Introduction

This report describes a visit to several gas well sites in the Fayetteville Shale on August 9, 2007. 

I met with George Sheffer, Desoto Field Manager for SEECO, Inc. (a large gas producer in 

Arkansas). We talked in his Conway, Arkansas, office for an hour and a half about the processes 

and technologies that SEECO uses. We then drove into the field to some of SEECO’s properties 

to see first-hand what the well sites looked like. 

Purpose of the Field Visit

In 2006, the U.S. Department of Energy’s (DOE’s) National Energy Technology Laboratory 

(NETL) made several funding awards under a program called Low Impact Natural Gas and Oil 

(LINGO). One of the projects that received an award is “Probabilistic Risk-Based Decision 

Support for Oil and Gas Exploration and Production Facilities in Sensitive Ecosystems.” The 

University of Arkansas at Fayetteville has the lead on the project, and Argonne National 

Laboratory is a partner. 

The goal of the project is to develop a Web-based decision support tool that will be used by midand small-sized oil and gas companies as well as environmental regulators and other 

stakeholders to proactively minimize adverse ecosystem impacts associated with the recovery of 

gas reserves in sensitive areas. The project focuses on a large new natural gas field called the 

Fayetteville Shale. 

Part of the project involves learning how the natural gas operators do business in the area and the 

technologies they employ. The field trip on August 9 provided an opportunity to do that. 

Fayetteville Shale

Unlike more traditional oil and gas fields that hold hydrocarbons in porous rock formations, 

shale holds natural gas in a fine-grained rock matrix. Until recent years, most shale formations 

were not considered profitable areas for gas production. With new technology and elevated 

natural gas prices, companies have made the Barnett Shale play in north Texas one of the hottest 

production fields in the country. Encouraged by the success in the Barnett Shale, operators 

looked at other large shale formations. The Fayetteville Shale play spans much of the northern 

and central portions of Arkansas. The Fayetteville Shale ranges in thickness from 50 to 325 ft 

and ranges in depth from 1,500 to 6,500 ft. The Arkansas Oil and Gas Board shows the locations 

of all the gas wells in the Fayetteville Shale play on its Web site (http://www.geostor.arkansas.

gov/apps/aogc/index.htm). 

Area Visited during the Field Visit

During the August 9, 2007, trip, we drove through Conway and Van Buren Counties, located 

north and west of Little Rock. After leaving the town of Conway, which was heavily developed 
6 

with commercial activity, we drove mostly through rural and agricultural areas. Route 65 is a 

four-lane road leading north from Conway. After about 45 minutes, we exited onto two-lane 

paved roads, which make up the main road network in these areas. At times, we turned onto 

some of the numerous “county roads” that were unpaved and had dirt and gravel surfaces. An 

example is shown in Figure 1. Those county roads were not designed to accommodate heavy 

traffic of large trucks and other oil field machinery. 

Figure 1 – View of typical “county road” that is the primary route used to get 

to gas well sites. 

How Does SEECO Produce Natural Gas?

This section of the report describes the steps followed in producing natural gas. I did not 

personally observe all of the steps during the field visit. However, I did talk with Mr. Sheffer 

about how SEECO conducts each step in the process. 

Leasing: The first step toward producing natural gas involves gaining access to the property 

under which the prospective natural gas resources are located and on which surface facilities will 

be located. Unless the operator owns the mineral rights for a piece of land, the company must 

lease the mineral rights from the owner. A lease is a legal agreement that allows the company to 

explore for and produce gas from a tract of land in exchange for paying royalties. Leasing does 

not require petroleum technology or fieldwork. Therefore, it is outside the scope of this project. 
7 

Seismic Surveys: Companies can make educated guesses about which tracts of land within a 

field hold recoverable natural gas. Before making large financial investments, however, they 

typically perform seismic studies that help in characterizing the size, shape, and depth of the 

formations most likely to hold recoverable natural gas. SEECO uses 3D seismic technology. 

When conducting a seismic study, contractors utilize trucks and helicopters to move equipment 

into the field and collect data. The contractors drill a grid of 20-ft-deep holes and place an 

explosive charge of 1 lb of dynamite into each hole. The charges are detonated under controlled 

conditions, and the resulting vibrations are detected by a network of seismic sensors. 

SEECO has an in-house geophysical group to analyze the data collected in the field. Mr. Sheffer 

did not have detailed familiarity with seismic methods and technologies, but noted that I could 

have a further conversation with Mike Rhoads, the head of SEECO’s geophysical department. 

During the field visit, we passed a seismic crew working in a field several hundred meters back 

from the road. We also observed several long cables crossing the road, which were connected to 

seismic sensors in fields on the opposite side of the road. 

Mr. Sheffer noted that in some heavily wooded areas, SEECO’s field teams would hand-cut trees 

and bushes to clear access ways for seismic lines rather than bulldozing. This is somewhat more 

labor intensive, but it creates less environmental impact. 

Well Drilling: After the company has identified a desired location for a well, it obtains permits 

to drill a well and construct a reserve pit (a pit located next to the drilling rig to catch the drill 

cuttings, used drilling mud, rainfall, and other materials). Before drilling can begin, the company 

clears vegetation and constructs a pad for the drilling rig and other equipment used in preparing 

the well and an access road to get from the county road to the well site. SEECO pays a use fee to 

the landowner for disturbing an area of 500 ft by 500 ft, plus the area of the access road. In 

practice, SEECO generally clears only 300 ft by 250 ft for the pad and the reserve pit plus two 

adjacent smaller “rig ditch pits,” which collect fluids that fall onto the footprint area beneath the 

rig. SEECO lines the pits with a plastic liner and covers the pad and access road with gravel. 

Figure 2 shows the gravel pad at a recently completed well site. Figure 3 shows the gravel access 

road, Figure 4 shows the reserve pit, and Figure 5 shows one of the adjoining rig ditch pits. 

Next the well is drilled. Oil and gas wells are constructed with multiple nested concentric layers 

of pipe known as casing (an entire length of casing is known as a casing string). The top interval 

is drilled starting at the surface and has the largest diameter hole. After a suitable depth has been 

reached, the hole is lined with casing that is slightly smaller than the diameter of the hole. Then 

cement is pumped into the space between the wall of the drilled hole and the outside of the 

casing. Next, a smaller diameter hole is drilled to a lower depth. Another casing string is 

installed to that depth and cemented. This process may be repeated several more times. The final 

number of casing strings depends on the regulatory requirements in place at that location. It 

reflects the total depth of the well and the strength and sensitivity of the formations through 

which the well passes. 
8 

Figure 2 – Newly constructed well showing gravel pad. 

Figure 3 – Gravel access road. 
9 

Figure 4 – Reserve pit. 

Figure 5 – Rig ditch pit. 
10 

SEECO drills a relatively large diameter hole from the surface down to about a 40-ft depth. This 

is lined with large casing called conductor pipe; the conductor pipe is cemented in place. Next 

SEECO uses an air-drilling rig to drill a hole to about a 500- to 550-ft depth. Surface casing is 

installed and cemented in place. SEECO continues with an air-drilling rig to drill deeper until the 

hole is about 600 ft above the top of the shale. 

At this point, SEECO moves in one of its larger conventional drilling rigs (according to 

Mr. Sheffer, the company has 11 of its own rigs in the area) to drill the horizontal section. The 

larger rig uses drilling mud to lift cuttings from the well, lubricate the drill bit, and to serve other 

functions. Using the larger drill rig allows SEECO to deviate the well (i.e., instead of drilling 

vertically, the well bore curves off at an angle). Figure 6 shows three diagrams of directionally 

drilled wells. Nearly all of SEECO’s Fayetteville Shale wells are horizontal wells that reach out 

laterally thousands of feet. Initially, wells were constructed with 2,200 to 2,500 ft of lateral 

reach. More recently, the wells are completed out to 3,000 to 4,000 ft. SEECO also tries to drill 

multiple wells from a single well pad, thereby minimizing surface disturbances. 

Figure 6 – Examples of directionally drilled wells. (Source: DOE 1999, 

“Environmental Benefits of Advanced Oil and Gas Production Technology,” 

DOE-FE-0385, U.S. Department of Energy, Office of Fossil Energy, 

Washington, D.C. Available at http://www.osti.gov/bridge/product.biblio.

jsp?osti_id=771125)
11 

Figure 7 shows a drilling rig in the process of drilling a well. 

Figure 7 – Drilling rig. 

Figure 8 shows a blue drilling motor on the pipe rack. Unlike the rest of the straight drill pipe in 

the background, the drilling motor has a slight curvature. It is placed on the leading end of the 

rotating drill string and gradually bends the well bore until the desired angle is reached. 

Many of the horizontal sections of SEECO’s wells are drilled using water-based muds (WBMs). 

When WBMs are used for drilling, the drill cuttings are placed in the reserve pit. At the end of 

the drilling job, the cuttings are stabilized with fly ash and then are buried in place after all 

liquids have been removed. Figure 9 shows a reserve pit that has been reclaimed by burial at the 

end of the drilling job. The used WBMs are disposed of using land application. 

In some of the wells toward the eastern side of SEECO’s leases in the Fayetteville Shale, the 

formations are more difficult to drill. There, SEECO uses oil-based muds (OBMs) to drill the 

horizontal sections. Because OBMs pose more environmental risk than WBMs, any wells drilled 

with OBMs use a closed system of tanks rather than putting muds and cuttings into a reserve pit. 

At the end of drilling a well with OBMs, the OBMs are recycled, and the cuttings are hauled 

offsite for disposal, typically at a municipal landfill, with permission from the landfill operator. 
12 

Figure 8 – Downhole drilling motor. 

Figure 9 – Reclaimed reserve pit. 
13 

Preparing the Well for Production: A newly drilled well must be properly completed to allow 

gas to enter the well and move to the surface. In a well that has casing along the gas-producing 

section, holes or perforations (“perfs”) are made in the casing using small explosive charges or 

guns. The perfs allow gas to enter the well. 

Because shale gas is held within a nonporous medium, it is necessary to fracture the shale so that 

gas has a conduit or pathway to move from the shale to a production well. The fracturing process 

(a “frac job”) injects water, sand, and other ingredients at very high pressure into the well. The 

high pressure creates small fractures in the rock that extend out as far as 1,000 ft laterally away 

from the well. The vertical extent varies but is related to the thickness of the shale layer. After 

the fractures are created, the pressure is reduced. Water can be removed from the well (“flowback water”), but the sand grains remain in the rock fractures, effectively “propping” the 

fractures open and allowing the gas to move. Fracturing is a critical step in producing the 

Fayetteville Shale wells. 

Previously, SEECO used nitrogen foam as its “fraccing fluid.” It found that wells fracced in that 

way did not produce the fracture system the company hoped to achieve. SEECO now uses “slick 

water” — water with some surfactant additives to help the flow-back water return from the well 

at the end of the frac job. 

SEECO conducts its frac jobs in stages. The length of the horizontal section of the well is 

divided into several sections by plugs. The outermost section is fracced first. First water is 

injected at increasingly higher pressure until a pressure chart shows that the bottom-hole pressure 

makes a sudden drop, indicating that the rock has fractured. At this point, sand is added to the 

injected water and the pressure is maintained until a desired dimension of fraccing is completed. 

The plug separating the last from the next-to-last section is sealed, and the frac job is continued 

for that section. The entire frac job may take a day and uses 50,000 to 80,000 bbl (2.1 to 

3 million gallons) of water and 1 to 1.5 million lb of sand. Operators try to avoid hauling such a 

large volume of water across unimproved county roads. When local water supplies are available 

within a mile or two, SEECO will pump water for the frac job. SEECO is building a series of 

dams near its wells that can capture stormwater for future use as frac fluid. Figure 10 shows a 

temporary pipeline built to convey water from a pond to the well site. 

Even without numerous tank trucks carrying water, the pad area at a well being fracced is 

crowded with heavy equipment. The service companies conducting the frac job will bring 

multiple engines and pumps, monitoring vans, frac tanks for making the frac fluid mixture and 

for capturing flow-back water, sand hauling trucks, and other support equipment. Figures 11 

through 16 show a well in the midst of a frac job. 

Immediately following completion of the frac job, the water used as part of the frac fluid begins 

to come back out of the well at a rate of 100 to 150 bbl per hour. It declines over time. This flowback water is collected in 500-bbl frac tanks and is either reused or disposed of. 
14 

Figure 10 – Water pipeline conveying water for a frac job. 

Figure 11 – Trucks lined up at the site of a frac job. 
15 

Figure 12 – One of several sand-hauling trucks in the center. 

Figure 13 – A row of frac tanks. 
16 

Figure 14 – Sand storage tanks. 

Figure 15 – The well being fracced is in the middle, with the pipe conveying 

the injectate. The two trucks beside the well are pumping units. 
17 

Figure 16 - The well being fracced is behind the white crane. The other 

wellhead near the middle of the picture was fracced on the previous day. In 

this case, two wells were constructed at the same well pad. 

When the frac job is finished, SEECO brings in a coiled tubing rig to drill out the plugs that 

separated the sections of the horizontal leg of the well. Then a workover rig is used to install 

production tubing. 

Water Management: Water is generated in three ways — ground water, flow-back water, and 

produced water. First, as the well is drilled with air drilling rigs, the borehole passes through 

shallow water-bearing formations. A substantial amount of water collects in the wellbore. 

SEECO is working with the Arkansas Department of Environmental Quality (ADEQ) to capture 

this water and treat it with an aluminum-based flocculant. If the chlorides concentration is less 

than 1,500 ppm, ADEQ allows the water to be applied to roads for dust control. 

As mentioned in the previous section, a large volume of water is used to make up the frac fluid. 

Much of the water flows back out of the well immediately following the frac job. A significant 

volume comes out of the well at a slower rate over an extended period of time. Mr. Sheffer noted 

that the Fayetteville Shale generates very little produced water (i.e., water naturally in the shale 

rock along with the gas). The combined water flowing out of the well when the well is producing 

gas is a blend of flow-back water and produced water. If this production-phase water has a 

chloride concentration less than 5,000 ppm, it can be sent to a land application site. If the 

chloride concentration exceeds 5,000 ppm, the water must be transported to distant commercial 

disposal wells. The cost of disposing of the high-chloride water, including transportation can 

exceed $6/bbl, a very high cost. SEECO has recently drilled some of its own water disposal wells 
18 

that are closer to its active sites. Active well sites generally have water storage tanks onsite. 

Figure 17 shows a water storage tank. 

Figure 17 – Water storage tank at well site. 

Well Production, Maintenance, and Closure: Gas initially flows to the surface by reservoir 

pressure. If necessary, later in the life of a well, SEECO plans to install plunger lift systems to 

produce the natural gas. 

SEECO estimates that the life of these wells is 20 to 30 years. If production declines in a few 

years, SEECO would consider additional frac jobs to restimulate the well. When the well reaches 

the end of its productive life, SEECO plans to plug and abandon the well in accordance with the 

prevailing state requirements at that time. 

Sending Gas to Market: Natural gas is produced at the wellhead (Figure 18). It moves to a 

metering station at the well site (Figure 19) and then is transferred to SEECO’s sister company 

that handles gas sales. 

SEECO has constructed a series of underground gathering lines at each well site that connect to 

larger gas pipelines running along some of the county roads. Figures 20 and 21 show workers 

connecting sections of pipe in a trench near a site where active well drilling was occurring that 

day. 
19 

Figure 18 – Wellhead. 

Figure 19 – Gas metering station at a producing well site. 
20 

Figure 20 – Worker connecting pipeline sections. Pipeline corridor can be 

seen in the background. 

Figure 21 – Workers splicing plastic pipeline and connecting a junction line 

in the field. 
21 

Production Information

Within a few days following the field visit, the Oil & Gas Journal published a short article1

giving some production statistics for Southwestern Energy Co., SEECO’s parent company. Some 

of those statistics are provided in this section. 

The company has run 145 mi2 of 3D seismic through June 30 in the Fayetteville Shale play, and 

expects to reach 400 mi2 of 3D seismic by the end of 2007. Southwestern averaged a net 

production of 105 MMcfd (million cubic feet per day) in the Fayetteville Shale during the first 

half of 2007. As of June 30, 2007, Southwestern has drilled and completed 303 producing wells; 

246 of them are horizontal wells, and 219 were fractured using slick water fluid. 

During the April−June 2007 quarter, Southwestern drilled and completed 62 wells in the 

Fayetteville Shale play. The average cost for these wells was $2.9 million. The horizontal portion 

of the wells averaged 2,550 ft, but 10 of the wells had horizontal reaches greater than 3,000 ft. 

The average drilling time took 18 days. The last 10 wells completed with slick water frac jobs 

averaged initial production rates of 2.6 MMcfd. 

 

1 “3D Seismic Guides Arkoma Basin Fayetteville Play,” Oil & Gas Journal, August 13, 2007, p. 40.