About 150 miles south and southwest of Midland in the Delaware Basin, there is a stretch of miles and miles of-well, miles and miles. Creosote and mesquite scrub brush, some pecan trees and a few scraggly oaks are the only markers as far as the eye can see. During World War II, the trainers based in the tiny town of Pyote probably disturbed only a few jackrabbits on their bombing runs. Gradually, the desolate land starts to fall away as one crosses the Pecos River heading west. Slight rises and dry canyons appear such that from a mile away, only the top half of a rig derrick is visible at first. Shortly after Thanksgiving a "blue norther" blew through, dumping up to six inches of snow in some locations, a rarity in arid West Texas. Cattle, sheep and goats take a backseat to oil and gas production in this region near the Davis Mountains, which hover in the distance. Decades ago, impressive fields here contributed to the foundations of Exxon, Mobil, Arco and other majors. The roll call includes standouts such as Block 16 Field in Ward County, which has produced 1.4 trillion cubic feet of gas to date; Pecos County's Coyanosa Field, which has yielded 2.65 Tcf; Gomez Field, also in Pecos County, which has produced 4.5 Tcf; and nearby Waha, which has made 790 billion cubic feet (Bcf). They still lend a great deal of weight to West Texas' reputation as a hydrocarbon-rich area that operators want to exploit, this time through the latest technologies, and in deeper, tight carbonate zones. The Devonian and deeper Ordovician Montoya are the hot targets now, but typically they have to be drilled horizontally, or reentered that way, because the production of vertical holes is not commercial. A lot more about this play needs to be proven. No one knows exactly because production data lag, but people think aggregate output from the horizontal Montoya now approaches100 million cubic feet per day. A year ago last October, veteran Midland oilman and former gubernatorial candidate Clayton Williams Jr. wanted in. Now 70, he says he was on horseback working cattle at one of his ranches when simultaneously, he finalized his first lease deal in the Montoya over his cell phone. That's how it's done in the New West. Williams is a charter member of the self-named Montoya Seven-six Midland buddies and one from Artesia, New Mexico, who are all septuagenarians or better. All well-known independents, they have assembled 13,000 acres on Texas University Lands to chase their share of the deep, tight carbonate play. At press time the rig at their first well, the Medlock, was about to start its horizontal leg in the Montoya. Total depth is 17,000 feet on the western flank of ExxonMobil's Block 16 Field in Ward County. Clayton Williams Energy Inc. is the designated operator because the company has so much experience in horizontal drilling, having drilled more than 300 such wells in the Austin Chalk during the last decade. The Montoya Seven also owns acreage in a section to the south and on two blocks to the north. Drilling is on 320-acre spacing. "We're kind of late in the play, but we picked up some expired leases," Williams says. "H.L. 'Sonny' Brown was the catalyst who worked up the idea and invited me and the others in to talk about it. We know this basin like the back of our hand. I bet there's 350 years of experience among us." The main leasing push throughout the play occurred in 2000 and 2001, focusing on the Devonian and more recently, the Montoya. Early on, optimists expected the Montoya to sweep the Delaware Basin, but after some fall-out and a learning curve, people are a bit more realistic. Still, horizontal drilling is spreading to all the old, known gas fields. As Williams points out, "It's similar to the Chalk in that the vertical wells really aren't commercial, but if you go horizontally, they are. "When gas was $4, this was very exciting, but at $2 it's not as attractive. Montoya gas gets New York minus 10 or 15 cents. You take the royalty out and that's $1.50. That won't pencil, so you've got to get a better well or bring your costs down. "But we've been dealing with these cycles for years. It's like growing onions-you've got to manage it as a commodity. One day you get a bonus and the next day you lose your tail." The challenges Attractive though they may be, these horizontal gas plays are expensive, tricky and deep. Drilling through hard rock such as the chert found in the Devonian takes a long time and eats up drillbits-on some wells, the bit only lasts 24 to 36 hours through only 100 or 200 feet of rock. Then the drillpipe must be tripped out of the hole over the course of several hours-or a full day-so the bit can be replaced. The use of 3-D seismic data, logging- and measurement-while-drilling tools and other special horizontal-drilling tools are crucial as the bit moves through complexly faulted zones. High temperatures of 280 to 380 degrees Fahrenheit risk burning up the sensitive downhole directional motors. Operators are experimenting with drilling, completion and acid-fracturing techniques to optimize recoveries, reduce water in the wellbore and reduce costs. "If somebody's thought of it, we've tried it," says one producer ruefully. Despite these technical challenges, key players are still jockeying for better position. Lease prices have soared as they scour the Permian and Delaware basins looking for tight carbonate rocks that are candidates for new horizontal wells or horizontal reentries of uneconomic verticals. Some of the leases between the Pecos River and Waha Field commanded as much as $500 per acre last fall. A few companies are keeping their plans close to the vest. Houston-based EOG Resources Inc., for example, declined comment for this article. However, by all accounts it is quite active, having leased at least 147,000 acres in these plays, in the ROC, Waha and Coyanosa fields and further south in Terrell County, part of the Val Verde Basin. In third-quarter 2001, it drilled nine successful Devonian horizontals. It estimates recoveries of 7- to 10 Bcf per well at a completed cost of $4.2 million each, according to reports from Stifel, Nicolaus & Co. analyst Andrew Lees and Credit Lyonnais analyst Brad Beago. EOG's multiyear, multiwell development program may be firmed and ready to roll in the second quarter of 2002, Lees writes. EOG estimates it may recover 100- to 200 Bcf in the Montoya and 200 Bcf to as much as a trillion cubic feet in the horizontal Devonian, he adds. The company is encouraged by results in its horizontal Montoya program, "which ultimately may include 15 to 20 wells in the area," says Beago. EOG "estimates the play to be economic in a gas-price environment of $2.25 to $2.50 per thousand cubic feet (Mcf)." ExxonMobil is active in Block 16 still, and reportedly plans to drill new horizontal wells and reentries throughout Coyanosa Field this year and next as it continues to maximize Mobil's legacy assets. Mobil kicked off the horizontal Montoya gas play with several high-performing reentries of verticals in its Block 16 Field, prompting other producers to chase after deeper horizontal gas plays throughout the Midland and Delaware basins. For many years, operators have known the gas was behind-pipe, but its commercial viability was in question. Armed with horizontal methods and other technologies, producers now estimate recoveries of 4- to 20 Bcf per well. If a 4-Bcf reentry well costs $2 million to complete, it could earn about $6 million or a three-to-one return. Depletion is fast the first year but the tail (the long-term, lower-production rate) can last 20 years. Producers figure even wells on the low end of the producing spectrum are commercial if gas is $2 per Mcf and they are "extremely commercial" if above $3. Pure Resources Inc. The largest independent leaseholder in these plays, Pure owns about 210,000 acres. West Texas remains a key theatre of operation for the Midland company, having received 65% of its capex last year, even though it is also active in South Texas, the San Juan Basin and the Gulf of Mexico. This area will again play a significant role in the new year. At one time Pure was running as many as seven horizontal gas rigs in the Delaware Basin and Central Basin Platform's deep horizontal plays. It may drill 15 to 20 wells there this year, but this will depend on gas prices. Chairman and chief executive officer Jack Hightower did not like the outlook at press time. "If gas is $2 or less in January, I'll start laying down rigs," he vowed. "But roughly 65% of our reserves are in the Permian, so this play will be an important component of our growth for a long time to come. We have 14 macro-project areas and within each of those we have numerous prospects. For example, under Gomez Field in Pecos County we have 20% to 100% working interest in about 33,000 acres. If we drill on 320-acre spacing, that could be about 90 wells." Pure has successfully completed one or more horizontal gas wells in each of five core project areas-Gomez, Yucca Butte, Monty, Blue Danube and the new Montoya project in the Waha-Worsham area in Reeves County. It has more than one horizontal well producing in each of the first four areas. In Upton County's Blue Danube Field, it has completed more than 10 such Devonian wells. Pure's first horizontal Devonian well, the Slaughter 26-2 in Terrell County's Yucca Butte area, is producing 5.3 million cubic feet a day. The PBM #2, a new horizontal at Gomez Field, tested 8.8 million cubic feet (MMcf) per day, also from Devonian. Gomez has produced 4.5 trillion cubic feet equivalent (Tcfe) from the deep Ellenburger. "Overall we've had something like 21 out of 23 wells commercially successful," says Hightower. "So far we're the only company to successfully go horizontal in Gomez. We've had success in three out of four wells there-two were horizontal. On the acreage we've leased on top of the feature, we estimate recoverable gas of about 300 Bcf, if it goes as we hope. We're looking at 15- to 20 Bcf per well. But we are pushing the limits of technology in these hard rocks." The company's first horizontal well at Gomez cost $8 million, but costs have since come down as Pure climbs the learning curve. Hightower says the company prefers to drill vertically first because it's less expensive, but will go horizontal if it needs to, to accomplish its goals. Not all Devonian or Montoya wells are equal as to pay thickness and reservoir quality. Pays vary greatly in thickness, from 60 to 1,000 feet, generally getting thicker as one moves west off the shelf of the Central Basin Platform that trends northwest-southeast. Some of the faults have 1,500 feet of throw; others have 2,500 feet. That kind of displacement is a challenge answered by 3-D seismic interpretation. Some of the reservoirs produce by pressure depletion and others are water-driven. Some are stratigraphic and some are structural. Wells can be up to 18,000 feet deep. Porosity can range from 3% to as much as 15%, yet the permeability of the rock is very tight, from 0.5 millidarcy to five. The attraction is that in many places, a well that might produce only 1 Bcf during its life if drilled vertically can produce 10-, 12- or 15 Bcf instead when drilled horizontally. "It's not for the faint-hearted," Hightower says. "But the potential is phenomenal. So far, I'm really glad we're in this play." At press time the company was busy-it was drilling three wells in Waha and one at Rojo, deepening one in the Oates Field to Montoya, and drilling its fifth well in Monty Field to the Devonian. It was also drilling its second well at Yucca Butte. The Rape 14-1H in Reeves County, Pure's first new-drill horizontal to the Montoya, flowed an encouraging amount of gas, but was then plugged back to the Devonian section for an attempted dual completion. At press time the Devonian was still being tested. That's another benefit to drilling in this area-many times, wells can be completed in both zones. Pure holds 25% and operates. Drilling time and well performance keep improving as the company learns the drilling intricacies involved and better understands the reservoirs. "Success is really related to mechanical issues. We know the gas is there; no one quibbles on that. The question is, how do you capture it and get it out?" says Bill White, vice president and chief financial officer. Another challenge is that large volumes of water load up the wellbore, reducing deliverability. The company is experimenting with various techniques. "It may be self-induced water production, from something we've done in our completion," says Hightower. "Are we communicating with water through a fault plane or a fracture system? Can I drill the well with no water, or can I complete it without inducing or increasing water? If we can learn how to complete these without increasing water, we're talking megatrillion cubic feet of gas left to be recovered. "We think there are deep gas opportunities from the Ellenburger all the way up to the shallower formations throughout the Delaware Basin," he says. "There's no question there are other formations that have gas potential that can be horizontally drilled, not simply the Devonian and Montoya, but also the Atoka and Wolfcamp in certain situations." For now though, Pure will focus on the Devonian and Montoya, and one reason is the success seen at ExxonMobil's Block 16 Field. Going south of that to Pecos and Reeves counties, other outstanding gas fields beckon, such as Worsham and Waha. Pure is involved in a large 3-D seismic shoot under the latter. (See map.) Pure and partners, Tom Brown Inc. and partner ChevronTexaco, and EOG and partner Abraxas Petroleum are active as well. Tom Brown Inc. Even though Tom Brown Inc. moved its headquarters to Denver in 1999-the same year Mobil's Block 16 action was starting to heat up-the company kept close to its roots so it could pursue overlooked gas plays throughout the Midland and Delaware basins. "We heard about Block 16 and started looking for a place analogous to that. By then Exxon and Mobil had merged so we sought out some ex-Mobil people who had expertise in the play," says Peter Scherer, executive vice president in charge of the Midland operation. Today Tom Brown means business. CEO Jim Lightener in Denver gave Midland his support to pursue this play in a big way. The company has grown its staff 50% in Midland since dropping the head count when the headquarters were moved. It has hired four former Mobil experts who were intimately involved with Block 16 early on, including a geologist, a geophysicist, landman and drilling engineer. It also hired a full-time petrologist, data manager and petrophysicist. It turned one of its conference rooms into a core library where it analyzes leads. "We have come way up the learning curve and we have an integrated team," says Scherer. "You just don't go drill a lateral anywhere you please. That's why you plan the well from the completion and work back. We work with the engineer and team on how to position the lateral-a longitudinal or a transverse lateral-what fracs are needed, and what stimulation is needed, if any. You're taking old prospects, applying all the basics and combining that with all the new technology, trying to make it an economic play." In the Delaware Basin in Reeves, Pecos and Ward counties, Tom Brown has amassed 23,000 net acres in what it calls the deep-valley play. In addition, the company and ChevronTexaco each contributed 8,000 net acres for joint development in the Worsham-Waha area. Tom Brown drilled the first horizontal Montoya test on this acreage, the G. Lyda #1. Unfortunately, the well made water and looked tight, which nobody expected. This led the company to shoot a 240-square-mile 3-D survey, and it may reenter the well and try a Devonian lateral instead. Interpretation of the seismic was to be finished by March. "The 3-D is important because when you're drilling horizontally, you've got to know where those faults are located. If you cross one, all of a sudden you've encountered a different formation-are you above or below where you wanted to be?" There will be multiple tests of the shallower Pennsylvanian Strawn formation in 2002, although Scherer wouldn't say how many just yet. The company has already drilled four such tests at its ACU prospects in Terrell County, with varying, but economically successful, results. "The idea is taking tight carbonates, whether in the Devonian, Montoya or Strawn, that are not commercial if produced from a vertical well and applying horizontal technology to make them flow at commercial rates." Abraxas Petroleum Corp. One of the smallest-cap public companies in the play, perhaps the one with the most to gain proportionally, is Abraxas Petroleum Corp. And no other company is active where Abraxas finds itself, drilling down in the far southwestern corner of Pecos County, almost into Brewster County. There, it owns 100% in leases over the old Oates Southwest Field. The San Antonio company's P.T. Hudgins 34-1H, which was about to be tested at press time, is 40 miles from the nearest Montoya drilling and 90 miles from the company's horizontal joint venture with EOG Resources at Caprito Field. "We hope it could be 10 million cubic feet a day initially. That's the average in Block 16 Field. If gas is $2 and the well declines to a stabilized rate of 3 million a day, then payout could be in 10 or 11 months," says Robert L. G. Watson, Abraxas CEO. "That would have a tremendous impact to Abraxas-it could be 15% of the company's production." Abraxas has identified three Montoya and six Devonian locations at the field, which it owns 100%. They could all be drilled within two years. "Without a change in gas price or a capital event, I can't see us drilling any faster," Watson says. He admits that Wall Street is skeptical that the overleveraged small-cap can come up with sufficient funds to keep drilling these wells, as important as they are to the company's future. He says he is negotiating and may consider a number of funding options. The Hudgins well was plugged about 10 years ago. Abraxas reentered and cleaned it out in August and found the casing intact. After waiting on a rig, then waiting for rig rates to moderate some, the company finally began drilling in late November. Directional specialist Leam Drilling Systems of Conroe, a Houston suburb, set a whipstock and milled a window through 7 5/8-inch casing to begin the lateral through the Montoya horizon. "We picked up the curve assembly and ran it into the hole and started time drilling, until we were 30 to 40 feet from the casing. It takes two or three days to drill the curve and start doing the horizontal itself," explains Will Wallace, vice president of operations. Here, the Montoya is about 350 feet thick, but the team tried to keep the bit within a 50-foot zone as it moved out toward a lateral length of 3,500 feet. They used 3-D seismic data to understand the direction and length of the lateral, avoid faults and stay in the target interval. "Because it's a reentry situation, it's a perfect opportunity for us to test our theories. If this well was drilled from scratch it would cost about $4 million but as a reentry it will be about $2 million," explains Wallace. "Saving that much money is very material for a company our size. "If it makes enough gas, maybe we can do it economically at $2 gas. Being the first reentry in the field, there's a lot of science to it because of the unknowns. Sometimes you test theories without necessarily banking on the economics, but we are not big enough to afford to do that-the thing that makes this one fly is that we can do it much more cheaply than $4 million. "The challenge is not so much in the redrill, but in the completion-that's not to say you can go in and drill with your eyes closed. But completing a 3,500-foot lateral is not a done deal and there are some questions about the best way to do it efficiently-we've spent hours cussing and discussing it, with other operators and the service companies." The well was drilled underbalanced, with water not drilling mud, and finished at 16,800 feet measured depth, including a 3,135-foot lateral in Montoya. Schlumberger then ran density neutron logs to glean information on porosity and formation micro-image (FMI) logs to determine fracture orientation and the nature of the porosity. "We had good gas shows and flared gas while drilling. We are waiting to complete it now," says Lee Billingsley, Abraxas vice president of exploration. "We'll get something out of it, we just don't know how much yet. We hope to drill other wells here to prove it up." The company intends to test Devonian in a second horizontal reentry in the field. The gas will be produced into an existing pipeline, receiving a wellhead price that's about 82% of the frequently used index price at the Houston Ship Channel. Observers in the region reported seeing gas flares at the Abraxas well, an encouraging sign to be sure for Jackie Wilson and Tom Fekete. They are partners in a new geological consulting firm called Jordan-Rubicon Resources LLC. The Midland geologists have studied the Montoya for many years, most recently as employees of Arco Permian before it was acquired by BP. Arco was a 50-50 partner with Mobil in several of the early Montoya wells in Block 16 and Waha fields that sparked the horizontal play. Currently Wilson and Fekete are evaluating the old Hovey Ranch in southern Pecos County, only a couple of miles from Abraxas' well. They've shown there is potential on the ranch by documenting the reservoir's quality and structure, which appear favorable, as the ranch is located high to the producing structure. Leasing should come soon, hopes the ranch owner. Having enough capital to pursue these expensive horizontal plays is a challenge all companies face these days, as most operators do not want to engage in deficit spending beyond 2002 cash flow. The play may slow down for a few months if gas remains around $2, until, as most people believe, prices begin to rise again. In the meantime, drilling and other service costs have come down some since last year's frantic gas boom. "The thing about the Delaware Basin is, it's so big and there are so many areas with Devonian and Montoya gas. This horizontal drilling is a real shot in the arm, almost like it's a new basin," says Ron Grant, Midland-based exploration manager for Abraxas. "They say these horizontal wells were paying out in 90 days last year when gas was $10. If gas goes to $4, that would make this ole country rock and roll."