San Juan basin producers are focusing more attention on conventional tight sands gas prospects as the region's coalbed methane production continues to climb.
Spurred by the federal Section 29 income tax credit for gas produced from nonconventional wells, San Juan operators through 1992 spudded as many wells as budgets would allow in the basin's Cretaceous Fruitland coal seams of Northwest New Mexico and Southwest Colorado.
When the tax incentive to spud wells expired at yearend 1992, companies that had positioned themselves to take advantage of the credit began concentrating on building production from qualified wells. As a result, much of the basin's upstream activity in 1993-94 involved operators consolidating coal seam portfolios, completing wells spudded in previous years, installing surface production equipment, and laying gathering systems.
Meantime, some San Juan operators were studying opportunities allowed by the basin's evolving upstream economics.
Even while spudding coalbed methane wells that qualified for the Section 29 credit, most San Juan operators had chosen to drill mainly prospects that would be economic without the incentive. Also, a half decade of intensive upstream activity focusing on the basin's nonconventional gas resources has yielded new insights, allowing operators to further trim production costs.
Economics have been improving, too, for development associated with the basin's conventional tight sands formations as producers applied more new technology and fine tuned operating procedures.
By yearend 1994, many operators were convinced that good opportunities will persist in San Juan basin well into the 21st century for development of conventional and nonconventional reserves.
The outlook is promising enough to encourage some latecomers to continue entering the basin, but success isn't considered a lock. Producers who achieve and maintain profitability in the basin likely will be those who can best use new technical capabilities to control drilling, completion, and operating costs while boosting production.
ACTIVITY INDICATORS
Because of the high level of drilling inspired by Section 29 and the unique production profile of coal seam wells, San Juan gas flow has trended upward since dipping to about 88.4 bcf in third quarter 1983.
Dwight's Energy Research, Denver, reports the number of active drilling rigs in the San Juan basin slid to less than five during most of first quarter 1993 after averaging about 22 throughout fourth quarter 1992. Still, the spate of coal seam wells drilled by late 1992 to qualify for the Section 29 credit likely was less than it might have been if the incentive deadline had not been extended from yearend 1990.
Most of the drilling through 1992 focused on the basin's Fruitland coal seams. As a result, the count of active Fruitland coal seam wells shot to 1,807 in 1993 from 51 in 1988, Dwight's data show. San Juan Fruitland methane production in 1993 amounted to 474.5 bcf.
Basin methane and conventional gas wells in first quarter 1994 produced more than 198.8 bcf. San Juan production previously peaked at about 182.3 bcf in first quarter 1991 and 186.9 bcf in fourth quarter 1992.
The U.S. Department of Energy estimates coalbed methane accounted for about 31% of New Mexico's total dry gas production in 1992, up from about 15% in 1990. About 26% of Colorado's total gas production in 1992 was coalbed methane, up from 11% in 1990.
The fact that San Juan's production curve trends irregularly upward reflects the extent to which basin gas has been competitive with supplies from other major U.S. producing areas.
RECOMPLETIONS
San Juan Basin Gas Well Completions (14965 bytes)
San Juan basin gas volumes have continued growing despite fewer well completions in the basin since a high of 278 in fourth quarter 1990.
Part of the higher production rates stems from growing output of coalbed wells during dewatering early in the production cycle. But the growing production also stems from well recompletions in the basin's deeper tight sands formations as operators apply new technologies to boost gas flow.
Since 1990, San Juan recompletions have accounted for nearly one of five completion procedures in the basin. Through the first three quarters of 1994, Dwight's counted 85 recompletions among the 163 completions reported by San Juan operators.
Two of San Juan's biggest producers - Meridian Oil Inc. and Amoco Production Co. - are enthusiastic about the results they are achieving with well workovers.
Dwight's reported gross production from Meridian operated San Juan wells in 1993 amounted to about 352 bcf and from Amoco operated wells 240 bcf, easily tops in the basin.
Randy Limbacher, vice-president of Meridian's operations in the San Juan basin, said about two thirds of the company's 538 basin projects in 199394 were recompletions and restimulations of Cretaceous Mesaverde wells, some of which were first completed with old open hole shot techniques as long as 30-40 years ago.
Limbacher said the emphasis by many companies on well recompletions vs. new drills is a basic economic decision: The cost of adding reserves in the basin often is lower with recompletions than with a new well.
"So we're emphasizing recompletions everywhere we can," he said.
In 1993, Meridian began sidetracking Mesaverde wells completed with old open hole shot techniques and reperforating and stimulating later Mesaverde wells completed with case and fracture techniques. Procedures in both general types of wells generated promising results.
"We added significant reserves as a result of those types of projects," Limbacher said.
With about 2,000 Mesaverde wells among the 7,200 it operates in San Juan, Meridian expects to find a lot of opportunities for workovers.
Hunter Rowe, Denver, manager of Amoco's San Juan basin activity in New Mexico, said Amoco has recompleted about 50 wells in the basin since yearend 1992, including recompletions from one conventional interval to another or from a very poorly performing conventional interval to a coal seam.
Amoco has recompleted some qualified Section 29 incentive wells in Fruitland coal seams.
"If a producer penetrated the coal seam during the qualifying window, it doesn't matter when he recompletes the well," Rowe said. "He still gets the tax credit."
With 3,800 company operated San Juan basin wells in New Mexico and 500 in Colorado, Amoco expects to continue recompleting about 30 wells/year in the basin.
MERIDIAN'S EXPERIENCE
Meridian's recent San Juan experience mirrors that of many other basin producers that have tried to capitalize on the Section 29 tax credit.
Nearly all of its San Juan activity before yearend 1992 was aimed at penetrating Fruitland coal seams to capture the incentive. In fact, before the deadline to spud qualified wells was extended, Meridian had timed most of its work to be complete by yearend 1990.
Meridian's Fruitland coal activity peaked in 1990, with 405 projects. After extension of the Section 29 deadline, Meridian undertook 93 projects in 1991 and 74 in 1992, again mostly coal seam related.
In 1993, after consolidating its coalbed methane operations and further mulling the future of San Juan activity, Meridian began changing its emphasis in the basin away from coal seam to more conventional projects. Since expiration of the Section 29 tax credit, about one third of its San Juan basin projects have been coal seam related and about two thirds in conventional gas formations, mostly the Mesaverde.
Meridian estimates its net San Juan basin reserves at 4 tcf of gas equivalent (tcfe), or 60-65% of its company-wide total. Coalbed methane accounts for about 25% of Meridian's San Juan gas reserves.
Due mainly to its coal seam drilling program, Meridian's net San Juan gas production in 1994 averaged 660 MMcfd compared with only 354 MMcfd in 1990. Included among the 1994 average is 350 MMcfd from about 1,200 Fruitland coal wells.
In addition to operating 7,200 San Juan wells, Meridian operates the Val Verde Fruitland coalbed methane gathering system in New Mexico's San Juan and Rio Arriba counties. The 800 MMcfd Val Verde system includes a carbon dioxide extraction plant, eight compressor stations, and about 400 miles of gathering lines.
AMOCO ACTIVITY
San Juan Basin Active Rig Count (18958 bytes)
Amoco hit the ground running in the San Juan basin with acquisition in 1988 from Tenneco of about 3,000 operated wells producing about 350 MMcfd, including about 25 MMcfd of coalbed methane. Amoco's San Juan well count in 1989 stood at about 3,950 wells.
Today, Amoco's gross operated production in the basin amounts to about 770 MMcfd, or about 10% of Amoco's world gas production, including about 400 MMcfd of coal seam gas. Coalbed methane accounts for more than half of the San Juan gas Amoco produced in New Mexico and about 98% in Colorado.
The company has drilled about 1,300 wells in the basin since the acquisition from Tenneco, 1,200 of them before yearend 1992, including 670 coalbed methane wells. Amoco estimates it has doubled its reserves in the basin.
Since forming business units in 1991, Amoco has relentlessly reorganized and examined every step it takes in the basin to make sure it takes on only value added activities.
Results have been promising. On a per unit basis, Amoco's direct and indirect costs in San Juan in 1994 were about 45% less than in 1991. The company's indirect costs/Mcf in 1994 amounted to about 25% of its total basin spending, down from 40% in 1991. Overall, Amoco has trimmed San Juan operating costs enough to earn a place among the basin's low cost producers.
Since kicking off its San Juan drilling campaign, Amoco has lowered the cost of a typical 8,000-9,000 ft conventional Dakota tight sand gas well to about $300,000, about one fourth of the average only 4 years ago.
"That comes from a radical redesign of the wellbore, partnering and better communication with service suppliers, and a control of operating costs by reducing downtime and streamlining operations," Rowe said. "So the benefits we're seeing didn't occur only in terms of lower operating costs. We think lower drilling costs will promote more drilling than we otherwise would see in the basin."
OUTLOOK PROMISING
Favorable economics created by the Section 29 tax credit led many companies to step up activity in the San Juan basin. And the economic outlook for further activity is prompting many latecomers to stay.
Phillips Petroleum Co. for the past 2 years has been assessing the potential of its conventional gas sands holdings in the basin while monitoring its coalbed methane operations. Although it has held San Juan interests since federal units were formed in the region in the 1950s, Phillips didn't operate in the basin until 1989, when it took over as operator of 600 conventional Mesaverde and Dakota tight sands gas wells.
Similarly, Apache Corp., Houston, does not consider the San Juan basin one of its core operating areas. In fact, it has no coal seam gas production in the basin. But Rod Eichler, Denver, manager of Apache's Rocky Mountain exploration and development, said the company expects to continue increasing its San Juan gas volumes.
Since entering the basin as an operator, Phillips has more than tripled gross production of wells acquired in 1989. In addition, the company by yearend 1992 drilled about 220 coalbed methane wells in the New Mexico portion of the basin, most to Fruitland coal seams at about 3,200 ft. Dwight's estimated Phillips' 1993 gross production at nearly 90.5 bcf.
Since 1992, Phillips has drilled fewer than 10 coalbed methane wells in the basin, none in 1994. The company has drilled only a handful of conventional gas wells in the basin since 1992.
While its production climbed, Phillips stayed busy in the basin in 1993 with coalbed methane related activity. The company installed a low pressure coalbed gas gathering system with more than 200 miles of 4-12 in. lines, as well as 130 miles of 4 in. water line.
While its drilling activity has declined, Jim Taylor, area manager for Phillips in Farmington, N.M., said the company expects its San Juan production to continue increasing "because of the vintage of our development."
CONVENTIONAL GAS PLAY
Apache's interest in the San Juan basin began with acquisition from Amoco in 1991 of 150 operated wells and 63 nonoperated wells.
After a series of small acquisitions, Apache significantly increased its acreage position in San Juan again last fall when it acquired interests averaging 76% in 48 operated and 26 nonoperated Dakota and Mesaverde gas wells in Ignacio Blanco field, La Plata County, Colo., from Southwestern Production Corp. (Swpco). The wells produce from conventional Mesaverde formations at about 5,500 ft and Dakota reservoirs at about 8,800 ft.
That deal lifted Apache's San Juan gross gas production by 6.2 MMcfd to about 14.2 MMcfd and gross oil production to 600 b/d from 199 operated and 89 nonoperated wells.
Eichler said Apache has about a dozen proved, undeveloped drillsites identified on the Swpco properties it plans to drill in 1995-96. On the southeast side of the San Juan basin at the Lindrith federal unit, Apache will participate in wells on nonoperated leases seeking to exploit Dakota D sands at about 8,000 ft. Also, Apache this year or next is to pursue some oil prospects in Cretaceous Mancos fractured shale along the northeast side of the basin.
ADDING INFRASTRUCTURE
Taylor said one of the main challenges for San Juan producers is getting gas treated and moved out of the basin.
Phillips' San Juan gas output in 1994 was limited by lack of treating and pipeline capacity. The problem could worsen in 1995 as the company's production continues growing.
One of the companies trying to catch up with demand for San Juan gathering capacity is Williams Field Services (WFS), a unit of Williams Cos. Inc., Tulsa. Together, WFS and El Paso Natural Gas Co. transport most of the gas leaving the basin.
WFS field volumes in the basin at yearend 1994 amounted to a little more than 1.1 bcfd, including about 820 MMcfd of coalbed methane on its Manzanares gathering system and 300 MMcfd of conventional gas. El Paso's third quarter 1994 field volumes in the basin averaged 1.036 bcfd.
Tom O'Keefe, Bloomfield, N.M., WFS director of San Juan basin operations, said the gas gatherer-processor has been trying to overtake San Juan gas well deliverability since it began recognizing emerging coalbed methane handling opportunities in the basin.
"We've been behind wellhead deliverability since we started because there has been so much more gas than anybody expected," O'Keefe said. "The trick has been to use all of the facilities as best we can while we build new ones."
WFS's Manzanares coalbed methane system includes two dozen central gathering points and about 120 miles of mostly 10-30 in. pipeline gathering gas from about 1,100 coal seam wells. Its conventional San Juan gas gathering and processing network includes about 1,200 miles of 4-30 in. pipeline serving about 2,700 wells.
Combined capacity of the systems could surpass 1.7 bcfd by yearend 1995 if construction proceeds this year as planned and if WFS about midyear finishes acquiring another conventional gas gathering and processing system in the basin.
WFS by midyear expects to add about 200 MMcfd of capacity to Manzanares with completion of the La Maquina facility, a two train coalbed methane treating plant about 6 miles northeast of Aztec, N.M., in San Juan County. Also under construction on the Manzanares system is a fourth 80 MMcfd processing train at the Milagro facility that will lift plant capacity to 320 MMcfd.
Because Milagro uses steam to power the pumps pressuring the plant's amine and glycol systems, WFS in March expects to break ground for a new cogeneration plant at the site. Plans include installing two gas turbines to turn the facility's power generator, using waste heat from the turbines to produce steam for the processing plant, and installing about 62,000 kw of power, most of which will be sold through the Western Area Power Administrators grid. WFS in early January was processing about 130 MMcfd through the La Maquina plant. It expected the fourth Milagro processing train to start up in early February.
WFS conventional gas handling capacity in the basin would roughly double about midyear if New Mexico public utility commissioners approve the acquisition of certain San Juan assets owned by Public Service Co. of New Mexico, Albuquerque. Included in the deal are natural gas liquids plants with combined charge capacity of about 360 MMcfd with about 1,830 miles of pipeline gathering gas from about 2,700 wells. Some of the assets are to be resold immediately to Phillips' GPM Gas Corp. unit.
JUPITER AUTOMATION
Amoco plans to further improve efficiency of its San Juan activity by fully automating all 3,800 wells it operates in the basin. With all Amoco operated wells on line, the company expects to save about $20 million/year.
Amoco began installing its Jupiter field automation system a little more than 2 years ago and at yearend 1994 had connected about 1,600 wells at a cost of $25 million. Each well is connected to the system by an on-site terminal powered by a battery that is recharged by a solar panel. The terminal unit collects operating data and controls the well, communicating with employees through a two way radio system.
Jupiter samples 10-15 parameters at each well every 6-8 min and stores the data at a host computer at Amoco's Farmington, N.M., office for later retrieval, if necessary. With 1,600 wells on line, Jupiter collects about 125,000 data points/hr, or about 10 times the next largest automated oil and gas production system.
Remotely monitoring and controlling 20-30 operating parameters at each well helps Amoco improve well productivity while altering workday routines and eliminating worker redundancies.
Jupiter helps Amoco better match production with nominations, at the least helping avoid pipeline transportation penalties. Pumpers can find problem wells faster and adjust production criteria without leaving the field office.
"For example, many of our Dakota wells in the basin have liquid loading problems and historically have had to be vented several times a day," said Jeff Childs, Denver, a foreman at Amoco's San Juan operations center. "With Jupiter, instead of venting, we instruct a well to produce a cumulative volume, then shut in. During the shut in period it will build enough pressure to buck line pressure the next day."
Before Amoco began using that procedure, a typical Dakota well might have been flowing about 195 Mcfd.
"Today," Childs said, "the same well is producing as much as 325 Mcfd."
NEW TECHNOLOGY
While it has been implementing cost saving and efficiency measures across the basin, Amoco has maintained a healthy interest in trying and applying other new technologies and procedures that promise further gains.
"In the San Juan basin, we see some neat technical things that can improve production, many of which we don't see other operators trying," Rowe said. "We think we'll be in the field sooner than the rest of the industry with those kinds of projects."
Among its notable technical advances in the basin, Amoco in the past year began stimulating active San Juan coalbed methane wells with a "recavitation" procedure that uses formation pressure to stress coal seams and clear wellbores and downhole equipment. Amoco so far has performed about 20 recavitations on some of its best coal seam wells. The company estimated it has added 30-40 MMcfd of production with the procedure, in some instances recouping the cost of the procedure within a month.
In addition, Amoco in 1994 achieved technical successes with three horizontal wells drilled in conventional San Juan gas intervals with air rigs typically used to drill vertical or deviated wells in the basin. Avoiding the use of drilling fluid eliminated concerns about losing fluid into the formation and damaging reservoir permeability, while the reduced manpower requirements of the air rig cut drilling costs.
"We penetrated the fractures where we thought they existed," Rowe said. "The long term production trends of those wells will show whether we're recovering more reserves."
Meridian, which reportedly has had significant success in drilling San Juan extended reach wells, has drilled about 10 horizontal wells in the basin since 1992.
Amoco in 1995 plans 10 more horizontal wells in the basin, about 20-25% of its basin drilling activity. Depending on results of its early horizontal wells, Amoco's horizontal drilling program could account for as much as half its San Juan drilling.
ENHANCED RECOVERY
Also in the San Juan basin, Amoco is experimenting with enhanced methane recovery (EMR) by injecting CO2, nitrogen, or gases with high concentrations of one or the other into coal seams. Injecting CO2 or nitrogen appears to speed methane recovery, increasing a coal seam well's economically recoverable reserves in the process.
"We think it represents the next wave of growth in the basin," Rowe said of EMR.
Amoco said several field tests have shown that a coal seam will release methane as a free substance to preferentially bond with either CO2 or nitrogen, increasing recovery. In a 1994 test, Amoco was able to predict how much CO2 it would be able to inject into a specific well, then verify its model in the field.
In the past month in New Mexico, Amoco drilled injection wells for a field scale EMR test to begin in first quarter 1995 studying the economic viability of nitrogen injection EMR. Later in 1995 or early in 1996, Amoco plans to start other EMR field tests, one in the Cedar Hill producing area where it began coalbed methane work in the 1970s and another in Bohannon Canyon producing area.
With unit costs of some early injection programs running as high as $1/Mcf of incremental methane recovered, economics will have to improve if the procedures are to contribute significantly in the basin.
"It's been our judgment from the pilots and laboratory work we've done that nitrogen injection probably is going to be the more economical of the two processes," Rowe said.
Other companies are holding their opinions pending further studies.
Meridian in fourth quarter 1994 began a CO2 EMR pilot test in the Allison federal unit on the Colorado-New Mexico line. The gas is to be injected into a Fruitland coal seam underlying the acreage.
Meridian in mid-January was installing compression at the site, drilling injection wells, and laying a CO2 pipeline.
"We hope to be injecting CO2 into the unit by the end of first quarter," Limbacher said, "But that's as much as we want to say about it right now."
ECONOMIC SENSE
Whatever the eventual contribution of EMR or other advanced production technologies in the San Juan basin, Limbacher predicts each producer in the region will continue to do whatever makes economic sense for the gas markets in which he is competing.
For Meridian, that means the basin will continue to be an important core area.
"We still see tremendous potential left in the basin, with high activity levels well into the future and the ability to continue increasing San Juan reserves and production for some time," Limbacher said. "If a company is focused on new technology and holding down costs, I think it can succeed here."
While for many operators that means more emphasis on the basin's relative deeper conventional horizons, Limbacher said San juan's Fruitland coal will continue playing a major role.
"Even though we've seen such tremendous Fruitland coal activity and even though the tax credit (for new wells) has expired, I still expect the Fruitland coal to be a very significant part of many operators' activity in the basin," Limbacher said. "It wouldn't surprise me at all to see work in the Fruitland coal account for as much as 25% of San Juan activity over the next several years."
With the timing good for companies with large gas reserves in North America to make gas a centerpiece of long term strategies, Amoco likely will either maintain or continue increasing its San Juan production at least through the decade. Amoco holds North America's largest portfolio of gas reserves.
Childs said Amoco's San Juan drilling activity in the future, either as a percentage of its production or its total well count, will be equal to the most aggressive developers in the basin. Current wellhead gas prices dictate that operators must be cautious about committing to too much, too far in the future.
"But certainly we can maintain about that level of activity over the period we talked about, through the early 2000s," Childs said.
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