Unconventional gas vital to US supply

Feb. 28, 2005
Unconventional gas resources have become a major source of US supply over the last 20 years and will be even more important in the future.

Unconventional gas resources have become a major source of US supply over the last 20 years and will be even more important in the future.

US gas supplies increased overall to 19.4 tcf in 2003 from 19.2 tcf in 2000. Yet conventional gas production declined in that same period, while unconventional gas production increased by 1 tcf. Production of tight-sands gas increased to 4.6 tcf from 4 tcf, while coalbed methane (CBM) production rose to 1.6 tcf from 1.4 tcf.

"The largest percentage increase was in gas shale, from 0.4 to 0.6 tcf, largely coming from the Barnett shale, the most active and by far the largest producing gas-shale play in the US today," said Scott R. Reeves, executive vice-president of Advanced Resources International Inc., Houston.

Unconventional gas production is expected to grow to more than 10 tcf/ year in 2005 from around 5 tcf/year in 2000, according to industry experts.

Click here to enlarge image

Of the 12 largest US natural gas fields listed by the US Energy Information Administration, 9 are classed as unconventional. Known resources of unconventional gas are broadly distributed across the Lower 48 (see map).

Unconventional gas plays are keeping dozens of rigs busy in several states and likely will continue to do so for a number of years, say industry experts. The Fort Worth basin Barnett shale gas play, confined to North Texas Dist. 9 for several years, is beginning to spread south into Dists. 5 and 7B. It is the state's busiest play in terms of rigs running and number of wells being drilled (OGJ, Jan. 17, 2005, p. 32).

Unconventional plays dominate gas drilling in the Rocky Mountains. In Wyoming, the state oil and gas supervisor estimated 2004 gas drilling at 3,180 CBM wells and 800 other gas wells. Unless commodity prices plummet in 2005, the supervisor is projecting 3,300 CBM wells and 900 other gas wells.

Unconventional resources represent more than 35% of the undiscovered gas potential in the Lower 48. The Rocky Mountain region contains most of the unconventional gas resource and is expected to increase unconventional gas production by 50% by 2020.

"The ability to continue growing nonconventional production [tight gas, CBM, and gas shale] will be critical to sustaining production levels," said the National Petroleum Council in its most recent report. "Aside from the deepwater Gulf of Mexico, the only US basins maintaining sustainable production increases (Rockies, East Texas-North Louisiana) are being driven by increased nonconventional production."

Excluding unconventional and deepwater gulf gas, the average estimated ultimate recovery (EUR) per gas connection in the Lower 48 fell 15% in 1990-99 as that resource base matured and as technology gains and higher commodity prices made smaller prospects more economic to develop. When drilling ramped up in response to the 2000-01 gas price spike, the average EUR fell a further 18% with a greater number of marginal wells being drilled.

"The growing contribution to supply from nonconventional resources is projected to offset the production decline from conventional sources in a robust price environment. The increase in production from this segment reflects access to and development of large nonconventional resources, particularly in the Rocky Mountain region," NPC said.

A difficult resource

Unlike conventional resources, unconventional gas is difficult to produce because of low permeability or poorly understood production mechanisms.

"The technical difficulty is also associated with tenuous economies," said Kent F. Perry, director of exploration and production technology at Gas Technology Institute.

He classifies unconventional gas into four primary categories: tight gas sands, CBM, Devonian shale, and natural gas hydrates. What those resources have in common, said Perry, "is that they require new technology development to be produced at market-clearing prices."

Some of the technology that has aided development of unconventional gas resources include "lateral wells, the ability to stay in thin zones and to identify natural fractures in these very low permeability formations—certainly the improvement in seismic, 3D, 4D, vertical seismic profiling across wells to help delineate these smaller, hard-to-see targets. Well completions and hydraulic fracturing technologies have improved quite a bit," said Perry.

However, he said, "We're probably starting to see signs of slipping behind in keeping up with the quality of the reservoir, as far as needing technology improvements. The emphasis seems to be slipping a little bit in the domestic resource phase in that the big companies tend to go overseas and the big service companies follow their customers," leaving the domestic resource "a little bit on the ignored side."

Development of tight sands, CBM, and other unconventional gas resources was stimulated 20 years ago by a combination of performance-based incentives in the form of the Section 29 federal tax credits, as well as research under both the Department of Energy and the Gas Research Institute. Both programs have ceased. Yet unconventional gas production continues to grow, demonstrating its commercial viability without incentives.

Tight gas sands

Although they vary considerably in size, location, and quality, tight gas sands are sandstone formations with less than 0.1 md permeability.

They also are the most widespread of the currently producible unconventional gas resources.

Union Drilling Inc.'s Rig 39 drilled the Lawson B25 well for Cabot Oil & Gas Corp. to a TD of 3,610 ft in Logan County, W.Va., in April 2002. The well, completed in the Devonian shale and Mississippian Injun and Big Lime, currently produces 60 Mcfd. The rig is currently drilling for Cabot in southern West Virginia.
Click here to enlarge image

"All geologic basins in the US contain some tight gas," said Perry. "Only a small percentage is economically viable with existing technology."

Production of tight gas has been greatly aided by improvements in hydraulic facturing technology, Perry said. By 1970, some 1 tcf/year was being produced in the US. Increased commodity prices and technology improvements in the latter part of that decade resulted in rapid development of tight gas sands in several parts of the US. Tax credits and continued development of new technology had production levels exceeding 3 tcf/year in the 1980s.

"Between 1970 and 1999, tight production from the Lower 48 US increased from 0.8 tcf to 3.3 tcf, accounting for 19% of the total Lower 48 gas production," said Perry. According to GTI's most recent study, he said, "By 2001, some 40,000 tight gas wells were producing from 1,600 reservoirs in 900 fields."

Five basins—South Texas, East Texas, the Permian in West Texas and New Mexico, San Juan in New Mexico and Colorado, and Green River in Wyoming—have dominated tight sands operations. The San Juan is the most mature of those basins so more drilling activity is now being seen in the other four basins, said Perry.


Cumulative gas production volumes have exceeded initial gas-in-place estimates in many established CBM plays.

"For example, the 10-year cumulative gas production of 23 wells in the Oak Grove field in the Black Warrior basin was 3.2 bcf, more than double the initial gas-in-place estimate of 1.55 bcf," said Perry.

"Cumulative gas production volumes for many coalbed methane wells in the San Juan and Powder River basins also exceeded initial gas-in-place estimates. This underestimation indicates that the reservoir parameters used to calculate the initial gas-in-place values were inaccurate and that potential may exist for significant reserve volume gains in other fields as well," he said.

There are three parameters for determining the amount of CBM in place: the amount of free gas within the cleat system, the gas dissolved in water in the natural fracture system, and the volume of gas adsorbed within the coal matrix.

"This latter number can represent greater than 95% of the gas volume and must therefore be carefully calculated," Perry said.

Producers commonly can recover 50-70% of the initial gas in place in CBM reservoirs.

"This type of recovery, somewhat lower than for conventional reservoirs, is an inherent feature of the pressure-depletion recovery method that is universally utilized in the production of coalbed methane," said Perry. "This method involves continuous removal of water from the natural fracture system, causing a progressive reduction in the reservoir pressure, which in turn results in the desorption of the sorbed phase gas from the coal."

He said, "There are both practical and economic limits on the extent to which average reservoir pressure can be reduced using this methodology." As a result, the gas industry has devised enhanced recovery technologies to accelerate CBM production rates and also overcome limitations of the recovery method. One technology involves injection of nitrogen or carbon dioxide into coalbed reservoirs to promote desorption.

"These technologies can increase gas production rates as much as six-fold and increase producible gas reserves as much as two-fold, enabling commercial exploitation of resources that otherwise would remain undeveloped," Perry said.

The three most active CBM play areas are in the Powder River, Uinta, and Raton basins, with Powder River the most active of the three. In 2000, CBM production from those basins totaled 250 bcf from more than 2,200 wells.

US production of CBM grew to 1.6 tcf in 2003 from 150 bcf in 1989.

According to Raymond C. Pilcher, president of Raven Ridge Resources Inc., Grand Junction, Colo., government incentives were crucial to growth in the early years.

"One of the things that spurred CBM development in the late 1970s and up through the early 1990s was, in fact, the Section 29 [US] tax credit," he said at an energy conference in Denver late last year (OGJ Online, Dec. 29, 2004). "It had a very large impact. At the point that the tax credit peaked, we were looking at almost twice the sale price of natural gas, so if someone had that tax credit they had quite a benefit."

In its development of CBM in the US, the natural gas industry applied existing technology in new ways. Technology is still being adapted to CBM and other unconventional gas resources, said Pilcher.

"Even in CBM, we have not reached the full physical potential. If you look at what's going on in the San Juan basin today, there are wells that have been productive that are being reentered and new technology is being applied, and more gas is being produced. There's in-fill well drilling, and now there is a lot of work in basins where there was [previously] no suspicion of there being producible natural gas," he said.

"The Green River basin contains 314 tcf, by far the single largest resource base of CBM. We think that's going to be a place of increasing activity. The coals are very deep there and will require special technology. We think something like enhanced CBM technology will help unlock that," said Reeves.

Devonian shale

In shale reservoirs, natural gas may exist as free gas within the rock pores, as adsorbed gas in organic material, and as free gas within the system of natural fractures. Those different storage mechanisms may affect the speed and efficiency of gas production, Perry said.

"Every gas-shale play is unique and must be examined, explored, and exploited differently," he said.

Shale-gas plays have three key advantages: moderate exploration costs, high success rates, and slow production decline rates.

"The rapid growth in gas-shale well completions that occurred during the late 1980s and early 1990s in the Antrim shale play in the Michigan basin has been repeated today in the Fort Worth and San Juan basins, driven by the powerful economic incentives of low risks and low finding costs," Perry said.

Perry defines shale gas as gas in which an organic shale interval is both source and reservoir.

"Fractured shales have been a source of gas for the US gas industry since its earliest days. The first known commercial natural gas production from the US was from a fractured shale reservoir in the Appalachian basin," he said.

In 2001, more than 28,000 gas-shale wells were producing nearly 380 bcf/year of gas from five basins: Appalachian, Michigan, Illinois, Fort Worth, and San Juan. Gas-in-place estimates for those five plays totaled 580 tcf prior to development of the Barnett shale, with recoverable resources estimated at 30-76 tcf, excluding the Lewis shale, said GTI.

In the 1920s, gas was produced from the black, highly carbonaceous Pennsylvanian Cherokee Group Fort Scott shale in eastern Kansas and in Jackson and Cross counties in Missouri. Since the late 1980s, gas also has been produced commercially from the fractured Pennsylvanian Excello shale in the Cherokee basin of southeastern Kansas.

"While the Appalachian basin has provided the bulk of historical shale-gas production because of its proximity to East Coast markets, the newer shale-gas plays are sustaining the contribution of this unconventional resource into the 21st century," said Perry.

"Operators have shown that natural gas production from a variety of fractured shale reservoirs can yield favorable financial returns when the unique characteristics of each reservoir are understood," he said. "Every new shale-gas play has presented technical challenges that operators have overcome by identifying and solving play-specific problems. Their success in these relatively low-cost plays has sparked a resurgence of industry interest in evaluating the production potential of the shale-gas resources present in basins throughout the US."

Perry said, "The major exploration risk in most shale-gas plays is generally not the drilling of a truly dry hole, but rather in not obtaining an economically viable gas production rate. Most shales have very low (micro-darcy level) matrix permeabilities and require the presence of extensive natural fracture systems to sustain commercial gas production rates."

Production from gas shale, too, began in the early 1980s at low rates with the help of Section 29 tax credits and research support from DOE and GTI. However, Reeves said, gas shale "did not grow as fast as CBM; it's a little behind the curve. Still, there was growth in gas-shale production from 1992 through today, commercial without incentives." US gas-shale production grew to 600 bcf in 2003 from 65 bcf in 1980.

For gas shale, said Reeves, "We see perhaps not anything like enhanced CBM as being a driver of commercial production, but really since gas shale's development and plays are much less mature, we see the growth there to be in new plays that have not yet been developed and gas shales that have not yet been fully assessed today."

Gas hydrates

Commercial production of natural gas hydrates awaits technology development and market access, Perry said, calling gas hydrates "an important resource for long-term gas supply."

Gas hydrates are a unique class of chemical compounds in which molecules of the guest material are enclosed within the open solid lattice of a host material, without bonding chemically, to form clathrates. Common examples of gas hydrates are methane and water or carbon dioxide and water (OGJ, Feb. 7, 2005, p. 43; Feb. 14, 2005, p. 45).

Humphrey Davy, the 19th century English chemist who discovered the anesthetic effect of nitrous oxide, and his assistant, Michael Faraday, known for pioneering experiments in electricity and magnetism, discovered clathrate compounds in a winter experiment with chlorine-water mixtures in the early 1800s. They found that as the mixtures cooled, a solid material formed at temperatures above the normal freezing point for water.

Helmerich & Payne Inc.'s Rig 235 drills a natural gas well for Devon Energy Corp. in the Barnett shale in Denton County, Tex., in late 2004. The rig is one of a dozen units that Devon Energy currently has drilling in the Barnett shale.
Click here to enlarge image


In the late 1960s, naturally occurring methane hydrates were found in the giant gas fields of western Siberia and on Alaska's North Slope. In 1974, Soviet scientists recovered large hydrate nodules from the floor of the Black Sea. In the early 1980s, the Glomar Challenger drillship found evidence of methane hydrates in cores from the ocean bottoms as part of the Deep Sea Drilling Project.

In the late 1990s, the first two wells were drilled to explore for methane hydrate. The first, Mallik 3L-18C, was drilled below permafrost in the Mackenzie River delta of Canada's Northwest Territories. The second was drilled by a Japanese consortium in 3,100 ft of water adjacent to the Nankai Trough off southeastern Japan. Both showed presence of large volumes of methane hydrate.

DOE and Texas A&M University, through the Ocean Drilling Program, have continued to recover and analyze deepwater samples of methane hydrates.

"The US Geological Survey has estimated that there is more organic carbon contained as methane hydrate than all other forms of fossil fuels combined. In fact, methane hydrates could provide a clean source of energy for several centuries," said Charles E. Taylor of the DOE and Jonathan T. Kwan, of the University of Oklahoma, in the preface to the book they edited, Advances in the Study of Gas Hydrates. They expect hydrates to become a commercially viable product "in the next 10 to 15 years."