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Coalbed Methane Development­A Vital Part of the Total Energy Mix

From hazard to environmental challenge to energy resource ­ that is how the perception of gas contained in coal beds has evolved.

Mine safety and greenhouse gas emissions (GHG) and air quality will continue to be concerns. But since the early 1980s, coalbed gas has increasingly been viewed as a valuable energy resource. Though its contribution to the total energy mix is still modest, coalbed methane (CBM) has impressive potential. It will supplement conventional natural gas supply, adding another environment-friendly component to the total energy mix. How fast the exploitation of coalbed gas resources will grow is difficult to project; some forecasts made in the mid- 1990s have proved to be very conservative. And development will surely accelerate as more is learned about coalbed behavior, and as innovative drilling and completion techniques are applied. On the demand side, coalbed methane will be welcome in the market. The world's appetite for gas is expected to grow faster than total energy demand, driven in part by a preference for gas instead of oil or coal. In the United States, where government emphasis is on dramatically increasing gas supply by the end of this decade, coalbed gas will play an important role.


Though estimates of the total CBM resource vary considerably, they typically rise with new understanding and technology. But much is still to be learned to fully exploit coalbed methane's potential. In the late 1990s, the U.S. Geological Survey (USGS) estimated in-place coalbed methane resources in the United States at more than 700 Tcf; of which almost 100 Tcf is economically recoverable, according to the USGS. Estimates of worldwide CBM resources are even more difficult to make, in part because few areas are as mature as the United States. Joe Awny, senior petroleum engineer, Equitable Production Co., said global CBM recoverable reserves are about 1,200 Tcf. By comparison, world reserves of conventional natural gas are estimated at 5,500 Tcf and U.S. recoverable conventional gas reserves are 183 Tcf.1 Half of the estimated 100 Tcf of recoverable CBM

reserves in the contiguous 48 U.S. states is in the Powder River, Northern Appalachian, San Juan and Black Warrior basins. Almost 75 Tcf may yet be discovered in the contiguous 48 states. Another 57 Tcf of CBM is estimated to be recoverable in Alaska.2 In the western sedimentary basin of Canada, in-place CBM reserves are estimated at more than 400 Tcf in Alberta and 15 Tcf in Saskatchewan. East Coast gas-inplace (GIP) is estimated at 22 Tcf. Today, U.S. coalbed methane production is more than 4 Bcf/d. Output totaled only 6 Bcf in 1983, then jumped to 1,090 Bcf by 1997, according to the U.S. Energy Information Administration (EIA). Since then, development has accelerated faster than EIA projected; current annual production of more than 1,500 Bcf represents more than 7% of annual U.S. gas production. Key U.S. producing regions include the Powder River Basin with an estimated 24 Tcf of recoverable reserves, the Northern Appalachian area with 11 Tcf, the San Juan Basin with more than 10 Tcf and the Black Warrior Basin with more than 4 Tcf. The number of CBM producing wells in the contiguous 48 states passed the 15,000 mark in 2001, up from 284 wells in 1984. Australia, with the most advanced commercial program outside the United States, produces about 20 Bcf/year, about 1.3% of U.S. output.


Because of its large ratio of surface area to volume, coal can store six to seven times as much gas as the same volume of rock in a natural gas reservoir. The gas content of a coal bed usually increases with depth and reservoir pressure. The deeper the coal, the less water is contained in the fractures, but water salinity increases with depth. Since water pressure prevents the gas from desorbing, the water must be removed to reduce the partial pressure in the coal seam so the gas can be released. After desorption, the gas spreads throughout the coal bed. Significant coalbed methane production usually occurs only after substantial dewatering. Coal seam plays can be classified in two major categories. The first is coalbed methane recovery in advance of mining operations, and the second involves primary CBM production in areas too deep to mine. In the first mode, the coal and methane resource are recovered in addition to potential GHG credits, making gas extraction economics less critical for project success. The second type of play must succeed without mining incentives or GHG credits. Like conventional natural gas wells, coal seam wells are drilled and stimulated, but coal's unique physical characteristics call for special techniques.


Coalbed methane development has the full range of energy production challenges: technical, economic,

environmental and regulatory. The solution to many of these lies in a better understanding of the reservoir and the effective application of available technology. There are several elements to the economic challenge. In the early stages of a project, large quantities of water must be pumped from the formation while little revenue-producing gas is being recovered. That makes an early, accurate assessment of the project's economic potential especially critical. Pumps, while modest in size and power requirements compared with oil pumping equipment, must be capable of handling water, gas and abrasive coal fines. Even more daunting ­ and it may become increasingly challenging ­ is finding a viable water disposal method that meets or exceeds environmental regulations while considering potential future risks for change. Together, dewatering and produced water disposal costs can often make or break the economic viability of a CBM project. In the United States, where researchers, operators and the U.S. Environmental Protection Agency are studying possible new requirements for handling produced water in the Powder River Basin, the sensitivity of CBM project economics to water handling regulations is shown by an Advanced Resources International study. It concluded that a regulation requiring all water produced from coalbed wells to be treated before discharge would make 12 Tcf to 15 Tcf of CBM uneconomic in the area.3


Finding cost, gas recovery and well productivity also are critical elements in the life cycle economic performance of a coalbed development project. An early study by the Gas Research Institute (now the Gas Technology Institute) found CBM finding costs in U.S. basins ranged from U.S. $0.11 to $1.23 per Mcf. Black Warrior and Powder River basins reported finding costs of $0.25/Mcf; in the San Juan basin, the cost was $0.11. Coalbed methane wells typically are on 40-acre to 80-acre spacing, but San Juan wells are on 320-acre spacing, according to the study


1. Oil & Gas Journal, Dec. 23, 2002 2. 3. Hart's E&P, February 2003

Understanding Reservoirs, Keeping Costs Low are Keys to Future

Coalbed Methane's role is modest, even in the few countries with

commercial development programs. But its advantages, particularly in those regions with large coal reserves, are too important to ignore.

"A KEY advantage of coalbed methane as an energy source is its low finding and development cost." - Jonathan Kelafant, Advanced Resources International

In this article, several leading coalbed methane (CBM) production experts share their perspectives on developing this unique resource: Jonathon Kelafant, vice president, Advanced Resources International; Joe Awny, senior petroleum engineer, Equitable Production Co.; Andrew Young, regional director, Australasia for Gaffney-Cline and current president of the Society of Petroleum Engineers (SPE); Genevieve Young, president, H&Y Services; and Karl Schultz, climate protection partnership division, Coalbed Methane Outreach Program. "A key advantage of coalbed methane as an energy source, is its low finding and development cost," Kelafant said. Coal resources are fairly well defined as a result of coal exploration and information gained from drilling oil and gas wells, he said. And challenges that complicate oil and gas exploration, such as locating subtle traps, are not issues in delineating coal reservoirs. "Also, a coal seam is a `selfsourcing' reservoir. In a conventional gas reservoir, the source rock is typically not the reservoir rock, and migration can make definition of the resource more difficult," Kelafant said. Because coal seams are much shallower than most conventional natural gas deposits, drilling and other costs are lower, he said. Predominantly methane, coalbed gas generally requires little processing. Although produced at relatively low rates and low pressures compared with conventional natural gas, if reserves are close to market, it may not require significant compression.


In some regions, Awny said, coalbed methane could eventually grow from a supplement to conventional natural gas supply to a main source of gas. "The global coalbed methane resource is of some significance in the near-term energy mix, where it is currently being exploited in several countries including the U.S., Canada, Australia and China," he said. "Long term, the resource is expected to be of great significance for the U.S., India, China, Poland, South Africa, Zimbabwe and elsewhere as a main source of gas supply." In less than a decade, U.S. coalbed methane production has jumped to about 8% of natural gas consumption. "CBM is going to continue to play an increasing part in contributing to the U.S. domestic gas supply," Andrew Young said. "In countries outside the U.S., including my own country, Australia, we are

seeing significant interest and development of CBM. "Because of the major attraction worldwide of gas as a primary energy source, the key ingredients for success in the short-term of methane derived from coal seams, is where coal resources are coupled with welldeveloped gas transportation infrastructure and gas markets, such as the U.S." In the longer term, any country with significant coal resources, large populations and, hence, high energy demand, offers major opportunities for CBM development, such as India and China, he said.

U.S. coalbed methane resource map. (Graphic courtesy of Gas Technology Institute)


"The key challenge is to get development costs as low as possible, particularly drilling and completion costs," Young continued. In addition, country-specificfiscal policy and regulations can play a major role, he said. On the technical side, much of a project's success depends on well and completion designs that will maximize the area of coalbed drawdown to optimize the rate of desorption, Young said. That, in turn, provides the highest production rate. A key part of project design is optimizing the number, location and spacing of wells. "Another key technical issue is the handling and disposal of produced water at as low a cost as possible

and in an environmentally sound manner," he said. "It is important to understand what controls how methane is trapped in coal and whether it can be recovered economically," Genevieve Young said. "Factors such as the preserved gas content in the coal, the amount of water, the ability of both water and gas to flow to a wellbore, the reservoir pressure exerted on the coal and the thickness and depth are all significant. For a coalbed reservoir to be viable, all of these critical factors must exist in some unique combination." Coal reservoirs are very sensitive to drilling and fracture treatment fluids, she said. "The coal reservoir can be easily damaged by stimulation practices," Ms. Young said. "Reservoir characterization is essential, but it is not well done in coals. It is difficult to obtain well test results that accurately reflect reservoir conditions. Reservoir characterization techniques, such as simulation, are critical to a better understanding of reservoir performance, and as an aid in improving operating practices ­ well spacing in particular." Because coalbed methane production requires low-pressure pipeline systems and facilities for water disposal, Awny said, the lack of an existing infrastructure (from a conventional natural gas play) can make initial costs high. "In the geologically favorable areas, development is economic at current gas prices. But as drilling expands beyond these areas, the economics are less favorable. Higher gas prices or tax credits may be needed to make development economic," he said, summarizing the most important needs for increased CBM production as: mapping coalbed methane reservoirs; identifying factors that influence reservoir heterogeneity and permeability; understanding hydrologic and geologic factors that control storage and release of methane in coal seams; obtaining critical reservoir parameters that control production; and calculating reserves and making long-term production forecasts.

"Several advances would accelerate CBM development," Ms. Young said. "Inexpensive technology to treat produced water for beneficial surface use would make many new coalbed methane wells attractive that would otherwise be uneconomic due to water disposal costs. Improved cased-hole techniques would help identify bypassed pay zones in existing wellbores. "And technologies that improve gas-in-place determinations and identification of natural fractures and their orientation should continue to be a focus," she said. An improved diagnosis of well completions also is critical to the proper application of appropriate fracture fluids. Ms. Young added that to improve the success of horizontal wells, two primary technology needs exist: improved underbalanced horizontal and multilateral drilling methods would help, and a more inexpensive way to drill horizontal wells ­ with coiled tubing, for example. "The need for data acquisition and analysis

cannot be overemphasized," she said. "With better data collection, comprehensive play analysis can help identify and delineate new plays that have been overlooked and identify the larger targets within these areas." These regional play analyses should integrate geologic, geophysical and engineering data for accurate resource assessment, she said. Market characteristics vary from country to country, but most CBM production will find a ready market. "In a highly developed market like the U.S., it is only necessary to get gas into the distribution system and it instantly available to either spot or medium term contracts," Andrew Young said. In less developed markets, potential customers must be convinced of the level of reserves, and producers require a contract that is sufficient to stimulate development. "A different paradigm for contracting CBM gas reserves than that used for conventional gas reserves may be needed," he said. "Further natural gas reserves are somewhat easier to estimate in the absence of long-term production tests."

Global coal distribution. (Graphic courtesy of Gas Technology Institute)


Within the U.S., the Rocky Mountain region will continue to be a significant play," Genevieve Young said. Expansion of CBM's role in Colorado is an example. Seven years after coalbed methane volumes became significant enough to report, its production in the state surpassed that of conventional natural gas in 1997. By 2000, 53% of Colorado's gas production came from CBM wells. "In just the past 5 years, the

identification of significant natural gas reserves in Colorado and the greater Rocky Mountain region has further fueled interest in exploration and development," she said. During the 1990s, the San Juan Basin in Colorado and New Mexico accounted for the bulk of U.S. coalbed methane production; in the late 1990s, Colorado's greater Rocky Mountain region held first place in total proved CBM reserves. But other areas have seen more rapid growth. An explosion drilling and production in Wyoming's Powder River Basin, for example, has significantly increased estimated reserves. "The mid-continent and the Gulf Coast also present potential opportunities," Young said. "Outside the U.S., application of improved technologies and the development of adequate infrastructure will be critical to fully exploit some of these global opportunities." Operators are active in all U.S. coalbed methane basins, so there is not likely to be a significant opportunity that is not currently known. Outside the U.S., although CBM production is currently almost "too small to measure," is where the big opportunities lie, Kelafant said. "I'm very bullish on the potential outside the U.S.," he said. He estimated the global coalbed methane resource at 4,000 Tcf to 5,000 Tcf, 20% to 25% of which is likely to be recoverable. Kelafant said that for countries with coal reserves, but little conventional oil or gas, such as China, India and parts of southern Africa, CBM could offer a gas supply. A five-well pilot program is underway in South Africa, he noted. "Some countries may need incentives, at least to kick-start coalbed development," Kelafant said. Australia has a research and development (R&D) tax incentive that applies to coalbed methane. In other countries, World Bank has funded CBM development efforts, making available U.S. $10 million each to China and India, with $6 million provided to Russia. "Even though the U.S. does not need tax breaks now, the Section 29 tax rule that expired in the early 1990s was important in getting coalbed methane development off the ground. So was about $65 million in R&D funding provided by DOE [U.S. Department of Energy] and an equal amount by the Gas Research Institute," he said. "Most of the CBM wells drilled in the U.S. have been drilled since that incentive expired," Kelafant said. "For more than 10 years now, coalbed methane has competed head-to-head with conventional natural gas"There are other issues outside the U.S., such as ownership, that are obstacles to rapid development.""But wherever there is coal, there is the potential for CBM development," Andrew Young said. To determine whether that potential can be profitably exploited requires an assessment of the coal gas capacity and desorption characteristics along with the seam permeability. The depth and level of variability in coalbed characteristics ­ and the economics of development ­ then become the overriding

factors. "What is really exciting is the possibility for projects that combine CO2- [carbon dioxide] enhanced recovery of CBM and associated sequestration of this greenhouse gas," he said. The challenge is to find locations CO2 can be captured near a CBM development. "Overall, as SPE president, I am excited by the expanding role of the professional as we move into gas-based developments. Gas creates wonderful opportunities beyond traditional areas such as fuel for heat and power, including petrochemicals, fertilizer manufacture, methanol, GTL (gas-toliquid), CNG and DME." In the drive to develop access to more methane resources, economics and a country's desire to be energy self-sufficient will drive the development of unconventional gas, including coalbed methane and low permeability ­ tight ­ gas.

Coalbed gas production from U.S. lower-48 basins. (Graph courtesy of Gas Technology Institute)


As understanding of CBM resources increases and technology advances, there are areas in which improvement is still needed."The key to addressing those issues is the discovery and application of emerging technologies: reservoir simulation, innovative geophysical logging techniques and improvements in stimulation fluids, for example," Awny said, adding that part of the challenge is that mechanical and reservoir properties cannot be accurately measured in the lab. "Laboratory measurements fail to duplicate in situ stresses in coal cleats, joints and natural fractures, complicating fracture

simulation," he said. The low reservoir pressure and low relative gas permeability found in coal beds require greater fracture lengths and conductivities than sandstone reservoirs. Multiple fractures generated in the coals during stimulation cause high treatment pressures and ineffective stimulation. Dewatering poses challenges besides disposal, too. "The amount of water produced from coals may not be easily handled with conventional artificial lift systems," Awny said. Produced water also has scaling tendencies, and produced CO2 and water is a corrosive combination. "Of course, the overarching goal is to reduce the cost of developing and producing coalbed methane," he said. Gathering data for decisionmaking is a particular challenge with CBM development projects. "Sampling, data gathering and laboratory testing are all important, as is innovation in conventional gas drilling, such as extended reach/ horizontal wells, multilateral completions, underbalanced drilling and completion practices," Andrew Young said. "Measurement of CBM characteristics, such as gas saturation, desorption isotherms, gas composition, coal density and the associated variability of the coal seams' characteristics is critical. Better understanding is also needed of the permeability of the coal seam and the level of free gas in the cleats. "Certification of reserves is important. The process is different than for conventional natural gas in that production growth is tied closely to drilling of development wells. SPE definitions remain appropriate, but CBM resources are not well characterized by just a few wells."


The need that eventually led to today's coalbed methane activity is still an important one ­ mine safety. Reducing reservoir pressure during mining releases methane traditionally vented to the atmosphere, but in recent years, mine operators began to recover this vented gas. Technical advances, along with changes in the utility industry and emission offset programs, have motivated mining companies to add methane recovery units to ventilation systems. Developing international emissions trading markets could help

make additional coalmine and coalbed methane projects viable. In the context of greenhouse gases, reducing methane emissions provides considerable leverage compared with reductions in CO2, for example. Methane is considered to have 21 times the global warming potential of CO2 during a span of 100 years. Eliminating 1 ton of methane has the same impact as eliminating 21 tons of CO2. To help with the effort to reduce coalmine methane emissions, the U.S. Environmental Protection Agency's voluntary Coalbed Methane Outreach Program was established to find ways to recover and use coalmine methane. Karl Schultz leads a team focused on removing gas from coal mines. The Coalbed Methane Outreach Program team is part of the Environmental Protection Agency's (EPA) Climate Protection Partnerships Division and partners with the industry to find ways to use gas profitably that otherwise would be vented. "Coalmine Methane is a subset of coalbed methane," Schultz said. "Our focus is on putting to market the methane associated with coal production in underground mines, rather than the coalbed methane that is found in in-mineable seams." In general, the quality of gas from a mined out area is lower because it is mixed with air. The objective is to get the gas out either in advance of mining or from areas already mined out to safely and efficiently produce coal. "Many of the technologies for draining gas in advance of mining are identical to those for more conventional coalbed development," he said. "Today, technologies developed from the gas industry, such as surface horizontal drilling techniques, are being applied to expose more gas to the wellbore and reduce the development footprint. In addition, in-mine drainage and boreholes into the worked out areas of a mine remain an important part of a mine's methance recovery program." The EPA's effort to help the industry to profitably reduce emissions began in 1989. Mine operators were consulted to see whether they were interested in putting the gas to market. Feasibility studies assessed drainage efficiency and processing for pipelines and power generation options. "The result was a significant increase in the amount of coalmine gas sent to market, from 14 Bcf in 1994 to 40 Bcf in 2001," Schultz said. The amount of gas now drained and not used ­ drained only for safety ­ is only about 8 Bcf/year. The team is looking at alternative ways to use the gas, and much of the emphasis has shifted to ventilation shaft methane. "We are interested in the 90 Bcf/year from ventilation shafts in the U.S.," Schultz said. Globally, that target is 590 Bcf, representing about half the remaining emissions from coalmines. "Our ultimate goal is to get at least half of these emissions taken care of," he said. The concentration of gas in the ventilation shaft stream is low and recovery technology is being demonstrated in field-scale tests. One promising

technology is flow reversal reactors that oxidize methane at a high temperature, producing heat that can dry coal or run turbines. Financing projects is sometimes difficult. Schultz's team is looking at creative financing structures to facilitate project development. "Though the U.S. is a leader in the effort, similar coalmine gas recovery efforts are underway in other countries, including several European countries, China and Australia," Schultz said.

Stimulation Technology Helps Boost Operators' Profitability

Halliburton's specialized technologies can help boost revenue and profit from coalbed methane projects by minimizing formation damage to increase early production and ultimate recovery.

The technology also reduces the cost, time required and footprint of stimulation operations.


Applied as a post-frac treatment, Halliburton's CoalStim remediation service removes damage because of fines, gel damage, and geochemical precipitation and restores production. A decline in initial production or a departure from an inclined production slope is often a signal that a CoalStim service treatment should be considered. The service process combines a proprietary chemical formulation with a field-tested application procedure. The CoalStim agent acts to solidify the damaging particulates that reduce the ability to desorb methane and dewater coal seams. The process has been used widely in coalbed methane plays in the Uinta and San Juan basins. For most coalbed methane applications, CoalStim service offers several benefits: helps achieve increased incremental production and cash flow for a short payout time; high treatment success rate resulting in reduced financial risk; the ability to perform treatments in large sets to offset lower output wells; and optimize pilot program production results and minimize premature production declines that may negatively impact reserves determination.


Designed to take advantage of the cost effectiveness of coiled tubing, Cobra Frac service can stimulate multiple zones by straddling each individual productive stringer during a single trip into the well. Cobra Frac service teams can often treat multiple wells in a single day. Single-day stimulation helps get production on stream sooner. In addition to speed, Cobra Frac service occupies a smaller equipment

footprint than required for conventional fracturing equipment. The Cobra Frac bottomhole assembly (BHA) is a key factor. The BHA includes a specially designed straddle packer and an equalizing valve that allows tool movement without overdisplacing the fracturing treatment. The BHA design enables multiple sets on a single trip and a safety shear sub allows the release of tools.


In Colorado, where a typical well was 3,500ft (1,067.5m) deep and cut up to 20 seams that trap methane, the multiple seams had plagued operators. Early on, the most popular way to fracture groups of seams simultaneously had been to use a velocity-over-accuracy approach. But, by the end of 2000, Cobra Frac service teams were fracturing multiple seams in a single day. In a highly populated area just outside Liverpool, England, Cobra Frac service was used to accurately place 3 million lb of sand in five wells; the increased production brought significant new revenue. In Alabama's Warrior Basin, Black Warrior Methane Co. needed to stimulate production from three zones in the J&M Land 8-9-300 well. Total thickness of the three formations ­ the Mary Lee, Blue Creek and Pratt Coal groups ­ was 30ft (9.15m) and was distributed over 800ft (244m) of wellbore. Well depth was 1,950ft (594.75m), and expected production rate after treatment was about 200 Mcf/d. After all the coal zones were perforated, the fractures were created in eight stages by isolating 2-ft to 10ft (0.61-m to 3.05m) intervals. Using 27/8-in. coiled tubing, each interval was treated with 250 gal of 28% hydrochloric acid with iron control agents. A water-based 60-quality foam system was used to place 80,000 lb of proppant into the Mary Lee and Blue Creek coal groups. In addition to the Mary Lee and Blue Creek groups, the process broke down each set of perforations in the Pratt Group. Coiled tubing fracturing could not be used in the Pratt Group since each perforated interval communicated with open perforations above. The Pratt Group was stimulated by placing 70,000 lb of proppant down the 51/2-in. casing. Instead of the anticipated 200 Mcf/d, the well came in at 500 Mcf/d against a backpressure of 125psi and later was producing 600 Mcf/d.


In coalbed methane wells, SandWedge NT enhancer offers the opportunity to achieve several desirable results:

increase fracture conductivity; improve frac fluid cleanup; reduce proppant flowback; diminish the effects of fines migration; and improve the permeability of the proppant pack.

The SandWedge NT conductivity enhancement system chemically modifies the surface of proppant grains. Across a range of jobs, the system has increased production by 20% to 25%; where fines had a major impact on conductivity ­ as is often the case in coalbed methane wells ­ the improvement has been higher. When fines build geochemical precipitates that block paths in the pack, SandWedge NT can maintain conductivity by dispersing the effects of fines trapped at the formation/ proppant interface. The system also maintains proppant pack integrity, thus stabilizing the filtering mechanics. SandWedge also inhibits proppant settling in the fracture, providing better vertical distribution and increased propped fracture height. The result is greater porosity and permeability. The system helps reduce proppant flowback by stabilizing the proppant bed. Because the forces between individual proppant grains and the fracture are increased, the proppant pack can withstand a higher fluid velocity, allowing more aggressive cleanup procedures.


A high performance fluid system designed to stimulate production from coalbed methane wells, the Delta Frac® CBM service meets U.S. Federal Clean Water Act requirements, an important advantage in coalbed methane (CBM) development. Requirements for aromatics, such as benzene, have been achieved without affecting fluid performance. A low polymer borate fracturing fluid suitable for bottomhole temperatures to 200°F (93.24°C), Delta Frac CBM service provides several benefits: reduces polymer loading required to obtain necessary viscosity; helps reduce formation damage; provides superior retained conductivity; provides excellent proppant transport; and achieves clean, complete breaks.


Three wells in the Fruitland Coal in northern New Mexico's San Juan Basin were not producing up to potential, each averaging about 200 Mcf/d. All three wells were almost identical in depth, hole size and formation conditions. Between 95,000 gal and 100,000 gal of Delta Frac service 20-lb frac fluid was used to carry over 300,000 lb of proppant into each well through 51/2-in. casing. In the well treated only with Delta Frac service, the anticipated production increase was achieved. But production from the two wells

treated with Delta Frac with Sand- Wedge services almost quadrupled, and the wells still flowed without artificial lift several months after the job. The production increase and lifting cost savings created an additional economic value of more than U.S. $60,000 per month for the operator. In the San Juan Basin, additional cavitation had increased production to about 700 Mcf/d from a well that was producing from an open hole in the Basal Fruitland Coal through a cased hole in the Upper Fruitland Coal. Halliburton recommended fracturing the Upper Fruitland Coal at about 3,000ft (915m), using the SandWedge service as part of a 20-lb Delta Frac service treatment. After sand cleanout, production began to build almost immediately. Within 21/2 months, output was almost 1,200 Mcf/d and no sand had been produced since the initial excess was cleaned out. Total added economic value from increased production during this period was about $132,100. In another San Juan Basin Fruitland Coal job, water had to be pumped off for 6 months before gas sales could begin, and the well only produced 30 Mcf/d. SandWedge service with a 20-lb Delta Frac service stimulation treatment was used on a new well to enhance conductivity and help solve the severe sand production problems. After fracturing, the well began flowing immediately. Sand cleanout costs were minimal and pump change costs were eliminated. After being shut in for about 3 months to prepare for production, the well began producing at 457 Mcf/d and climbed at a rate of 40 Mcf/d to 50 Mcf/d for some time. Primarily because of SandWedge technology, the added economic value was about $185,000 in the first year of production. Delta Frac Service and SandWedge conductivity enhancer also helped a major operator add coalbed methane production worth an estimated $10 million/year from 10 coalbed wells in New Mexico's San Juan Basin. Unlike other area operators, who traditionally had drilled another blind sidetrack wellbore that had to be cased and cemented, the Delta Frac with SandWedge treatments called for hanging an uncemented liner inside the existing 7-in. casing and then perforating at four shots per foot. The wells that had been completed open hole were cavitated. The treatments were pumped at a rate of 65 bbl/min using a 20lb/1,000-gal Delta Frac service fluid to place 5,000 lb of 20/40 sand/ft of net coal. All proppant was coated using the SandWedge service. Average production from the under-performing wells increased by 2.4 fold to more than 14.8 MMcf/d. Treatment costs were recovered in 3 months.


If evaluation of a prospective coalbed area indicates it can be profitably exploited, a structured assessment of the reserve can help determine the best development approach. In SPE paper 75684, Dana Weida, Technical Advisor--Reservoir on Halliburton's Eastern Business Development Technical Team, said this phase of "local asset evaluation" should result in a "high degree of confidence in either condemning or moving forward on an area. This "structured resource assessment" should also provide the data necessary to conduct reservoir simulations and demonstrate production potential. Moving from lower-cost to higher-cost, structured evaluation options include: a core hole to obtain full cores and geophysical logs; a full-size wellbore for open hole or cased-hole pressure transient testing; a five-spot pilot for interference and production testing.

Core and log data help determine gas-in-place and the potential for water production from adjacent intervals. Single-test wells, used to determine absolute permeability, can also be used for a fully stimulated production test. With data from the core hole and single-test wells, reservoir simulation, net present value (NPV) calculations, measured values and a range of sensitivities provide the information needed to estimate production potential. A five-spot production test program is conducted if justified by the economics based on this estimated production potential. The five-spot program should include interference testing ­ which can yield permeability, anisotropy and orientation ­ and production testing. Data derived from this structured local assessment program is then used as simulator input.


The best well pattern is one that maximizes the difference between production NPV and capital investment, Weida said. Acquiring reservoir data and performing reservoir simulation is the only way to determine an economically optimized well pattern. Geospatial well pattern and completion practices determine field-wide production rates, ultimate recovery and cumulative gas production.

Well pattern refers to spacing and well location. In the United States, wells are usually placed on a northsouth and east-west grid system. But a staggered rectangular pattern aligned with the fracture and face cleat can also be effective, Weida said. For a minimal cost, simulation can provide an economic assessment, and compare well patterns and completion options. Although completion practices based on trial and error may be perceived as a low-cost strategy, it usually is not, Weida said.

Coalbed Methane: A Range of Solutions Available, More Technology on the Way

Halliburton has a field-proven package of cost-effective coalbed methane technologies that use special fluids, equipment and procedures to remove wellbore damage and improve flow through fractures.

A long with fit-for-purpose equipment that speeds treatments and has a smaller footprint, these systems can improve financial performance and lower risk. Though much technology is available today to improve recovery of coalbed methane (CBM) and reduce development costs, some is under used, often letting an opportunity slip by to enhance project economics. Emerging technologies span the spectrum from those likely to be developed to "blue sky" ideas. In between are extensions of technology that soon could provide real savings and significant production increases. With a leading role in CBM well completions and CBM development, Halliburton has taken a comprehensive look at the impact available and emerging technology could have on CBM costs and recovery.


Today's horizontal and multilateral drilling capability can offer much for CBM development. The anisotropic cleat permeability in most coals limits production from seams with low average permeability, though often, permeability is low in only one orientation. Efficiently drilled horizontals can open these marginal permeability plays. As the technique gains acceptance during the next 5 years to 10 years, it could boost expected ultimate recovery by 50%. Multiple laterals can drain hundreds of acres from a single surface location. Industry trials are draining 85% of gas in place in 1,280 acres from five wells (five-spot pattern, 300-ft ­ 91.5-m ­ spacing) in only 2 years. An up-front cost of U.S. $2.5 million represents about $1.50/Mcf. This compares favorably with drilling 32 vertical wells on 40-acre spacing at a cost of $8 million. A central production facility also

reduces operating costs. This concept is set to gain wider acceptance, especially for degasification ahead of mining. Another drilling technology poised for expanded application is air coiled-tubing drilling. It can cut drilling time by 50% and reduce the footprint on vertical wells. During the next 5 years to 10 years, costs could be reduced 25% to 50% by the development of area-appropriate equipment. Stimulation understanding: The complexity of CBM fracs exceeds current modeling capabilities. FracTrac® tiltmeter and micro-seismic mapping, and pressure transient testing can help optimize treatments in areas still in the initial development phase. Though available, the technology is underused. Optimizing hydraulic fracture treatment size and fluid could yield 20% to 50% greater ultimate recovery at a minimal incremental cost. Well spacing and geospatial well pattern: Coalbed methane wells are typically drilled on 80-acre to 160-acre spacing, often with limited knowledge of the reservoir. Some wells on excessive spacing have not seen maximum desorption rates, even after 8 years of production. The correct spacing and pattern allows peak desorption within 1 year to 3 years. Technology is available to optimize well spacing using pressure transient and interference testing, and well spacing is likely to get more emphasis as more marginal plays are pursued. As much as a 100% increase in net present value could result from better well placement.

Infill drilling:A recent project involved infill drilling that reduced 80-acre spacing to 40 acres. New wells outperformed old ones and production improved in the old wells. The operator now has 600 new drilling locations with better economics than the original program. Now cautiously being investigated in major CBM basins, the infill drilling concept could be a widespread practice within 5 years, yielding 75% to 150% increases infield recoveries. Continuously variable pump controllers: As water production decreases during the life of a CBM well, termittent pump operation and changing pump sheaves is usually the solution. But the instantaneous changes water flow resulting from intermittent pumping releases migrating coal fines. That leads to proppant pack ugging, loss of production and damage to downhole pumps. Continuously variable pump controllers that

it could possibly boost ultimate recovery by 5% to 10%. Though this technology is available, it is likely to see slow implementation.

Coalbed methane fracture treatment near Durango, Colorado

Nitrogen foam cement: Coal zones usually have normal or subnormal pressure gradients, which can allow a significant influx of cement. Nitrogen foam cement has a density approaching that of water while still providing adequate compressive strength. Ductile foam cement also is resistant to fracturing when perforating. Routine use of this technology, likely within 5 years, could add 5% to 10% to ultimate recovery. Coiled tubing frac: Midcontinent and Eastern U.S. basins typically have six to 15 producible coal seams; single-zone stimulation is usually preferred. Available systems, such as packer and plug, ball and baffle, and drillable frac plugs are cost prohibitive or inadequate for the large number of seams. Coiled tubing systems are ideally suitable and could begin to have an impact this year if enough units are available. The increase in ultimate recovery could be 15% to 30%. Enhanced cavitation: Cavitation is used to enlarge the wellbore and enhance permeability. Wellbore enlargement can be promoted with hydraulic jetting. Permeability enhancement resulting from cleat realignment during overpressuring would be accelerated with high rate nitrogen injection. The technology is available to reduce cavitation time by 4 days to 6 days and increase production rates by 5% to 15%.

Halliburton's Cobra Frac service uses coiled tubing to isolate and stimulate multiple zones.


Downhole water injection pumps are available, but limited fines tolerance hinders their application in coalbed wells. Better technology is thought to be 10 years to 15 years away. Well location size is an issue for cost and environmental reasons in many basins. Small footprint rigs that can be transported in one or two loads ­ or a self-propelled unit and a single additional load ­ could reduce location size and might trim $15,000 from location cost in rough terrain. Units could be available now by special order. By eliminating large mud and flare pits, and blooie lines, closed loop air drilling also could reduce location

size, saving $20, 000 to $30,000 per well in mountainous or environmentally sensitive areas. It might take 2 years to 5 years to develop the technology. Casing drilling with air would provide the advantages of air drilling and casing drilling, possibly saving $10,000 per well. The technique also could be ready in 2 years to 5 years. Continuous drilling with spooled casing (41/2-in. or 51/2-in.) would increase penetration and eliminate the time required to run casing. It could take 3 years to 7 years to develop the metallurgy and another 5 years to deploy. But cost savings could amount to $10,000 to $20,000 per well. Perforations do not give adequate formation access for stimulation or production in very thin coal seams. Cutting slots with hydraulic jets with real-time depth control provided by a gamma ray density tool would help. It could take 10 years to 15 years for technology development and deployment, but ultimate recovery in areas such as Appalachia could increase by 20% to 30%. Sequentially stimulating multiple coal seams with jet slotting and a coiled tubing deployed bridge plug could cut completion cost by $10,000 on a typical Appalachian well and boost recovery by 20% to 50%. Logging tools for behind-pipe coal identification would eliminate lost rig time while logging, perhaps saving $3,000 per well. Development time is estimated to be 5 years.


Although technology can reduce bottomhole flowing pressure to as low as 30psi to 50psi, as much as 20% to 40% of GIP is not recovered. Downhole gas compression could produce the gas left behind, but 10 years may be needed to develop the technology. Flue gas sequestration enhances methane production because of the preferential adsorption of carbon dioxide (CO2). The U.S. Department of Energy is conducting field trials for smokestack effluent disposal in coal. In 10 years, enhanced recovery because of flue gas sequestration could yield ultimate recovery increases of 20% while providing a tax credit for disposal. Other emerging technologies are aimed at solving water cleanup and water disposal problems, enhancing cleat permeability with hydrogen peroxide and developing filtration processes that will clean water to a potable level.

Hydrogen peroxide can remove formation damage and enhance primary production in a variety of well and formation types


Hydrogen peroxide (H2O2) is a powerful oxidizer that can dissolve organic polymers and residues. It can remove formation damage and enhance primary production in a wide range of well and formation types. Its use has been limited in oil and gas wells because of the lack of an adequate, safe delivery system for large volumes capable of pressure injection. Application also was limited by the lack of process knowledge and poorly understood risk factors. A Halliburton team focused on the most challenging issue ­ the catalytic decomposition reaction with metals, including steel tubulars and pumping equipment. Successful development of their process was driven by the need for a favorable environmental profile and the ability to handle a wider range of applications.

Fit-for-purpose hydrogen peroxide delivery system includes a prototype pump unit.

The resulting process consists of the following elements: dilution system: On-site, on-thefly H2O2 dilution allows for large volumes to be economically delivered to location in concentrations up to 70% for mixing in a special tank; chemical delivery system: Fit-forpurpose H2O2 delivery system includes a prototype pump unit engineered and built specifically for H2O2 chemical compatibility using cutting-edge composite coil tubing; chemical stabilization system: An additional chemical solution has a chemical stabilizer for redundant protection and integral control, and to trigger the release of the peroxide decomposition reaction where it is needed; and operational process planning and safety engineering: Detailed process planning and engineered controls includes contingencies to allow safe and reliable implementation and field scale-up of the process. Last year, a treatment involving the largest volume of H2O2 pumped into a producing well was successfully performed in La Plata County, Colo., for a major operator. More than 3,500 bbl of fluid were pumped, placing 100,000 gal of 3% H2O2. The project was part of the field trial phase of a 2-year joint development effort, a planned six-well pilot study to evaluate the technical and economic merits of H2O2 technology for coalbed methane production enhancement.

Send questions or comments about this site to Halliburton Service Center or call U.S. (877) 263-6071 or outside U.S. (281) 9834900. Copyright © 2009 Halliburton. All Rights Reserved. Terms and Conditions Privacy


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