Unconventional Gas Resources

Unconventional gas resources fill the gap in future supplies

In North America, there should be enough gas to go around for years to come, but it will increasingly be from low-permeability, low-flowrate unconventional gas deposits. With a little technological boost, this may be the lower-risk path.

Perry A. Fischer, Editor

It was just 1998 when US wellhead gas prices averaged $1.96/Mcf. Those days are long gone. Nobody thinks of $2 gas anymore. Going forward over the next 15 years, the lowest estimates by industry pundits are well over $3, while the high end is about $6. Will industry be able to meet the demand? The answer is a resounding “yes,” but only a sustained, robust effort will keep North America supplied with gas.

The above scenario is the conventional wisdom. The only caveats to bear in mind are that virtually everyone subscribes to it – and historically, markets usually prove everyone wrong. Also, these are the same experts that told us in 1998 that US gas demand would be soaring by now and that wellhead prices would rise to $2.81 by 2020. Those earlier forecasts were profoundly wrong, calling for some 2.4 Tcf, or 12.6% more demand than is currently the case. The once-ballyhooed 30 Tcf US demand by 2015 – 2020 is not to be. The simple explanation is that consistently high prices – double to triple those of just a few years ago – have lowered demand.

Nevertheless, “tight” is the operative word, not only for describing the present supply and demand situation, but for the subsurface geology as well. There are rumblings that the problem is a lack of resource, but government and private estimates say the resource exists. However, excluding arctic regions, most of the resource exists in the form of unconventional gas deposits.

OVERVIEW

Unlike conventional reservoirs, which are discrete accumulations that often produce at high rates, these unconventional, or continuous, gas deposits produce at much lower rates and include low-permeability sands, fractured shales, coalbed methane, and possibly, someday, methane hydrate.

Unconventional gas resources, which do not have obvious sealing and trapping mechanisms, are typically not driven by water. These gas resources are estimated at more than 350 Tcf.¹ Some 169 Tcf are in the Rocky Mountain region, which now account for about 25% of all US gas production.^2,3 They have a high probability of geologic success and are sensitive to pricing and technology changes, as well as government incentives. In Canada, these resources are only at the beginning stages of development, and are estimated between 290 and 1,800 Tcf.³

Of the total unconventional gas resource base, tight gas sands have the largest proven potential. According to a recent study by the Gas Technology Institute,¹ tight gas sands in the US comprise 69% of gas production from all unconventional gas resources and account for 19% of the total gas production from combined conventional and unconventional sources. The same study 1 estimates tight gas sand economically recoverable reserves to be 185 Tcf.

TIGHT GAS SANDS

These continuous sand formations are common, and progress in a seamless way from appearing conventional – when operators have been fortunate to intersect a dense natural fracture network – to extremely tight, with permeabilities in the microdarcy-range. Generally speaking, their economic development depends on technology advances in: determining precise well placement; advances in fracturing, fracture fluids and proppants; multi-zone completions; and much denser well spacings, in some cases down to 10 acres.

Some fields, previously thought of as conventional, are now recognized as part of a continuous trend. Identification of fracture densities within these trends, together with their orientation and the ability of the drilling team to plot a wellpath that intersects as much of these as possible, will help determine production. Finding the right drill site involves identification of fracture-induced anisotropy in these tight gas sands. Multiple-azimuth 3D seismic attributes and petrophysical data analysis, together with integration of production and other data, resulted in a successful well for Burlington in a recent DOE-funded project, Fig. 1.

Fig. 1. Composite-attribute map, showing seismic lineaments (pink lines), high lineament density (red outlines), favorable AVO attributes and low clay (blue). Many of the weakest producers in this field would not have been drilled if based on this assessment methodology. From World Oil, September 2002. Courtesy GeoSpectrum, Inc., Midland, Texas

In situ resource estimates in the US range from 10,000 to 20,000 Tcf and even higher, but economic development of these reservoirs is challenging, since such low permeabilities do not favor gas flow toward wellbores. There are about 40,000 wells producing gas from tight sands, with production per well averaging 170 Mcfgd. A small percentage is economically viable with present technology, particularly well stimulation, but that is likely to improve.

SHALE GAS

Since the 1920s, the Devonian shales of the Appalachian basin have produced most of the shale gas in the US, with over 21,000 wells. And this continues today. However, new plays in the Fort Worth and San Juan basins have become significant new gas sources in the last few years. These areas, together with contributions from Michigan and Illinois basins, have allowed more than 37,000 shale-gas wells to account for 3 – 4% of US gas production – a percentage that is expected to increase. In Canada, a 2002 Gas Technology Institute report concluded that the Western Canada Sedimentary basin held 86 Tcf of shale gas in place, but recoverability has not been established.

Gas is stored within a shale sequence mostly in two ways. One is as an adsorption of gas into kerogen (an insoluble, organic oil precursor). This portion can range from 20%, as in the Barnett Shale in northern Texas, to 85% in the Lewis Shale in New Mexico/ Colorado. This adsorption aspect has similarities to gas in coalbeds. Silts and kerogens within the shale can be active sources for both biogenic and thermogenic gas generation. The second way is similar to more conventional reservoirs, with free gas occupying matrix and fracture porosity, both within the shale and within interbedded sand lenses.⁴

Recovery factors vary between 5% and 20%, sometimes higher. Porosity typically ranges 3 – 10%, often half-filled with gas, the rest water.⁵ Because they usually have some conventional porosity, gas shales are subject to pressure variations due to compression. They typically have low permeability, resulting in low production per well (<100 Mcf). The key to profitability is often reducing decline rates, to make up for low flowrates with a long production life. Expect improvements with new techniques. These wells are almost always fracture stimulated, which can get expensive, so careful control of drilling and completion costs is essential.

COALBED METHANE

According to USGS, worldwide, coal contains between 3,500 and 9,500 Tcf of in situ gas, with 1,000 to 3,000 Tcf in North America. Worldwide, some 34 countries have coalbed methane (CBM) exploration activity, with about half actively producing from CBM wells. In the US, CBM production, at 4.6 Bcf a day, is about 9% of total US gas production. The potential exists to someday double that rate, producing up to 3 Tcf annually. CBM is now 10% (18.5 Tcf) of US proven dry gas reserves (187 Tcf). Ultimate recoverable CBM is estimated at 63 Tcf,² with 42 Tcf located in the Rocky Mountains. In Canada, the coalbed industry is just getting started, but recoverable reserves are estimated at lying between 20 and 100 Tcf in the Western Canada Sedimentary basin.⁶

The US has been leading the world in CBM development. Production has gone from near zero to nearly 1.7 Tcf from about 18,000 wells, Fig. 2. World Oil's surveys of state agencies and operators shows that over 4,200 CBM wells were drilled in 2003, and another 4,600 are forecast for this year. The majority of these wells are being drilled in the Powder River basin in Wyoming.

Fig. 2. Soaring US coalbed methane production.

Environmental issues have slowed development. Dewatering is an essential step in most CBM wells, as gas will not flow until the water has been removed. This is a substantial cost for operators, as pumps must be powered by fuel, handle fines, and pump tens of thousands of gallons of water. While there are a few producing coal seams at record 8,000-ft depths (in Colorado), CBM seams are often so shallow (500 to 800 ft) that the water is actually part of the surface water aquifer. While generally not potable, this water is occasionally suitable for crops and livestock. Nevertheless, collectively, it's enough water to form a small flowing river, and it is often laden with salts and sediments that become part of the surface soils. Thus, its continuing environmental impact is closely watched.

Most often, ranchers and those with interests in the area can be willingly bought out, but there is the occasional holdout who neither wants to sell his land or see any negative surface effects. After a lengthy four-year process, recent finalization of the Environmental Impact Statement means that up to 50,000 more wells can be drilled in the Powder River basin area. Our survey shows that over 6,500 CBM permits are expected to be issued this year in Wyoming (see Table).

Better logging, fracturing and resource assessment methods have made a considerable difference in CBM economics. These show no signs of leveling off. Fracturing efforts generally do not achieve the penetration and coverage in coals that they do in sandstone. It is estimated that if fracturing in coal seams could be brought to parity with that of sandstone, recoverable gas in CBM plays could be tripled.⁷

METHANE HYDRATE RESEARCH

You will often read that methane hydrates (MH) have several times the energy resource of all the oil and gas deposits in the world. However, strictly speaking, calling methane hydrates a resource is inaccurate, since it has yet to be proven that they can be economically produced. The most recent results at the Canadian arctic Mallik site were encouraging and gathered a wealth of scientific data, but were far from conclusively proving MH as a resource ( World Oil, What's new in exploration, Jan. 2004). In these tests, production was initiated from a vertical section of hydrate by depressuring and heating, while two adjacent wells were monitored. The tests established the theoretical and technical feasibility of producing MH by these methods, while leaving questions of sustained production, maximum rate and ultimate recovery unanswered, as well as, of course, economic viability.

Hydrates exist at relatively shallow depths in deepwater and permafrost regions, the latter being the easiest, cheapest and most viable for research and testing purposes, discounting distance to markets, of course. While the Mallik tests did establish production, such rates (a maximum of 53 Mcfd, but generally much less) are far from establishing whether methane hydrates are a bona fide resource. To do that, it is necessary to establish what the maximum production rates are in an extended well test, and then the overlay of economic analysis can begin. Mallik is a near-ideal hydrate site for such a test. Outside of permafrost regions, distribution of hydrates is believed to be much better (closer to markets) worldwide, occurring in deepwater areas off most continental shelves. However, the economics of methane hydrate exploration and production become even more challenging in the deepwater environment, with what are likely to be coalbed methane production rates.

As at Mallik, Japan remains the prime mover in MH exploration and research. A consortium comprising JAPEX, JNOC and Teikoku Oil Co. is drilling in 2,300 to 6,000 ft waters offshore Japan to find and test MH in 1,000-ft shallow wells. It's part of a 16-year study that began in 2001 to determine whether methane hydrate can be produced on a commercial basis.

To produce MH will require extremely innovative, untested methods. It is possible that commercial production of hydrates has already occurred, in Western Siberia. Production profiles suggest that Messoyakha field is a conventional free gas reservoir overlain by methane hydrate. The hydrate may be producing via depressurization, but cannot be proven. However, whether it's a good thing to produce what ostensibly could be part of the top reservoir seal of a shallow gas deposit, especially in marine environments, is unclear.

On the exploration side, success will rely on basin modeling, analysis of the pressure-temperature region known as the Hydrate Stability Zone, identifying Bottom Simulating Reflectors on seismic, seafloor geochemistry, and perhaps geochemical “sniffing” of the water column. A setback recently occurred in MH exploration south of Kuparuk River field in the Alaskan Arctic. ( World Oil, What's new in exploration, April 2004). There, after two seasons of drilling the Hot Ice-1 well and extensive planning for MH production testing, free gas was encountered instead of the “sure thing” hydrate deposit. Obviously, this was a substantial setback for determining where MH exist pre drill. 

LITERATURE CITED

¹ Shenk, C. J., “Geologic definition and resource assessment of continuous (unconventional) gas accumulations in the United States,” USGS, Dec. 2002.

² McCallister, T., “Impact of gas technology in the Annual Energy Outlook 2000,” US Energy Information Administration.

³ James, F., “North American Unconventional Gas Resources: a U.S. Major's perspective,” Canadian Society of Exploration Geophysicists, SCEG/CSPE Joint Conference, June 2 – 4, 2003.

Abstracts,

⁴ “Shale Gas Overview,” Canadian Society for Unconventional Gas, available from www.csug.ca.

⁵ Faraj, B., et al., “Gas potential of selected shale formations in the Western Canadian Sedimentary basin,” GasTIPS, Vol. 10, No. 1, Winter 2004.

⁶ “CBM Output,” Petroleum News, June 6, 2004.

⁷ Garbutt, D. et al., “Unconventional gas,” Schlumberger white paper, 2004, available from slb.com website.