Issues Concerning the Use of 

Horizontal Wells in the Injection of 

Carbon Dioxide for Geologic 

Sequestration
Office of Water (4606M)

EPA 816‐R‐10‐007  

November 2010

http://water.epa.gov/drink/
1 

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. 

Source: http://www.trident4-22.ca/index.php?page=pad-based-drilling

Figure 2. A Re-entry Horizontal Well

http://www.aoc.co.jp/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 

Source: 
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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 Turn Radius (Ft.) Build Angle (degrees/ft.)

Ultra-short Radius 1 – 2 45 – 60

Short Radius 20 – 40 1 – 2 

Medium Radius 300 – 800 0.06 – 0.2

Long Radius 1,000 – 3,000 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)(1)). 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)(1). Signals are transmitted to the surface via mud telemetry, electromagnetic 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)(1)). 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)(1) 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 Preoperational 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-whiledrilling 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, N., Ramakrishnan, T.S., 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 TimeIndependent 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.