Years after successful drilling began in the prolific Barnett Shale, operators continue to increase activity and expand to new counties. Production from the play has been rocketing upward-some 2,210 wells are making approximately 800 million cubic feet equivalent of gas per day from the tight black shale. Technology has always been crucial to the Barnett play, as it is in most unconventional natural gas reservoirs. Unquestionably, that technology is still evolving. From its early days, the play has progressed from an emphasis on vertical drilling, cementing, fracturing and refracturing, to the present use of horizontal drilling and completion methods and 3-D seismic. Horizontal wells are the new focus for Barnett players. At press time, operators had filed 105 horizontal permits in 2003, a dramatic jump from the seven such permits requested in 2002 and three in 2001. Devon Energy Corp. has been the driving force in this effort. The Oklahoma City-based company drilled seven horizontal wells in the Barnett play in 2002, and has already drilled 43 of a total of 70 such wells planned for this year. "We have drilled 50 horizontal wells and 34 of those are on production at this time, making 51 million cubic feet of gas per day," says Brad Foster, vice president and general manager, central division. The interest in horizontal drilling is driven by the search to find new ways to exploit the Barnett, particularly in areas outside of the developed core. Core development The heart of the play is in southeastern Wise, southwestern Denton and northern Tarrant counties, Texas. It sits just north of, and overlaps into, the Fort Worth metropolitan area. The boundaries of the core development area are partly geologic and partly economic. Essentially, it is the portion of the Barnett where the reservoir is fairly thick, the gas is rich but not too oil prone, and where upper and lower fracture barriers are present. Inside the core, the traditional Barnett drilling and completion techniques work very well. The typical vertical well costs around $750,000 and recovers an average of 1 billion cubic feet of gas equivalent (Bcfe). In most places in the core area, tight limestones encase the Barnett and act as frac barriers, confining the energy of a stimulation treatment to the target zone. Devon Energy entered the play with its purchase of Mitchell Energy in early 2002. At that time, Devon acquired 800 Barnett wells producing 345 million cubic feet of gas equivalent per day. (See "Barnett Shale," March 2002, Oil and Gas Investor.) Almost immediately, Devon launched a vigorous infill-drilling program on its 120,000 acres of net leasehold in the core area. Today, it has 1,500 producing Barnett wells making 560 million cubic feet of gas equivalent per day. "We have nearly doubled the well count in the core area during the last two years," says Terry Shyer, Devon's central division manager of operations and production. "Our Barnett production has grown year over year, and we are still on a slight incline in total, but production from the core area is now flattening out." This year, the company expects to drill 260 vertical wells and 40 to 50 horizontal wells in the core area, in addition to drilling laterals in several existing vertical wellbores. In 2004, however, a reduced drilling program is planned. Devon is entering a transition period in the Barnett play, shifting its emphasis from vast vertical drilling programs in the core toward a more limited number of horizontal wells, both in and outside the core. For 2004, Devon has budgeted 30 vertical and 30 horizontal wells inside the core. "There are some additional areas where we will drill vertical wells, and we will also continue to do reentries and refracs on existing wells, but now we are focusing on areas outside the core." That's because Devon's core position is essentially developed within the limits of present technology. Devon has now drilled up most of its vertical locations on 40-acre spacing, and the majority of those that remain have surface issues or localized geologic problems. In these places, the overlying Marble Falls Lime or the underlying Viola Lime are present but not competent. One of two events occurs without proper frac barriers-the frac treatment goes into the deeper Ellenburger, which is very porous, permeable and wet; or the frac energy escapes out of zone and not enough of the Barnett is stimulated to make an economic completion. Horizontal wells are the technology of choice for exploiting these difficult areas. And to date, the technology has worked very well within the core. With horizontal wellbores, the frac treatments tend to extend laterally, limiting the vertical extent of the induced fractures and reducing the risk of fracing out of zone. "In the core, we drill some horizontal wells because of surface restrictions, and some because of geological problems. We also drill some to establish a baseline for horizontals outside the core," says Jeff Hall, manager of exploitation and exploration. "That lets us compare horizontal efficiencies in different parts of the play." Devon estimates that a typical horizontal well in the core, which has a single lateral between 2,000 and 3,500 feet in length, will cost about $1.6 million and recover 2- to 3 Bcfe of gas. Another technology bearing fruit for Devon is 3-D seismic. "There has been a real change in how we use seismic in the Barnett play," says Foster. Until recently, seismic was used to identify tectonically quiet areas. Experience taught the Barnett players that the best wells were made in unfaulted, homogeneous shales. "However, a lot of our leases occur in tectonically active areas, so we have done some additional processing," says Hall. Now, Devon applies seismic to strategically place wells in areas it avoided in the past. It is also using seismic data to help steer the direction of the laterals. And, the company is working on integrating seismic data into the completion process, to help design stimulations. Later this year and in early 2004, it plans to acquire a substantial amount of new seismic across the play. "We know that we only retrieve 10% to 14% of the gas in place in the Barnett Shale so we are focused on getting more of that gas out of the ground," says Foster. Beyond the core Devon holds some 430,000 acres in the Fort Worth Basin outside the core area, and it estimates that as much as 200,000 acres of that total are prospective for Barnett production. The key issue outside the core, although far from the only one, is the lack of a lower frac barrier. Vertical wells just don't deliver economic rates. Devon is experimenting with several solutions, including single-lateral horizontal wells, multilaterals and various fracing techniques. "We think these technologies will allow us to break into the expansion area," says Foster. The company is concentrating its formidable resources on figuring out the best way to exploit that position. Through the study of whole cores, rock mechanics and seismic data, it has been working intensely on the geology of the shale and the properties of the formations above and below it. Devon has also enlisted the aid of several major service companies and universities in its research and development efforts. "It's my belief that there is enough variety in the geology outside the core area that there will not be a single solution that's going to work everywhere," says Hall. "We're going to need different solutions for different areas. But, I'm confident that we will develop technologies that will allow us to develop a large area, if not all of it." At press time, Devon had drilled 12 horizontal wells outside the core, sampling the prospects in northern Denton, western Wise and northern Johnson counties, as well as on the Parker/Tarrant county line. Ten of those wells are currently on production, and by year-end it expects to have drilled as many as 30 horizontal tests. Essentially all of Devon's wells in the expansion area are single-lateral horizontals, except for a handful of vertical wells used to monitor completions. Results vary across a wide range. "Some of the wells are good and some are mediocre, and we haven't had any failures," notes Hall. "But, we don't have a lot of data yet and we're still trying to figure out the play." This year's wells will help Devon determine where to concentrate its 2004 drilling program, in which it plans at least 60 horizontal wells outside the core. A host of operators Although Devon is far and away the largest operator in the play, accounting for more than 80% of all Barnett production, many other companies have staked out significant positions. These range throughout the core and expansion area, with a number of firms concentrating in Tarrant, Parker and Johnson counties. Chief Oil & Gas, headquartered in Dallas, centers its activity on the Barnett. The firm is running five rigs and has drilled 150 Barnett wells, says Trevor Rees-Jones, president. Of these, 130 wells are producing 66 million cubic feet of gas per day, and another 20 wells are in various stages of drilling, completion operations or pipeline hookups. In 1999, Chief began leasing in Tarrant County, at what was then the southern edge of the Barnett play. Today this area, just north and northwest of Fort Worth, is very active. The company recently acquired Swift Energy Co.'s acreage position in Hill and Johnson counties, and it has also acquired leases in Parker County. Chief expects to spend more than $60 million in the Barnett play in 2003 and is budgeting a like amount for 2004. That level of capital will support drilling 80 to 90 wells a year, says Rees-Jones. Presently, Chief has 225 locations in inventory in the core of the play, not including locations in outlying Hill, Johnson and Parker counties. The firm of Hollis R. Sullivan Inc., based in Wichita Falls, is drilling both vertical and horizontal wells in the core. "The initial horizontal results look positive," says Sullivan, who is currently drilling a fourth horizontal well in Denton County. Sullivan owns leases in Wise, Denton, Montague, Tarrant, Hood, Johnson and Parker counties. Local independents, including Dallas firm Harding Co. and Fort Worth-based Burnett Oil, are working in western Tarrant and eastern Parker counties. Leasing there is highly competitive. In the initial years of the play, this area boasted just five active operators running eight rigs; today, more than 30 operators are running 60 rigs. "Most of the early wells were poor," says Robert Miller, exploration manager for Harding. "They were blamed by operators as being located west of the Viola pinch-out and thus having no lower frac barrier." In fact, in some of these areas, tight Simpson Lime and underlying tight Ellenburger form frac seals, and the Marble Falls lime provides an upper frac barrier. In Parker and Denton counties, Llano Royalty Corp., an Amarillo-based firm, plans to drill in excess of 150 Barnett wells in the next three years. "We like to focus on plays that have a large known gas resource in place, with a large areal extent and wells that exhibit steady decline rates," says Steve Looper, chief executive officer. Llano initially farmed in properties from Denbury Resources, with the help of Dallas-based Wellspring Partners, and it has continued to add to that base. The independent plans to drill 45 wells during the coming 12 months, 10 of which will be horizontal. "We will have an inventory of 300 drill sites by year-end, with a goal of increasing our inventory and expanding our reserve base." Llano's biggest challenge is drilling in urban environments, Looper adds. Many communities in the Fort Worth Basin have annexed huge chunks of land in anticipation of future growth, and have also adopted drilling ordinances that contain many requirements. "In these areas we have to begin the permitting process at least 90 days before spudding," says Looper. South of Fort Worth in Johnson County, EOG Resources Inc., Houston, expects to have up to four horizontal wells completed and production-tested by year-end. For the past three years, EOG has been accumulating acreage, predominately in Johnson County, and now holds approximately 90,000 leased acres. It is currently testing completion methods on its wells and is concentrating on developing low-cost horizontal techniques that will yield acceptable rates of return. Further drilling activity will depend on successful results from its present program, it says. There have also been several notable entries, but not necessarily exits, in the Barnett play. Burlington Resources Inc. acquired a portion of the production and acreage of Dallas Production Co. At the same time, Dallas retained a large acreage position, and is continuing to lease and drill in the Barnett. Burlington has six rigs running in Denton County and is actively leasing elsewhere. At press time, it had 87 vertical wells on 40-acre spacing, and expected to drill another 52 wells by year-end. The company has an inventory of 250 40-acre locations, with another 150 locations possible on 20-acre spacing. (Other operators are already downspacing some areas to 20 acres per well.) Meanwhile, Burlington is closely watching the application of horizontal drilling in the play by other operators near its acreage. Another new player is Antero Resources Corp. The Denver-based start-up acquired production in the Vinson Ranch area from Threshold Development Co. and Sinclair Oil Corp. Calgary-based EnCana Corp. has also bought into the play, picking up the production and assets of Tulsa-based Bravo Natural Resources Inc. Additionally, it acquired production and leases owned by Tejas Western Gas. And, Progress Energy (Winchester), a utility headquartered in Raleigh, North Carolina, bought the production and acreage of Republic Energy Inc. this year. The $135-million purchase included 156 vertical Barnett Shale wells and undeveloped acreage. Progress asked Republic to act as operator until it could set up its own staff, and Republic has drilled 44 additional wells-eight of which are horizontal and six of which are directional-for Progress since the purchase. Meanwhile, Republic principals Jerry Baldridge and Frank King are also starting afresh in the Barnett. The company has been actively leasing outside the core area and now has approximately 40,000 new acres, mainly in Parker, Hood, Johnson and Tarrant counties. "Our focus is going to be on horizontal wells," says King. "We see it as the key breakthrough in the play." In 2004, Republic plans to keep at least one rig busy, drilling 15 to 25 horizontal wells. To date, the firm has drilled two horizontal wells for its own account. "The Barnett wells continue to get better, and more reserves are being found for less money," says King. "This field has not even been remotely defined, and it will continue to develop for years to come." Exploration along the edges Independents are also boldly pushing the play into the outlying counties in the Fort Worth Basin. In Johnson, Bosque and neighboring Hood counties, Quicksilver Resources, formerly Mercury Production, has acquired a large block of acreage from Adexco Production Co. Quicksilver has hired several Barnett experts to spearhead a drilling program that is slated to kick off next year. Adexco, owned by long-time producers and brothers Craig and Glenn Adams, has been active in the Barnett play for more than two years. The company assembled more than 60,000 acres in northwest Tarrant County and in selected areas in Parker, Johnson, Hood, Somervell, Hill and Bosque counties. Adexco plans to drill its first horizontal well utilizing an uncemented seven-inch liner. "The larger-diameter liner allows us to pump a 3-million-gallon frac at much higher rates-up to 180 barrels per minute," says Glenn Adams. "Higher injection rates appear to have a direct impact on the rate [of production] and reserves. We see this play as a 20-year opportunity for our company. We may buy and sell out of it from time to time, but we are a local company and plan on exploiting this asset base, which literally lies under our backyard." In Jack County on the western side of the play, Best Petroleum Explorations Inc. is drilling a vertical Barnett test 11 miles southeast of its Jacksboro, Texas. headquarters. Earlier, it drilled the first Newark East Field well in the county. That well initially tested 528,000 cubic feet of gas per day and has produced 48 million cubic feet of gas since May 2001. And, on the north side of the basin in Cooke and Montague counties, where the Barnett turns oil-prone, Wichita Falls-based Trio Consulting & Management LLC has tested five of its wells in Saint Jo Ridge Field. This field produced oil and associated gas from the Barnett Shale at depths to 9,000 feet. One well has an initial pumping rate of 280 barrels of oil per day, and is currently producing 48 barrels per day. W.B. Osborn Oil & Gas Operations, San Antonio, discovered the field in 2001 when it recompleted a well as a Barnett producer. Future of the black shale Certainly, there are many issues facing the Barnett Shale play. These range from variable geology to inadequate gathering, processing and pipeline infrastructure, to community regulations regarding drilling, and to increased costs associated with proximity to housing and businesses. One favorable development would be the expansion of the Texas Railroad Commission's designation of a "tight gas sands" area in the Barnett play. Presently, such a designation covers Wise, Denton, Tarrant, Clay, Palo Pinto, Jack, Parker and Montague counties. Devon recently requested that the TRC confirm its tight-gas-sand designation to cover Johnson and Hood counties. "It is critical to future development that the entire Barnett Shale be classified as 'tight gas,'" says David Martineau, exploration manager, Dallas Production Co. "The economic impact of reduced severance taxes, should the request be approved, is enormous." Martineau's firm has requested that the TRC add Hill County to the tight-gas classification. Ironically, a tax reduction granted by Texas will help foster continued development of the largest gas field in Texas. "Rig rates are $500 to $1,000 per day higher now than they were at the first of the year. The tax credits help offset increased costs," he says. Still, aside from such economic incentives, improvements in technology will have to firmly launch Barnett Shale production outside of the core area. Today, many of the nation's largest independents are deeply involved in the play, bringing their capital, expertise and operational savvy to bear on the tight black shale. If they are successful, production from the Barnett Shale may one day rival that from Hugoton Field, the largest natural gas field in the onshore U.S. J. Robert Ransone is president of Dallas-based asset divestment firm Wellspring Partners.
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