities for storing equipment and supplies.
Current Exploration Technology. It is likely that field work still would be
required in ANWR, as it is the only method that allows the study of the vertical and
lateral relationship of the different rock types at the surface or outcrops that one
would expect to be potential reservoir targets in the subsurface. While the length of
time required in the field may not change, other work could be accelerated by faster
interpretation of many data sets and new remote sensing and positioning techniques,
compared to those available in the 1980s. Additionally, advances in computer
technology help make interpretation of field work more efficient. For example, over
the decade, some of the major petroleum companies have been using vast amounts
of outcrop-derived rock data from around the world to design and calibrate powerful
computer models to predict potential reservoir rock and its properties in the
subsurface of an area.
In ANWR, vibrators probably would be used to acquire the seismic data during
the winter. This type of seismic data equipment usually is the largest, heaviest piece
of equipment used by seismic crews, and requires special methods of transport. The
number of seismic crews in the field in a given area may well be about the same as
in other regions being explored, as seismic contractors may follow the common
practice of conducting seismic programs for multiple companies interested in
but 3-D seismic data are not commonly used to explore far from known hydrocarbon
fields. Their greatest value is in areas with sufficient data and in the use of the
production of a known hydrocarbon accumulation.
Depending on the kind of information needed, the geology expected, and the
type of terrain, 2-D seismic surveys can be customized to obtain the necessary
seismic data for exploration. Today, 2-D seismic data are of much higher quality
than even 15 years ago; and, if programs are laid out correctly, 2-D seismic data are
a valuable exploration tool.
Advanced Drilling Technology
Drilling is the only way to measure directly the amount of subsurface petroleum;
there is no substitute. It is possible for industry on the North Slope today to drill for
thinner and deeper reservoir targets with fewer wells, smaller drill rigs, and with less
fluid and solid waste than it was 20 years ago.
Directional Drilling. Directional drilling — accurately drilling through rock
layers in the subsurface at angles other than vertical while guiding a well-path to a
An introduction to drilling: the processespredefined target — involvesintegrating a complex set of
and terms. Drilling a well requires the use of
a drilling rig, which controls rotating pipe ortechnologies to solve technical,
drill pipe, on which a cutting tool, or drill bit,control, and safety problems. These
is attached. The drill bit needs to be lubricatedproblems can be related to
by drilling fluids, usually a natural or syntheticunexpected subsurface pressure
fluid called mud. Equipment can be placed onregimes and fluid types. As these
the bit to direct the location and movement ofproblems have been and are being
the bit. As the pipe rotates and cuts throughsolved, directional drilling has
the rock below the surface, it produces rockgained widespread acceptance. The
chips or cuttings, which flow to the surface inadvantages of directional drilling
the mud and placed in shallow, plastic-linedare:
holes on the drill pad, called reserve pits, or
reinjected into the subsurface. Evaluation tools
are used measure the rock characteristics. To!multiple wells can
preserve the well hole, or borehole, beingbe drilled from a
drilled, mud is used to hold back thesingle location,
subsurface rocks during drilling, and casing, orallowing easier
pipe, is placed in the hole to protect theconnections to
overlying rocks and the reservoir rocks.production
Casing also controls the flow of drilling fluidfacilities and less
and oil, gas, and water from the reservoir aftersurface disruption;
a part of the hole is drilled. The borehole also
is the conduit for petroleum and water from the!targets below
reservoir to the surface. If the flow of fluid up
the borehole is uncontrolled, a blowout (in theenvironmentally
least extreme case, a kick) occurs. Preventionsensitive areas can
techniques are used first to kill the well, or stopbe reached from a
the fluid flow. As a last resort, equipment, adifferent location
blow out preventer stack, BOP, or blind ramsup to five to seven
placed at or near the surface over the top of themiles away;
well-bore are used to stop the flow of fluids.
The direction of the borehole is the well path,!more of the target
and the equipment at the beginning of thereservoir formation
borehole at the surface is the wellhead. If thecan be accessed
well encounters hydrocarbons, the casing andfrom a borehole,
formation are perforated to allow
hydrocarbons to flow into the borehole to thereducing the
surface. Wells drilled from a commonnumber of wells;
borehole are called sidetracks.and
!in case of a kick
(see box), relief
wells can be drilled
at an angle to kill
Technology now allows wells to deviate from the vertical from a few degrees
to horizontal, depending on the subsurface geology and the environmental
constraints. Types of directional wells are extended reach, horizontal, and designer
or complex wells. (See Figure 1).
Extended Reach Drilling (ERD) and Horizontal Well Drilling. ERD
wells evolved rapidly in the 1990s, and generally are used to reach targets in
environmentally sensitive areas from fewer surface locations. ERDs have a
horizontal displacement of two to five times the vertical depth. Wellheads can also
be located closer to each other, allowing for easy hookup to production facilities. In
the late 1960s, ERD could reach out a little more than a mile. Now, ERD wells can
routinely go out about four miles, and five- to-seven-mile long ERD wells have been
successfully completed in the North Sea and China.27 The seven-mile distance
between the discovery and the confirmation well at Prudhoe Bay could have been
drilled by ERD from one location.
Horizontal wells are ERD wells drilled vertically to the desired depth and then
turned 90 degrees to continue horizontally through rock formations for up to five
miles. Drilling ERD and horizontal wells require specialized equipment such as
motors placed near the bit and equipment to stabilize the well-path. Because of the
difficulties of using standard evaluation tools in these wells, evaluation tools have
been developed that measure the rock characteristics at the drill bit while drilling.
Designer Wells. These are drilled with high precision at sharp angles, at
times less than 90° and even to a near circle. They are designed to reach small
targets, several small oil accumulations at one time, or to go around geological
barriers. Complex well drilling has been made practical by the use of 3-D seismic
data that allow reservoir engineers to plot subsurface features to within 10 feet, and
made possible by new technologies that allow tight turns with steel pipe.
The drilling of a well itself (see box on the previous page) has not been the
limiting operation in horizontal and ERD wells. The limitations are the physical
operations of working with long, non-vertical strings of steel pipe. As discussed in
the next section, drill bit technology and new drilling fluid systems have been
developed to help alleviate the problems of high performance drilling.
Drill Bit Technology and Drilling Fluid Systems. Advances in drill bit
technology and drilling fluids have improved drilling performance significantly by
allowing wells to be drilled more quickly.
Drill Bits. Greater efficiency during the drilling phase allows for shorter times
in an area. Extending the drill bit life at the bottom of the hole saves time. Bits such
as the polycrystalline diamond compact (PDC) bit provide for faster drilling and can
be used much longer. The PDC bit was introduced by General Electric in 1973. The
bits use cutters made of a thick layer of tungsten carbide impregnated with bonded
diamond particles. Diamond is 10 times harder than steel and is the most wear-
resistant material in existence.
Drilling Fluids. Drilling fluids, or muds, are essential to carry drill cuttings
of the rock to the surface, for maintaining pressure balance and stability in the open
27 DOE, Environmental Benefits of Advanced Oil and Gas Technology; C.J. Mason and A.
Judzis, “Extended-reach drilling – What is the limit?,” SPE Paper 48943, Society of
Petroleum Engineers (1998).
hole in the subsurface, for lubricating and clearing the down-hole cutting equipment,
and for preventing the influx of other fluids from the rock. Millions of research and
investment dollars have been spent over the last decade to improve the performance
of these drilling fluids, and to avoid problems caused by inappropriate fluids.
Three types of fluids are used in drilling: water-based mud (WBM), oil-based
mud (OBM), and synthetic-based mud (SBM). Because OBM is hard to handle and
to dispose, SBM is being developed to act like OBM without the environmental
problems. In developing of SBMs, operators are using other organic substances to
replace oil. SBMs combine the performance of OBMs, which cannot be discharged
on-site, with the easier, safer disposal of water-based muds.
Drilling Technology Comparisons
Drilling Paradigm in the Late 1980s. DOI described drilling as a large-
scale operation using heavy equipment confined to a localized area for an exploration
well, and spreading over multiple sites to delineate a newly discovered field. Drilling
typically was expected to be conducted during the winter for the exploration and
A typical drill pad including the reserve pit covered five to ten acres, which
included facilities to house 100-135 workers during construction and drilling of the
well. Reserve pits were excavated on the pad. The reserve pit generally covered 0.5
to 2.0 acres and was 10 to 20 feet deep. A flare pit or a vent system for excess gas
was also included on the drill pad.
Current Technology. Conventional vertical wells most likely would be used
for drilling exploratory wells in ANWR. If a potentially commercial hydrocarbon
accumulation were found, high performance drilling techniques likely would be used
to reduce the number and size of drill sites and allow drilling fewer delineation wells.
Probably. all wells would be drilled in the winter. Prudhoe Bay had 42 drill sites
constructed in 1971-1977 to develop the estimated 9.6 billion barrels of oil. If
Prudhoe Bay were developed with horizontal drilling only, 11 sites would be needed28
to develop an estimated 14 billion barrels of oil.
Temporary reserve pits, if needed for storage of well cuttings, would be
surrounded by walls of ice on the ice pad. According to ARCO Alaska, now Phillips
Alaska, cuttings would be transported to sites where they could be cleaned and could
be used for construction material. Cuttings might also be reinjected into special wells
for solid and fluid drilling wastes, if permitted.
28 DOE, Environmental Benefits of Advanced Oil and Gas Technology.
Figure 1. Conventional and High Performance Wells Used in Drilling Today
Reduction in Physical Presence
Production facilities are necessary to extract hydrocarbons through the life of
a field. They consist of airstrips, power plants, production pads, access roads,
flowlines, and crew offices and living quarters. New developments in production
field facility construction and maintenance and in production drilling techniques have
reduced the footprint of oil and gas operations and should reduce environmental
impacts. A by-product of both drilling and production advances has been the
reduction in oilfield solid and fluid waste volumes.
Compact Facilities or Central Processing Facilities (CPF)
Compact production facilities are transportable unmanned production facilities
that may be used to exploit remote accumulations in environmentally sensitive areas
such as the Arctic. Four elements common to these facilities are design integration,
equipment elimination, multi-use systems, and automation. The use of 3-D animation
graphics, borrowed from the automobile and airplane manufacturing industries,
allows for the design of compact facilities. 3-D graphics combine engineering design
and the different ways one would be able to construct the production modules. The
ability to “see” on a computer screen how the modules will function in the Arctic and
to instantly “see” the effects of suggested changes results in more efficient design and
construction of the facilities.
Zero Discharge of Solid and Fluid Wastes
The major drilling wastes are drilling mud, water produced along with the oil,
and drill cuttings. Drilling mud is pumped down a borehole into rock layers in the
subsurface containing enough pore space to accept additional fluids without inducing
cracks in the rock. The borehole must be adequately protected by casing strong
enough to contain the fluid in the rock that would flow into the borehole as a result
of the higher reservoir pressures. Currently, all liquid and all solid drilling and
associated wastes generated at the recently developed Alpine Field are disposed of
by injecting them into the subsurface. At Prudhoe Bay, all drilling wastes are treated
and reinjected into the subsurface. Associated wastes such as office paper and food
waste are burned on site and the ash is transported elsewhere for disposal.
Water almost always is produced together with oil, and the amount of water
increases as oil production from a given field decreases. Usually water and oil are
pumped to the surface for separation, but systems below the surface can now separate
oil and water. New down-hole separation technologies may be able to reduce the
amount of produced water by as much as 97% in some wells.29 Dual pump systems
at and above the reservoir level pump the oil and reinject the water into the
29 DOE, Environmental Benefits of Advanced Oil and Gas Technology.
British Petroleum Exploration Alaska built a prototype grinding and injection
facility that recycled cuttings into construction gravel in 1990. The facility also
ground associated operational wastes for subsurface re-injection. By 1994, refined
grind-and-inject technology enabled Prudhoe Bay operators to achieve zero surface
discharge of drilling wastes, eliminating the need for reserve pits. Additionally, in
1988, ARCO conducted a pilot project indicating that cleaned and processed drill
cuttings could be used safely as road construction material. The composition of the
cuttings is said to be very close in to that of native gravel and surface soils.
Improved Production Drilling
Over the past 100 years, industry has employed only two basic drilling rigs,
cable and rotary. Cable drilling is pounding a hole in the earth with a heavy rod to
depths of up to 7,000 feet. Rotary drilling with the use of surface-rotated, jointed
drill pipe, much like a household electric drill, is now used to drill into the subsurface
to much greater depths. Today, production drilling technologies allow for smaller
drilling units than conventional ones, contributing to reduced equipment size.
Slim Hole Drilling. Slim hole drilling has been used in one form or another
by the oil and gas industry since 1960 as a way of reducing costs and improving
exploration and drilling results.30 Slim holes are 3- 4.25 inches in diameter, while
conventional holes are 8-10 inches at the bottom of the well. A slim hole drill rig
uses 97% less drilling fluid, generates one-third less cuttings volume, and has a 25-31
man drill crew instead of a conventional rig crew of 40. Transport of equipment
and rig can be by helicopter for easier access to remote areas.
Slim hole drilling also can be used in exploratory wells to gather cores from the
subsurface, and slim holes are used in improved production drilling techniques
discussed below. However, the shortcomings of slim hole drilling are poor methods
to keep fluids from escaping the borehole and the need for non-standard bits and well
evaluation tools. Also, if a drill pad were to benefit from slim hole drilling, all wells
on that site may need to be slim hole wells.
Coiled Tubing Drilling (CTD). Traditional rotary drilling rigs are as tall as
200 feet and include 30-foot portions of drill pipe that must be connected to increase
the length of the pipe as the well goes to greater depths. In CTD units, a large drum
containing a reel of seamless steel pipe that is quite flexible is used. CTD units drill
rock with the use of a motor on the bit to drive the coiled steel through the formation.
CTD drilling was used first on the North Slope in 1991.
Some of the advantages of CTD are:
!very little pipe handling and no drill pipe connections;
30 Petroleum Technology Transfer Council, Developments in Well Stimulation and Slim Hole
Technology, based on a workshop sponsored by PTTC’s Central Gulf Region on December
31 DOE, Environmental Benefits of Advanced Oil and Gas Technology.
!better control of fluids in the borehole, allowing for the use of
lighter, less toxic muds;
!noise at 45 decibels instead of 55 decibels;
!smaller sites (less than half) and less surface disturbance because it
is easier to handle the equipment during the preparation for drilling;
!less heavy equipment, lower fuel consumption and emissions; and
!no personnel necessary at the wellhead.
Disadvantages of CTD are:
!small diameter drill pipe is used and limits the utility for some
drilling objectives, such as exploration wells;
!the drill pipe cannot be rotated from the surface, mandating more-
advanced drilling practices and equipment; and
!the reel of coiled pipe is heavy and often difficult to transport and
Multilateral Drilling. Multilateral wells were first used in production drilling
on the North Slope in 1999. From a central borehole, additional boreholes are drilled
to different locations — branching from a common borehole. Because the secondary
boreholes share a central borehole, they can share the same surface facility.
Through-Tubing Rotary Drilling Wells. The most recent, and very
innovative, technology developed on the North Slope in years, is through-tubing
rotary drilled (TTRD) wells. With TTRD, a new well is drilled through the
production tubing of an older well as a multilateral well. Because the old tubing
doesn’t have to be pulled out of the ground by a drilling rig, a rig even smaller than
a CTD unit can be used for drilling. One of the benefits of TTRD equipment is that
the unit can be transported over ice bridges with stringent weight restrictions. These
benefits allow access to areas not open to conventional rigs and decrease the number
of surface drilling sites. However, the technology is useful only in areas where
production wells have been completed in the past.
Comparison of Production Technology
Production in the Late 1980s. The 1987 FLEIS evaluation assumed the
production facilities would be producing from a hydrocarbon accumulation of 35,000
acres in the subsurface. This accumulation was estimated to require 220 production
wells and 90 injection wells. Expected well spacing was 120 feet, requiring seven
20- to100-acre drill pads constructed of gravel and containing 40 to 50 wells on each
drill site. The production facilities posited would have included operations offices,
fuel and water storage, electrical power-generation units, solid and fluid waste and
The impact of petroleum operations on the surface was estimated in 1987 to
extend only to the size of the accumulation (i.e., 35,000 acres). DOI projected that
the subsurface size and shape of the productive field would define the areal extent of
the surface disturbance from the central production facilities. Directional drilling
from one pad site was posed as an option, and the directional wells were assumed to
have been drilled at angles up to 60°.
Peak production was assumed to be attainable in two to five years and to remain
at this level for three to eight years, with the productive life of the field projected at
20-30 years. While difficult to determine in the Arctic, about a 10 year time lapse
was expected from lease acquisition to initial production under optimal conditions.
The drill cuttings would have to be placed in a reserve pit (0.5 - 2.0 acres, 10 - 20 feet
deep) on the drill pad. Drilling muds would be reinjected into previous drilled wells,
and hazardous solids and wastes removed and held in a government-approved site.
Current Production Technology. Today’s production facilities are more
compact, with multi-faceted, multi-functional modules and production techniques.
Computer graphics now allow operators to plan a site and to make changes before
construction begins at the site.
The Alpine field is a 40,000-acre accumulation with operations including two
production drilling sites connected by a road/airstrip; these structures cover 97 acres.
Alpine field operations occupy only 0.2% the area of the hydrocarbon accumulation,
whereas Prudhoe Bay facilities occupy twice the area of the accumulation. Alpine’s
footprint is reduced by drilling all wells horizontally and from compact facilities.
Permanent drill sites can be much smaller today, partly because drill solids and
fluids are reinjected and not put in reserve pits. Multilateral wells and coiled tubing
wells drilled as slim hole wells require less mud and produce less waste. TTRD units
can be used to access hard-to-reach areas over light-load bridges and in seasons with
barely frozen tundra. Gas may not be flared, except for safety reasons, but can be
used in projects during production, and may be flared for safety reasons only.
However, today in Alaska, drill sites still would be constructed of gravel or
recycled cuttings from the exploration wells. Well cuttings may be treated and used
as construction material in place of gravel. Produced water today is greatly reduced
by improved production techniques. By 2001, more than 95% of the associated
operational waste were being recycled at Prudhoe, and operators at the Alpine field
had a project goal of zero discharge of all wastes.32
Gains from North Slope Experience
Thirty years of development experience on the North Slope have led to
considerable advances in exploration, drilling, and production operations, and a
reduction in the size of the footprint of petroleum operations in Arctic environments.
These advances, many of which are used at the Alpine field, would be available for
use in the 1002 area of ANWR, should it be opened by Congress.
Exploration success rates have improved dramatically, which probably would
mean fewer exploration wells. The use of 3-D seismic technology during the
exploration for hydrocarbon fields and the production stages of fields on the North
32 Personal communication with Dawn Patience, Phillips Alaska, at Anchorage, May 2001.
Slope enables geologists and geophysicists to be more proficient in interpreting
seismic data and in identifying the type of hydrocarbon. And the use of computer-
aided models results in fewer and better-placed wells.
Partly to protect the North Slope’s tundra, exploration operations are conducted
exclusively in the winter with extensive use of ice roads and all-terrain vehicles.33
Advances in seismic acquisition and processing techniques allow for permafrost
exploration using vibrating instead of explosive techniques.
Reductions in the size of production facilities have decreased the footprint of
more recent North Slope operations. The minimum spacing between onshore wells
has been reduced by about 80%, from 160 feet to 35 feet. An average production
drill site has shrunk about 85%, from 65 acres to fewer than 9 acres, and fewer dril
sites are needed with new high performance drilling techniques and production
drilling technology; and reserve pits have been eliminated or used on insulated ice
pads only temporarily.
North Slope operators are using advanced technology to manage drilling wastes
more effectively. Cleaned well cuttings can be used for construction material in
roads and other gravel structures. Grind-and-inject technology can enable 100% of
all drilling solid and fluid wastes to be injected into the subsurface, which eliminates
the need for reserve pits. Additionally, fewer wells drilled means that less solid and
fluid waste is generated.
There are supportable grounds for proponents of opening ANWR to energy
development to assert that the advanced technologies for oil and gas development in
the Arctic might significantly mitigate the effects on the environment of oil and gas
operations. But opponents assert that, notwithstanding technological improvements,
facilities of any size would be an industrial site and an intrusion on the ecosystem
that would use the area’s natural resources, interfere with wildlife, risk spills of
hazardous materials, and result in a permanent loss of wilderness. In the final
analysis, the issue of whether to open ANWR to energy development remains a
33 However, warming trends in the high Arctic have shortened the exploration season over
the last 30 years. The shorter season is now addressed by having two starting dates and two
stopping dates — a shorter season for heavy equipment, and a longer season for lighter
vehicles. In addition, studies (conducted jointly by federal and state agencies, as well as
academic experts) are underway to modify current standards for cross-tundra travel; these
may result in a further lengthening of the exploration season.
Exploration Within ANWR
Section 1002 (a) of, the Alaska National Interest Lands Conservation Act of
1980 (ANILCA) directed the Department of the Interior (DOI) to assess the plant and
animal resources and the hydrocarbon potential in 1.5 million acres of the coastal
plain portion of ANWR, referred to as the 1002 area. This assessment included
surface geological and geophysical work, but no exploration drilling.34
1983-1985 Oil and Gas Exploration Programs. Exploration crews from
15 companies visited the 1002 area during the summers of 1983-1985. Access by
helicopter was allowed, but no ground vehicles were permitted. The work was
monitored by the U.S. Fish and Wildlife Service (FWS), which observed no adverse
effects on fish and wildlife from geological field operations such as collection of rock
samples and mapping. The goal of the field work was to collect rock or outcrop data
to better understand the rocks that could be potential reservoir and source rocks.
However, the data to determine rock type and distribution in the area were from
outcrops covering only 4.0% of the 1002 area.
Seismic operations were permitted during the winters of 1983-1984 and 1984-
1985, when most wildlife species were absent or present in smaller numbers. As
seismic surveys are the only exploration technique involving mechanized surface
transportation, it posed the greatest possibility of adverse environmental effects. To
avoid significant adverse impacts, access was limited to one seismic contractor and
activities in acutely environmentally sensitive areas were restricted. The total
distance in straight and parallel tracks called line-miles in the 2-D seismic survey was
restricted to approximately 1,300 line-miles, which the FWS believed was sufficient
to identify potential areas for the purpose of the FLEIS report. Full-time FWS
monitors accompanied each seismic crew. The FWS effectively limited short-term
adverse environmental effects, but followup studies were planned to determine the
long-term impacts. It is unclear if such studies were carried out or published.
Petroleum Geology. ANWR’s 1002 area is between two known petroleum
provinces, the U.S. North Slope to the west and the Canadian Beaufort Sea and
Mackenzie Delta province to the east. Interpretation of the regional geological data
collected during the summers of 1983-1985 and more recent nearby well data by the
Bureau of Land Management (BLM) in 1991 and the U.S. Geological Survey in 1998
indicate that the rocks of both provinces may extend into the 1002 area (Figure 2).
34 For additional information, see U.S. Department of the Interior, Arctic National Wildlife
Refuge, Alaska, Coastal Plain Resource Assessment.
Figure 2. Map of the 1002 area of the Arctic National Wildlife Refuge.
hed line labeled Marsh Creek anticline marks the approximate boundary between the undeformed and the deformed areas established by the USGS in 1998. Fields and discovery
s are shown surrounding the 1002 area.
Arctic National Wildlife Refuge, 1002 Area, Petroleum Assessment, 1998, USGS Fact Sheet FS-040-98, May, 1998.
The approximate 1,300 line-miles of seismic data were reprocessed and
reinterpreted between 1987 and 1998. These data, in addition to the geological data,
were used in the 1991 petroleum assessments of ANWR by BLM and by the USGS
in 1998.35 In its 1998 study, the USGS divided the 1002 area into two areas based
on the type of geological structures or potential hydrocarbon traps. The first is a
structurally simple area called the undeformed area, and the second a more
structurally complex, more stressed area called the deformed area. The geological
sequence in the northwestern portion of the 1002 area, the undeformed area, is
similar to the sequence encountered within the North Slope, which includes the
Prudhoe Bay, Kuparuk River, and Alpine fields.
The southeastern deformed region of the 1002 area is more like the Canadian
Beaufort and Mackenzie Delta, which include more than 36 hydrocarbon fields
totaling 740 million barrels of oil and 10 trillion cubic feet of gas. Because of the
geologic complexity, selection, acquisition, and interpretation of data in the deformed
area is difficult compared with acquiring and interpreting data from the undeformed
area. If ANWR were opened, drilling and production techniques in the deformed
area would be different than in the undeformed area because of this complexity.
The determination of the existence of a source rock that can generate petroleum
is important before active exploration begins in a new area. The potential for rocks
to generate hydrocarbons is determined by the organic geochemistry of the rocks on
the surface or in the subsurface. The geochemistry of the outcrops, analyzed from
the outcrop samples taken in 1983-1985, indicate that five rock sequences sampled
in the 1002 area have the potential to generate oil and gas. Gas can be generated
from the same rocks that produce oil, but the rocks need to have been buried to
greater depths and higher temperatures. Gas can also be generated from rocks with
a different organic content than the oil-generating rocks. Only one of the five rock
sequences in the 1002 area is more prone to producing oil than gas. The other four
identified rock sequences are more likely to produce gas.36
35 U.S. Department of the Interior, Bureau of Land Management, Overview of the 1991
Arctic National Wildlife Refuge Recoverable Petroleum Resource Update (April 8, 1991);
and Arctic National Wildlife Refuge, 1002 Area, Petroleum Assessment, 1998, USGS Fact
Sheet FS-040-98 (May 1998).
36 Kenneth J. Bird and Leslie B. Magoon, eds, Petroleum Geology of the Northern Part of
the Arctic National Wildlife Refuge, Northeastern Alaska, U.S. Geological Survey Bulletin