Issues Concerning the Use of


united states             Horizontal Wells in the Injection of
Environmental Protection
Agency                 Carbon Dioxide for Geologic


                      Sequestration

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Office of Water (4606M)
EPA 816-R-10-007
November 2010
http://water.epa.gov/drink/

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 Issues Concerning the Use of Horizontal Wells in the Injection of Carbon Dioxide for Geologic
                                         Sequestration

1.0 Introduction

    Horizontal wells are wells drilled at an angle that deviates from the vertical by an angle approaching
    or equaling 90 degrees. Typically, these horizontal wells are directionally drilled using advanced
    drilling technologies. The horizontal portion of the well bore is generally drilled parallel to the
    bedding of the geologic formation, although the angle of deviation may vary depending on the local
    geology. Horizontal wells have been used in many applications including oil and gas production,
    enhanced oil recovery, coalbed methane production, hazardous waste remediation, and recently for
    geologic sequestration. (Hazardous waste remediation wells are typically shallow wells drilled in
    unconsolidated soil not exceeding a few hundred feet in depth. Therefore, they are not applicable
    to the situations that will be encountered in geologic sequestration and are not discussed further in
    this paper.)  This paper focuses on directionally drilled horizontal petroleum production wells, as
    they are most similar to wells that may be used in geologic sequestration projects.  A brief overview
    of the technology will be presented followed by a discussion of how horizontal wells differ from
    vertical wells and how those differences may affect the permitting and operation of carbon dioxide
    GS wells.

       1.1 History

       The first horizontal oil wells were drilled in the early to mid 20th century. Use of these wells was
       limited, until technological advancements, particularly in directional drilling techniques, began
       to reduce the costs and facilitated the use of horizontal well installation in the 1980s.  Use of
       horizontal well technologies  has increased since  then. As of December 2002, there were over
       17,000 horizontal wells drilled in the United States.  In general, decreasing costs have been the
       main factor in the increased  use of horizontal wells. Initially, well drilling costs were
       substantially higher for horizontal wells, with costs up to 7 times the cost of a vertical well (EIA
       1993). Advanced technology and experience have dropped the costs significantly.  Today,
       horizontal well costs are typically between 1.4 to 3 times the costs of a vertical  well and can
       approach equal costs as a crew gains experience in a formation (Joshi 1991, Knoll 2005). The
       cost differential per foot drilled also drops as the vertical well depth increases.

       1.2 Types of Wells

       A horizontal well can either be drilled as a new well or from an existing vertical  well; such a well
       is termed a re-entry well. Wells drilled as horizontal wells typically are drilled vertically to a
       point called the kickoff point, then angled toward the target formation, as shown in Figure 1.
       The deeper the kickoff point, the more difficult it is to control the direction of the well (Inglis
       1988). A horizontal well is drilled horizontally through the target formation, and it is generally
       possible to move the well bore up or down within a formation to take advantage of geologic
       features. A re-entry well is drilled in the same manner, but an existing vertical well bore is used
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as the starting point. A hole is drilled through the casing and the well bore is extended from
that point. Either type of well can have multiple laterals extending from a single starting point.
Examples of this type of well bore are shown in the rightmost panel of Figure 1 and in Figure 2.
Figure 1. Comparison of Horizontal and Vertical Well Types.
         Vertical Wells
           2000 - 2004
Stand-Alone
 Horizontal
 2004 - 2005
 Multi-Lateral
2005 - Present
Source: http://www.trident4-22.ca/index.php?page=pad-based-drilling
Figure 2. A Re-entry Horizontal Well
         Completion
             Slrinn
Source: http://www.aoc.co.ip/e/tec/tec-main.html


Horizontal wells are often categorized based on the turn radius or the build angle. The turn
radius of a horizontal well is the radius it takes the well bore to turn 90 degrees. The build angle
is the angle the well bore can turn in one foot. The build angle is equal to 90 degrees divided by
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the turn radius. Table 1 shows the different types of wells and their typical turn radii and build
angles.

Table 1. Categories of Horizontal Wells and Their Characteristics
Well Type
Ultra-short Radius
Short Radius
Medium Radius
Long Radius
Turn Radius (Ft.)
1-2
20-40
300 - 800
1,000-3,000
Build Angle (degrees/ft.)
45-60
1-2
0.06-0.2
0.02-0.06
Source: Joshi(1991)

Ultra-short and short radius wells are most common in re-entry wells and are useful on small
leases where large horizontal distances cannot be covered. They can be drilled relatively short
lengths. Medium radius wells are most common and are widely versatile. Long radius wells are
less common but can achieve great horizontal distances of 30,000 feet or more.

1.3 Applications

The main advantage of horizontal wells is that they enable a longer segment of the well
completion to come into contact with the target formation (since these targets are commonly
horizontal or nearly horizontal) and they have a smaller footprint for the above ground
operation. For production wells, this can lead to  higher production rates (since the oil or gas has
a shorter distance to flow to the production well) and for injection wells, this can allow lower
injection pressures and better injectivity. The method can also be useful to reach formations
that are under obstacles such as a river or a lake, or in heavily populated areas which make a
vertical well  impractical. Some common applications are:

              Fractured formations (instead of in porous media)
              Formations  with high water or gas production (coning)
              Low permeability formations
              Formations  that are thin in the vertical direction
              Formations  used for gas production and enhanced oil recovery

In enhanced oil recovery operations, several configurations are possible. An operation can use
horizontal injection wells with a vertical recovery well or it can use horizontal injection and
recovery wells.

Horizontal wells have also been used for carbon sequestration at Sleipner, Weyburn, and In
Salah, as described below:
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              The Sleipner project injects via a single horizontal injection well that is 12,310 feet long
               and 3,816 feet deep (saline aquifer CO2 storage). The well has a surface casing
               extending to 1,919 feet measured depth and a production casing to 7,831 feet
               measured depth, which marks the top of the injection formation (Baklid et al. 1996).
               The well is cemented for  8,530 feet along the well bore. The well is equipped with a
               downhole shut-off device.  Because the well injects wet carbon dioxide with some
               hydrogen sulfide content, the exposed portions  are constructed of 25 percent
               chromium (Cr) steel.
              The Weyburn project injects through 37 wells including several dual leg (i.e., two
               horizontal segments departing from a single well bore) horizontal injection wells (Basin
               Electric Power Cooperative 2009, White et al. 2004). The wells are approximately 4,600
               feet deep. The Weyburn field also  anticipates increasing the use of horizontal recovery
               wells (Bennaceur et al. 2004). In total the Weyburn project has 105 horizontal wells,
               including both production and injection wells containing 175 lateral legs.  The Weyburn
               project began using single leg horizontal wells and then moved to dual, triple, and
               quadruple leg wells. A typical single leg well has a kickoff point that is 4,500 feet deep
               with a 3,280-foot medium radius horizontal section. The well is typically cased to the
               kickoff point and then is left open hole after that.  The dual leg wells are kicked off from
               the horizontal portion of the first leg with the two legs typically running parallel.
               Quadruple leg wells add two more  parallel well bores in the opposite horizontal
               direction of the first two  well bores.
              The In Salah project uses three horizontal injection wells that are 6,000 feet deep in a
               60-foot-thick aquifer.

2.0 Overview of Technology

    Advances in horizontal well technologies, including drilling technology, logging and measurement,
    and completion technology, have increased the use of horizontal wells.

        2.1 Drilling Technology

        Traditionally constructed vertical wells are drilled by attaching a drill bit onto straight sections of
        drill pipe.  The pipe typically comes in 30 foot sections that are threaded or attached to each
        other, usually in two or three sections. The pipe is rotated at the surface on the drilling floor,
        providing the torque for the drill  bit. Drilling fluids are injected through the pipe and the
        assembly containing the drill bit and pumped up the annulus between the pipe and well bore to
        remove the rock cuttings. The same technique can be used to drill long radius horizontal wells.
        The difference is that with directional drilling technology the drill pipe is deflected to the desired
        angle using a variety of tools.  Jet drilling, whipstocks, and  "rebel bars" are among the
        equipment that can be used to bend the trajectory of the drill pipe (Inglis 1988).
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The increased use of downhole motors was one of the technologies that allowed horizontal
wells to become commonplace.  Downhole motors, sometimes called mud motors, are attached
to the bottom of the drill pipe and rotate the drill bit from the bottom of the hole instead of
having to rotate the entire drill pipe from the surface to the bottom of the hole.  Downhole
motors decrease the torque placed on the drilling assembly caused by rotating the drill pipe
through the curved portion of the well bore. They also allow finer control of the drill bit and its
direction.  Downhole motors also allow the use of coiled tubing in place of the traditional drill
pipe. Since downhole motors  do not require rotation from the surface,  rigid drill pipe is not
required.  Instead, coiled tubing, flexible tubing that comes coiled on large spools can be used.
The flexibility of the coiled tubing allows drilling at sharper angles than does rigid tubing. Also,
because the coiled tubing can  be fed into the hole continuously, the drilling does not have to be
stopped to attach new segments of drill pipe.  This greatly saves time and improves the
efficiency of drilling, which decreases costs significantly. Ultra-short radius wells can be drilled
using various types of jetting technologies.

2.2 Logging and Measurement Technology

Drilling horizontal wells with precision requires sophisticated measurement techniques. The
drill bit position is critical to ensuring that the well's course can be plotted and corrections can
be made, if necessary. Accelerometers and magnetometers are used for drill bit positioning.
These pieces of equipment supply deviation checks as required in the Class VI injection
regulations (146.87(a)(l)).  Other equipment is used as well to measure variables such as
temperature, pressure, weight on the bit, torque, drill speed,  mud volume, and type and
severity of vibrations. These instruments can provide pressure and temperature readings
required under 146.86(b)(l).  Signals are transmitted to the surface via mud telemetry, electro-
magnetic telemetry, or occasionally by hard wires run through the entire length of drill pipe.

In addition, advanced geophysical well logging equipment is now available to facilitate logging
while drilling. Logging instruments are capable of measuring properties of the formation during
drilling.  Instruments can measure spontaneous potential, gamma ray, seismic, sonic, resistivity,
and record photographic data  to provide information including formation density, porosity,
composition, and pressures. These instruments can provide information for both the resistivity
and cement logs required at 146.87(a)(2) and 146.87(a)(3).

Medium and long radius wells should also be able to accept the equipment and instrumentation
required to perform mechanical integrity tests required at 146.87(a)(4). As long as the well
bore is cased and cemented as required, pressure and tracer tests can be conducted.  The
equipment described in the previous paragraph can also be lowered into the well bore at times
other than drilling. Equipment to measure temperature, pH, conductivity, and perform video
inspections of the casing is also available. Therefore the full suite of mechanical integrity tests
described  in the GS regulation will be available for horizontal wells.
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2.3 Completions

There are three possible ways that the production zone of a horizontal petroleum recovery
(production) well can be completed:
              Open hole
              Slotted liners
              Traditional cementing and perforations
Open hole completions do not place any structural well components or equipment in the well
bore. This type of completion requires that the formation be stable enough to avoid collapse of
the rock formation into the well bore. It is a fairly common practice in short and ultra-short
radius wells.

Slotted liners are liners with pre-formed holes or slots which are inserted into the well bore.
They provide structural stability and can limit the amount of fine material entering the well.
They can be fitted with a gravel pack, which can further reduce fine particle production. Liners
will allow fluid in the annulus between the liner and the formation and therefore do not seal off
one zone from another. Packers can be inserted along the liner to provide isolation between
zones. Completions in this manner are not, however, amenable to well stimulation techniques,
such as hydraulic fracturing to increase formation permeability and injectivity.

Traditional cementing of casing in a horizontal well can be accomplished in medium and long
radius wells. Any cement  that can be used in a vertical well  may be used for medium and long
radius horizontal wells. The production casing and cement are then perforated using shaped
explosive charges. Cementing is necessary if the well is to be stimulated using fracture
techniques.  Under the Class VI rule, all stimulation, including hydraulic fracturing, must be
approved by the Director.  Owners or operators must submit a proposed stimulation program  as
part of the permit application under 146.82(a)(9); the plan must demonstrate that any
stimulation activities will not compromise the integrity of the confining zone. The oil industry
has established 6 levels of integrity for horizontal well completions (Charlez and Breant, 1999).
They are:

      Level 1 - Open hole for both the vertical section  and the horizontal well bores.
      Level 2 - Main vertical bore is cased and cemented with open hole horizontal bores.
      Level 3 - Main vertical bore is cased and cemented, horizontal bores are cased but not
       cemented.
      Level 4 - Both vertical and horizontal well bores  are cased and cemented.
      Level 5 - Both horizontal and vertical well bores  are cased and cemented, the junctions
       are hydraulically isolated using packers.
      Level 6 - The  horizontal and vertical well bores are cased and cemented, the junctions
       are an integral part of the casing.
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       Levels 1 and 2 are considered to have neither mechanical nor hydraulic integrity. Levels 3 and 4
       are considered to have mechanical integrity but lack hydraulic integrity. Levels 5 and 6 have
       both mechanical and hydraulic integrity and are necessary in situations where there is complex
       geology with multiple pressures, fluids, and strata. Class VI wells are required to be cemented to
       the injection zone (146.82(b)(3)), therefore they must have a minimum of either level 3 or 4
       integrity depending on whether the horizontal portion of the well is below the caprock or not.
       Of course, providing higher levels of integrity will provide increased protection against potential
       fluid migration.

3.0 Unique Considerations for the Use of Horizontal Wells

In many ways, the construction, monitoring, and maintenance of horizontal wells are very similar to
those of conventionally drilled vertical wells. In several areas, however, there are differences which can
affect activities such as well completion, well integrity testing, and well logging.

       3.1 Turn Radius

       The turn radius of a well (i.e., the deflection from the vertical of a well) influences the type and
       size of equipment that can be lowered into the well.  Longer, less flexible equipment requires a
       larger turn radius to successfully insert the equipment into the well. Although advances are
       continuously being made, generally it is not considered feasible to cement short and ultra-short
       radius wells (Joshi 1991).  The types of geophysical logging equipment that can be used in short
       and ultra-short radius wells are also limited. Medium radius wells  may limit the use of some
       larger pieces of equipment. However, technology has advanced to the point where most
       traditional activities such as logging and cementing can be carried out. In general, long radius
       wells can use any equipment used in traditional vertical wells.  Use of short or ultra-short radius
       wells may be an issue where there are very deep USDWs and it is undesirable to kickoff the well
       above the USDW. They may also be an issue if  land availability is limited, such as in  heavily
       populated areas or offshore platforms.

       3.2 Loads on Casing

       Casing in curved and horizontal portions of a horizontal well is subject to  physical loads not
       imposed on the casing of traditional vertical wells (Cernocky and Scholibo, 1995; Chen et al.
       1990). Extra stress is placed  on the casing through the angled portion of the well because of the
       bend of the casing.  Additional force can also be placed on the casing in the horizontal portion if
       the formation is unconsolidated or the formation collapses into the open well bore. The casing
       can also experience higher friction and torque  when being installed through the bend.  These
       factors necessitate careful design of the casing and may require use of stronger materials or use
       of casing with thicker walls to prevent damage.
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3.3 Formation Damage

During well drilling, drilling fluid can be forced into the surrounding formation along with
cuttings from the drilling. This can reduce formation porosity and decrease production from the
formation (for production wells) or the injectivity of the formation (for injection wells). While
formation damage is a consideration when drilling any well, it is a critical consideration in
horizontal well drilling, construction, and operation because of the longer drilling times and the
additional gravitational force on the fluids (Powell et al. 1995; Sabins 1990).

One technique that can lessen the damage to the formation is called underbalanced drilling.  In
traditional drilling, the pressure of the drilling fluid is maintained at a pressure slightly higher
than the reservoir pressure in order to prevent gas blowouts. In underbalanced drilling, the
pressure is maintained slightly lower than the formation pressure so that less drilling fluid is
squeezed into the formation. Some drilling fluids  may also lessen formation damage associated
with horizontal well  drilling. In addition, development techniques can be used to clean the
drilling fluids and cuttings out of the formation. Options for development include acid
treatment, mechanical scraping, and fracturing (Joshi 1991).

3.4 Cementing

During cementing of a horizontal well, solids can settle along the bottom portion of the long
horizontal segment of the well. This  can cause cement channeling and may result in an
inadequate cement job.  Free water in cement can also settle out and result in compromised
cementing.  It can also be more difficult to keep the pipe centered  in the well bore in horizontal
wells, and pipe eccentricities can be more frequent and lead to flaws in the cement job. For this
reason, it is important that the wellbore be cleaned of any drilling fluids or cuttings before the
cement job begins. The cement should also have no free water content, as determined by
conducting the American Petroleum  Institute free water test at an angle of 45 degrees or
greater (Joshi 1991).  Keeping the drilling fluid turbulent, using special drilling fluids, and
maintaining  consistent fluid velocities around the  pipe have been found to limit solids
channeling and result in better cement jobs (Powell et al. 1995; Lockyer et al. 1990; Sabins
1990). Centralizers can also be used  to keep the pipe centered in the well bore during
cementing. The Class VI regulation requires the use of centralizers to the injection zone, see
146.86(b)(3); supporting guidance will contain more details on the use and placement of
centralizers.

3.5 Mechanical Integrity Tests with Multiple Laterals

Pressure tests done for mechanical integrity require blocking off the casing to monitor for
pressure changes. This is not possible in laterals that are level 1 or 2 and are not cased.  In wells
with multiple, cased laterals, required mechanical integrity tests will be more complex, as each
of the bores will  need to be plugged.
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4.0 Potential Impacts of Horizontal Well Issues on Geologic Sequestration and Protection of USDWs

    Horizontal wells present some unique challenges and require specific considerations in comparison
    to vertical injection well construction and operation. When constructing, permitting, and operating
    Class VI wells, owners or operators and permitting authorities need to  keep these challenges in
    mind. All of these challenges can be addressed with proper well design and planning.

    Because short and ultra-short radius wells are not usually constructed with cement in place, owners
    and operators of these wells will find it impossible to meet the requirements to case and cement the
    well from the injection zone to the surface (146.86(b)(3)) unless the kickoff point for the well and
    the entire horizontal portion of the well lie entirely within the injection formation. These wells may
    also not be able to meet the logging and integrity testing requirements. Therefore, in general, short
    and ultra-short radius wells are not practical for use in Class VI wells. Medium and long radius wells,
    however, are more than capable of being cemented and accommodating logging equipment. Such
    longer radius wells should be able to reach the same points as short radius wells if owners or
    operators start the  kickoff point at a higher elevation.

    Horizontal injection wells may require stronger casing than vertical injection wells. Class VI
    regulations require that the cement and casing materials be of sufficient structural strength and last
    the life of the project (146.86(b)(l)).  For horizontal wells, this means that the well  will need to be
    designed to withstand additional forces from the rock column and from bending in addition to the
    traditional collapse, burst, compressive, and tensile forces used to design vertical  wells. Well
    designers should calculate these forces and include them in their designs.  Permitting authorities will
    need to consider these additional forces in determining that the strength requirement has been
    met.

    While formation damage can be a problem with horizontal drilling, it should not affect the integrity
    of the well or the containment of the carbon dioxide. It will only affect the injectivity (and the
    viability of the well for use in  injection).  Stimulation of GS wells, including hydraulic fracturing, may
    be permitted if injectivity is low. All stimulation techniques must be designed and monitored in such
    a way that the confining zone is not fractured (146.88(a)); 146.87(d)(l) requires that the fracture
    pressure of the confining layer be determined during the construction  of the well  before operation
    is allowed. Modeling programs exist which can calculate fracture lengths for hydraulic fracturing and
    can be used to design the fracture so the confining layer is not fractured.

    Pipe eccentricities, free water, formation damage, and solids channeling can lead  to poor cement
    jobs in horizontal wells. The use of centralizers, underbalanced drilling, and proper use of
    mechanical scraping and acid washes can eliminate many of these problems. As a practical matter, if
    existing horizontal wells are used for GS, they are likely not cemented from the injection zone to the
    surface,  but are likely cemented through USDWs.  In such cases, the well may need  to have
    additional cement placed to seal unsealed formations or to repair existing defects. The Class VI rule
    at 146.87(a)(3)(ii) requires submission of cement logs, which should show any defects that

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    occurred during cementing. The logs will give confidence that the cement job was completed
    satisfactorily.  Any defects found can be repaired using cement squeezes before the well is allowed
    to operate.

    If multiple laterals are used in horizontal wells, the laterals may complicate mechanical integrity
    tests. Each lateral will need to be cemented to perform the tests properly. To perform the tests, the
    owner or operator will need to isolate each lateral with packers and perform the test individually on
    that lateral.

    Table 2 presents a summary of requirements for Class VI injection wells and potential considerations
    and challenges that owners or operators of Class VI horizontal injection wells will encounter and
    address during well construction and operation.

    Table 2 Class VI Rule Requirements and Potential Considerations with Horizontal Wells.
Class VI
Requirement
Potential Considerations for Horizontal GS Wells
146.86
Construction
requirements
Solids channeling, formation damage, free water, and pipe eccentricities can lead
to poor cement jobs. Review of cement logs will be critical. Casing and cement
materials may need increased strength over vertical wells.

Short and ultra-short radius wells cannot meet the requirements to case and
cement the well from the injection zone to the surface.
146.87  Pre-
operational logging,
sampling, and
testing
Limited in short radius wells. No major issues in medium and long radius wells
although cement logs will be more important items to review in permit approval.

Deviation checks, MITs, and other logs required during drilling (at 146.87(a) and
(b)) can be performed using measurement-while-drilling and logging-while-
drilling techniques.
146.89
Mechanical integrity
Logging may be limited in short radius wells. Pressure tests not possible in
unlined horizontal portions. No issues with medium and long radius wells. More
complex with multiple laterals.

Equipment to measure temperature, pH, conductivity, and perform video
inspections of the casing is all available. The full suite of MITs required in the GS
regulation will be available for horizontal wells.
5.0 Summary

    While there are unique challenges associated with drilling and operating horizontal wells, use of
    horizontal wells for Class VI GS is technically feasible, and such wells may be used by Class VI well
    owners or operators in their GS projects. Owners or operators of technically sophisticated, Class VI
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horizontal wells may not be able to use some techniques such as short radius drilling. However,
with appropriate planning and well design, horizontal wells can and have been used for GS. Tools
such as logging while drilling, underbalanced drilling, specially designed cements, centralizer
placement, and cement logs along with proper design procedures will enable construction of wells
that can meet the Class VI regulations.
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6.0 References

Bennaceur, K., Monea, M., Sakurai, S., Gupta, Nv Ramakrishnan, T.SV Whittaker, S., and Randen, T. CO2
Capture and Storage - A Solution Within.  Oilfield Review: Autumn 2004, pp 44-61.

Baklid, A., R. Korbol, and G. Owren.  1996. Sleipner Vest CO2 Disposal, CO2 Injection into a Shallow
Underground Aquifer.  Presented at 1996 SPE Conference.

Basin Electric Power Cooperative.  2009.
http://www.basinelectric.com/Energy Resources/Gas/CO2 Sequestration/

Cernocky, E.P., and F.C.  Scholibo. 1995. Approach to Casing Design for Service in Compact Reservoirs.
Presented at SPE Conference

Charlez, P.A., and P. Breant. 1999. The Multiple Role of Uncoventional Drilling Technologies from Well
Design to Well Productivity. Presented at 1999 SPE Conference.

Chen, Y.C., Y.H. Lin, and J.B. Cheatham.  1990. Tubing and Casing Buckling in Horizontal Wells. Journal
of Petroleum Technology v. 42.

Energy Information Agency. 1993.  Drilling Sideways - A Review of Horizontal Well Technology and its
Domestic Application.

Inglis, T.A. 1988.  Petroleum Engineering and Development Studies: Volume 2 Directional Drilling.
Kluwer Publishers

Joshi, S.D. 1991.  Horizontal Well Technology. Pennwell Books, Tulsa, OK

Knoll, R.G. 2005.  Lessons from Canadian Natural Gas Horizontal  Wells. Presented at Petroleum
Technology Transfer Council 2005 meeting.

Lockyer, C.F., D.F. Ryan, and M.M. Cunningham. 1990.  Cement Channeling:  How to Predict and
Prevent.  Presented at SPE Conference.

Powell, J.W., M.P. Stephens, J.M. Scheult, T. Sifferman,  and J. Swazey. 1995.  Minimization of Formation
Damage, Filter Cake Deposition, and Stuck Pipe Potential in  Horizontal Wells through the Use of Time-
Independent Viscoelastic Stress Fluids and Filtrates. Presented at SPE Conference.

Sabins, F.L  1990. Problems in Cementing Horizontal Wells.  Journal of Petroleum Technology v. 42 #4.

SACS. Best  Practices Manual.
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White, D.J., G. Burrowes, T. Davis, Z. Hajnal, K. Hirsche, I. Hutcheon, E. Majer, B. Rostren, and S.
Whittaker. 2004. Greenhouse Gas Sequestration in Abandoned Oil Reservoirs: The International
Energy Agency Weyburn Pilot Project. GSA Today v. 14.
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