Reversing the Gas Crisis: The Methane Hydrate Solution

Deck: 

Commercialization of methane recovery from coastal deposits of methane hydrates could head off an impending gas shortage.

Fortnightly Magazine - January 2005

Looking superficially at today's gas market data, one might conclude that all is well with the gas industry. For example, working gas storage at the beginning of the current winter withdrawal season-projected to reach well above the normal level of 3.2 trillion cubic feet (Tcf) [1]-actually reached more than 3.3 Tcf at the beginning of November. Furthermore, average active rig count drilling for natural gas was projected to reach a record high of about 1,025 in 2004.

However, growing numbers of energy experts-increasingly alarmed at the ever-increasing price level of natural gas-predict a natural-gas supply crisis for the United States in the coming years.

Strikingly, these forecasters, who projected that pipelines and liquefied natural gas (LNG) terminals would arrive too late to prevent a natural-gas disaster, also had projected spot prices years into the future that were reached in the last few months. For instance, projected mid-winter Henry Hub spot prices of about $6.60 to $7.70/MMBtu for 2004/2005 and $7.50 to $8.50/MMBtu for 2005/2006 [2] were reached during the October 2004 cold spell.

This article investigates the potential of U.S. methane hydrates to avert an impending shortage of natural gas from domestic sources, supplemented by pipeline and liquefied natural gas (LNG) imports at competitive costs.

Deposits

Government agencies, private energy companies, and universities have access to enormous coastal methane hydrate deposits. The Blake Ridge deposit about 250 miles east of Charleston, S.C., seems like the best U.S. site for such an effort. Blake Ridge is exactly the type of deposit most amenable to conventional production techniques-a tight sedimentary cap overlying an increasingly porous sediment containing an increasing amount of solid hydrates bounded by a free gas zone. Reducing the pressure level in this free gas zone by gas withdrawal will result in increased amounts of hydrates decomposing and adding to the supply. A similar opportunity may exist in the Nankai Trough, southeast of Japan's main island of Honshu. Each of these two deposits is estimated to contain 2,000 to 2,500 Tcf of potentially recoverable gas. In fact, a great deal of seismic, sonar, and BSR (Bottom Simulating Reflector) data of these areas already has been assembled, and it promises to be a source of important information on how to proceed with commercial production attempts. These crystalline polyhedral complexes of water and methane molecules as well as hydrocarbon molecules-consisting of only 90 percent methane and 10 percent higher hydrocarbons (primarily ethane, propane, and some butane) that release 170 to 180 volumes of gas per volume of hydrate upon decomposition-will be examined as a potential global source of unconventional natural gas exceeding 700,000 Tcf.

More than half of the Earth's organic carbon is in the form of methane hydrates, while somewhat less is contained in the total of recoverable and non-recoverable fossil fuels (coal, oil, and conventional and unconventional natural gas), soil, dissolved organic matter, land biota and peat [3]. According to Timothy Collett [4], the world's marine and permafrost gas hydrate accumulations are about 20,000 trillion cubic meters (706,293 Tcf) and correspond closely to the above-mentioned organic carbon in the form of hydrates assuming a composition of 100 percent methane. This compares with the upper bound of 20,000 Tcf of technically remaining recoverable conventional and unconventional natural gas resources, excluding, of course, methane hydrates. The other unconventional sources of natural gas-gas from tight formations, geopressured reservoirs, Devonian shales, extremely deep reservoirs, and coal beds-are now included in natural gas production, and reserve and resource statistics, such as the Dec. 31, 2003, proved global reserves value of 6,076.5 Tcf [5].

The U.S. potential is enormous-at least 100,000 Tcf-but significant commercial production has not been achieved. Hydrates production is possible using depressurization, thermal stimulation, and solvent injection (such as methanol). It is already quite apparent that the latter has unacceptable environmental impacts, and that thermal stimulation is too expensive. Depressurization is most feasible in deposits where, under a stable, non-porous sediment cap, there are sediments with increasing hydrate concentrations at increasing depth, bounded by a free gas zone. As the pressure in this free gas zone is reduced by production with suitably designed wells, increasing amounts of the overlying hydrates in the porous sediments decompose and can be produced without any environmental impact.

Note that 100,000 Tcf of methane would meet total U.S. primary energy requirements at the current rate for 1,000 years and that combustion of 69,000 Tcf of methane would emit only 1,000 billion metric tons of anthropogenic carbon in the form of carbon dioxide (CO2). This is the upper bound of total anthropogenic emissions set by the Intergovernmental Panel on Climate Change (IPCC) from 1991 to 2100 to limit atmospheric CO2 concentrations to 550 parts per million by volume, about double the pre-industrial concentration, and thereby limit projections of further increases in average global surface temperatures due to this CO2 enrichment at mean climate sensitivities to between 1.6°C and 2.8°C [6,7].

Potential U.S. and Japanese Methane Hydrate Resources

U.S. methane resources in methane hydrates, according to an August 1998 study by the DOE's Office of Fossil Energy [8], are 112,000 Tcf at 95 percent probability, 676,000 Tcf at 5 percent probability, and a mean value of 320,192 Tcf, in 9 coastal plays and on a small 590 Tcf on-shore permafrost play in Alaska. In a 1995 study by the U.S. Geological Survey (USGS) cited by Timothy Collett [4], U.S. resources are 3,200 trillion m3 (113,000 Tcf) at 95 percent probability and 19,000 m3 (671,000 Tcf) at 5 percent probability in 10 coastal plays and one on-shore permafrost play in Alaska, with a mean value of 9,000 trillion m3 (317,800 Tcf). How much of this wealth of methane resources is practically recoverable is not known, but even a relatively small percentage would greatly expand U.S. gas supplies. To pursue this objective, the U.S. government has budgeted $47.5 million from fiscal year 2001 through fiscal year 2005 (Public Law 106-193, May 2, 2000) for the Methane Hydrate Research and Development Act of 2000 (under the direction of the National Research Council), and numerous other studies are under way. The Gulf of Mexico Hydrate Research Consortium includes six private organizations and 17 universities organized in 1999 by the Center for Marine Resources and Environmental Technology at the University of Mississippi (CMRET), which has developed and installed a remote seafloor observatory within the hydrate stability zone of the continental slope of the Northern Gulf of Mexico. Funding for this consortium initially was obtained from the Department of Interior's Minerals Management Service and then from the cognizant agencies of DOE and the Department of Commerce [9]. Japan's Ministry of International Trade and Industry (MITI) and the Japan National Oil Corp. (JNOC) also have mounted a large research, development, and demonstration (R,D&D) effort. As noted before, a major focus of the Japanese effort is the Nankai Trough southeast of the main island of Honshu, which has yielded promising geophysical data [10].

Figure 1 - Phase Diagram of Methane Hydrates in Arctic Sediments (a) and Marine Coastal Settings (b)

Blake Ridge, about 250 miles east of Charleston, S.C., a sedimentary deposit at roughly 6,500 to 16,000 feet of water depth and 310 miles long, may be a good U.S. site for a demonstration of the feasibility of methane recovery from methane hydrates using the pressure reduction technique. Occurrence of methane hydrates in the United States has been studied there for about 30 years, and it is believed to contain large amounts of methane trapped both within the hydrate layer and as free gas below it. A recent (2000) estimate by Collett of the total gas content is 57 trillion m3 or 2013 Tcf (more than 10 times U.S. proved reserves), although it is distributed over an area of 10,000 square miles. Of this 34 percent is free gas and 66 percent comes from methane hydrates in the overlying sediment [4]. Other estimates place the total gas content as high as 70 trillion m3 (2,470 Tcf) [4]. Similarly, the hydrate-bearing sediments in the Nankai Trough, southeast of Japan's main island of Honshu, contain as much as 60 trillion cubic meters (2,119 Tcf) of gas and range in porosity from about 36 to 39 percent [10].

The Impending Shortage of Natural Gas

On the problems of U.S. natural gas supply and price stability, there are two critical areas in which R,D&D can make relatively near-term contributions, including more aggressive development of still sizeable lower-48 conventional and unconventional natural gas reserves and resources. There are also much higher imports of plentiful and relatively low-cost LNG from large stranded reserves of natural gas in many parts of the world (Trinidad, North Africa, Nigeria, the Persian Gulf region, Indonesia, etc.) But the most promising long-term solution would be the commercialization of methane production from a relatively small percentage of the enormous U.S. coastal resources of methane hydrates.

The recovery of coalbed methane, of which there were proved U.S. reserves of 18.491 Tcf on Dec. 31, 2002 [11] and the total potential resource is about 169 Tcf (see Table 1), is another opportunity for R,D&D to increase the production from 1.6 Tcf in 2002 [11] to only 2 Tcf projected for 2025 [12]. The same is true of large, untapped resources of the other types of unconventional natural gas-especially tight sands and gas shales, which by 2025 are projected to supply over 7 Tcf of U.S. production [12]. But, while substantial, these supplemental sources of supply are insignificant when compared to the promise of methane hydrates.

For LNG imports, the United States now has only four operating receiving terminals and new technology is needed to reduce public opposition to the construction of new terminals in most U.S. coastal areas except, perhaps, the Gulf Coast in order to raise LNG imports to projected levels of 2.2 Tcf in 2010 and 4.8 Tcf in 2025 (see Table 2).

Table 1 - Estimated Potential Natural Gas Resources of the United States*

Regarding conventional natural gas supply, the number of gas well completions has increased to a rate of about 24,000 a year [13]. The active natural gas rig count rose to an extraordinarily high level of 1,082 during the week ended Sept. 3, 2004 [15] and is likely to set a record high of at least 1,025 in 2004 based on the author's estimate from Baker Hughes Rig count data.

This increase followed large wellhead gas price increases after the California energy crisis in 2001/2002, and the excessive depletion of underground storage reservoirs during the winter of 2002/2003. But the increases can be attributed mostly to development drilling in known formations, while gas production has remained flat, or even declined [13].

The gas industry, gas consumers, and DOE need to assess the significance of the decline in the EIA's projections of gas supply from 2003 to 2004. The Annual Energy Outlook 2003 With Projections to 2025, forecasts 23.17 Tcf of U.S. natural gas supply (including 3.65 Tcf of net imports) in 2001, increasing to 34.60 Tcf (including 7.76 Tcf of net imports) in 2025 [16], whereas the Annual Energy Outlook 2004 With Projections to 2025 reduces the forecast for 2025 to 31.33 Tcf (including 7.24 Tcf of net natural gas imports) [12]. This one-year decline in projections shown in Table 2 is a major cause for concern. Attention to the supply problem is especially needed since U.S. dry natural gas production had declined, from 21.7 Tcf in 1973 to 16.1 Tcf in 1986 before recovering steadily to 19.7 Tcf in 2001 [13]. Improvements in exploration and production technologies to minimize their environmental impact would greatly increase the probability that large, existing lower-48 reserves (such as the six basins straddling the Rocky Mountains region) would become accessible to exploitation. R,D&D in all critical areas of high-pressure, large-diameter pipeline transmission technology also would facilitate the construction of a pipeline to transport the large Alaskan and Mackenzie River Delta reserves to the lower-48 states.

As noted before, the Potential Gas Committee estimate of remaining technically recoverable U.S. gas resources as of Dec. 31, 2002, is 1,314 Tcf (including proved reserves of 186.946 Tcf-see Table 1) after subtracting the estimated cumulative production of 989 Tcf from the initial ultimate resource base of 2,303 Tcf [17]. Based on the well-known but controversial peak crude oil production projections of M. King Hubbert that were reasonably close for the lower-48 states [18], a simplistic approach to projecting the level and time of peak U.S. natural gas production would be to plot the record up to the present and then extend it in a sigmoidal (probabilistic), symmetrical curve whose enclosed area represents the total resource base, including cumulative production and proved reserves. Aside from the fact that the past U.S. natural production curve is not sigmoidal, the midpoint of U.S. gas production for Table 1 would be about 1,151 Tcf. Subtracting 989 Tcf of cumulative production gives only another 162 Tcf of remaining cumulative production, until it might peak, or at least plateau, using the widely questioned Hubbert methodology. At the latest production levels of 19.70 Tcf in 2001 to 23.99 Tcf in 2025 projected by EIA (see Table 2), this would give only a few more years of increases in annual domestic supply. Clearly, this possibility is one of the highest priorities for investigation of the role the enormous U.S. resources of methane hydrates could play to avert such a crisis for U.S. residential, commercial, and industrial gas consumers.

The Threat From Excessive Demand

Table 2 - U.S. Natural Gas Supply & Consumption for Power Generation Projected by the Energy Information Administration

An additional 11.7 Tcf/year would be required if the existing 311 GW of largely old, depreciated, inefficient coal-fired steam-electric plants-which provide more than one-half of U.S. power demand operating at an average operating factor of about 70 percent-were replaced by gas-fired, combined-cycle units operating at 60 percent (lower heating-value basis) efficiency. However, CO2 emissions would be reduced by two-thirds and conventional pollutant emissions (except for nitrogen oxides, which are easily controlled) essentially eliminated. In addition, between 2001 and 2025, another 170 GW of gas-fired, combined-cycle capacity at an investment cost of only about $500/kW operating at an average load factor of 50 percent are projected (see Table 3) [12]. This would require another 4.6 Tcf/year, or a total of about 16 Tcf. But the Energy Information Administration in its latest report forecasts an increase only from 23.4 Tcf to 31.3 Tcf in U.S. gas supply between 2001 and 2025 (including net imports) and an increase of a mere 3.0 Tcf/yr (from 5.4 to 8.4 Tcf/yr) for power generation (see Table 2). Thus, if these 311 GW of coal-fired, steam-electric capacity were replaced by 2025, largely because they are responsible for 1/3 of U.S. CO2 emissions, and all of the additional 170 GW of additional gas-fired, combined-cycle capacity really were built, the net increase in gas requirements for power generation between 2001 and 2025 would be about 13 Tcf/yr (11.7 + 4.6-3.0). This would lead to total 2025 gas requirements of about 43 Tcf/year, which clearly is not attainable and would severely limit the ability of the majority of gas consumers to obtain adequate supplies of gas at affordable prices. This conflict between the gas and electric industry to meet with natural gas the growing constraint on pollutant and greenhouse gas emissions is a further incentive to commercialize recovery of methane from the abundant U.S. methane hydrate resources.

Increasing Reliance on Clean-Coal Technologies

The increase in natural gas prices and the impending shortages of natural gas already have sharply reduced the projections of increases in gas-fired, combined-cycle capacity. In the equivalent of Table 3 in EIA's Annual Energy Outlook 2003 With Projections to 2025 [16], an increase of 255 GW between 2000 and 2025 was predicted, requiring an additional 6.9 Tcf/yr of natural gas at an average load factor of 50 percent. Also, the predicted increase in coal-fired power generation was only from 311 GW to 376 GW between 2000 and 2025, compared with an increase from 311 GW to 412 GW between 2001 and 2025 in the Annual Outlook 2004 With Projections to 2025 [12]. This ongoing renaissance of coal-fired power generation is spearheaded by American Electric Power (AEP), which is planning to build a 1,000 MW Integrated Coal Gasification - Combined-Cycle (IGCC) clean coal unit by 2010, although it has a substantially higher investment cost than conventional steam-electric plants-on the order of $1350/kW [26]. However, in addition to higher thermal efficiencies, IGCC plants have negligible conventional pollutant emissions and can be modified to produce hydrogen instead of synthesis gas-an objective of the DOE $2 billion FutureGen Project.

But so far only two 250 to 300 MW IGCC plants have been built with DOE support. Jeff Johnson writes: "If IGCC installations grow worldwide, and if ongoing R&D projects to sequester CO2 turn out to be feasible, IGCC could knock coal from this current position as the world's dirtiest fuel and biggest contributor to global warming" [26]. This refers to the use of a modified IGCC Process in which the raw synthesis gas produced by the initial high-pressure, high-temperature steam-oxygen gasification of the coal is converted with more steam by the well-known catalytic water gas shift reaction (CO+H2O=> CO2+H2) to a hydrogen-CO2 mixture (either before or after removal of the hydrogen sulfide formed from the sulfur content of the coal depending on the sulfur resistance of the water-gas-shift catalyst), and the CO2 is then removed by one of the commercial processes and sequestered in suitable underground reservoirs. The remaining high-pressure product hydrogen then can be used for emission-free central power generation, or as a regional source of fuel for distributed generation and, eventually, high-efficiency electromotive surface transport with proton exchange membrane (PEM) fuel cells using high-pressure on-board hydrogen storage. However, a recent estimate of the investment cost of such a modified IGCC process, excluding the cost of CO2 sequestration, was $1,642/kW [19]. The author has advocated this approach to a pollutant and carbon-emission-free coal-based power generation method in several recent publications [20].

Another use of clean synthesis gas produced by the IGCC process is the production of synthetic liquid fuels such as naphtha and diesel oil by the Fischer-Tropsch Process. Houston-based DKRW Energy is working on a $2.76 billion project to build such a plant in Medicine Bow, Wyo., which would produce 26,200 barrels/day of these synthetic premium liquid fuels and 1,000 MW of power [21,22]. However, this would not allow elimination of CO2 emissions by catalytic water gas shift and CO2 sequestration.

Table 3 - Net U.S. Summer Electricity Generating Capacity 2001-2025 (Gigawatts)

In view of evidence of tightening U.S. gas supplies and the competition between the majority of gas consumers and electric utilities for the supplies that are available, it seems that a concentrated effort should be made to demonstrate the feasibility of producing methane from methane hydrates.

To expedite these efforts of commercializing production of natural gas substitutes from methane hydrates, a forum to collect and exchange more than 30 years of R,D&D results needs to be created-similar to the international conferences on LNG organized by IGT in 1968 that contributed substantially to the growth of the global liquefied natural gas industry. The Gas Technology Institute (GTI), could best assume this responsibility. GTI has conducted a great deal of R&D on methane hydrate occurrence, stability, and recovery. Just as the responsibility for managing the international conferences on LNG was shared successfully, a similar arrangement could be made for international conferences on methane hydrates. GTI seems to be most highly motivated to take the lead in this important venture as the central R,D&D organization working on behalf of more than 66 million U.S. gas customers.

Acknowledgement. The author gratefully acknowledges the generous financial support of underlying analytical studies by Gas Technology Institute in Des Plaines, Illinois. Valuable technical inputs were also received from Dr. Timothy S. Collett, Research Geologist, U.S. Geological Survey, Denver, Colorado, and from Iraj Salehi, Manager, Exploration and Production Technology, Gas Technology Institute.

References

1) Andrew Ware, "Gas Prices Erupt as Ivan Deals Blow to Some Gulf Operations," Natural Gas Week, Vol. 20, No. 38, pp. 1,6,14 (Sept. 20, 2004).

2) Michael T. Burr, "Gas Supply Too Little Too Late?" Public Utilities Fortnightly, Vol. 142, No. 9, pp. 34-41 (September 2004).

3) "Report of the Methane Hydrate Advisory Committee on Methane Hydrate Issues and Opportunities - Including the Assessment of Uncertainty of the Impact of Methane Hydrate on Global Climate Change" pp. I, 1-11, December 2002.

4) Timothy S. Collett, U.S. Geological Survey, "Energy resource potential of natural gas hydrates," AAPG Bulletin, Vol. 86, No. 11, pp. 1971-1992 (November 2002).

5) Marilyn Radler, "Worldwide reserves grow; oil production climbs in 2003," Oil & Gas Journal, Vol. 101, No. 49, pp. 43-46 (Dec. 22, 2003).

6) Houghton, J.T., et al., eds., "Climate Change 1995, The Science of Climate Change," Contribution of Working Group I to the Second Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), 1996, Cambridge University Press, Cambridge, U.K. and New York.

7) Houghton, J.T., et al., eds., "Climate Change 2001, The Scientific Basis," Contribution of Working Group I to the Third Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), Cambridge University Press, Cambridge, U.K. and New York.

8) "A Strategy for Methane Hydrates Research & Development," U.S. Department of Energy, Office of Fossil Energy, August 1998, 54 pages, Document No. DOEFE/0378.

9) "Fire in the Ice," The National Energy Technology Laboratory, Methane Hydrate Newsletter, pp. 1-14 (Summer 2004).

10) Naburo Tezuka "Challenges for Offshore Energy Around Japan: Sakhalin and Methane Hydrates," Proceedings of The Twelfth (2002) International Society of Offshore and Polar Engineers, Kita Kyushu, Japan, May 26-31, 2002, pp. 6-12.

11) Energy Information Administration, Office of Oil and Gas, U.S. Department of Energy, 2003 Annual Report, "U.S. Crude Oil, Natural Gas and Natural Gas Liquids Reserves," Document No. DOE/EIA-0216 (2003), Advance Summary, September 2004.

12) Energy Information Administration, Annual Energy Outlook 2004 With Projections to 2025, Document No. DOE/EIA-0383(2004), January 2004.

13) Energy Information Administration, Monthly Energy Review October 2004, Document No. DOE/EIA-0035(2004/10).

14) Richard A. Kerr, "Gas Hydrate Resource: Smaller But Sooner," Science, Vol. 303, No. 5660, pp. 946-947 (Feb. 13, 2004).

15) "Baker Hughes Rig Count for Week Ended September 3, 2004," Natural Gas Week, Vol. 20, No. 36, p. 14 (Sept. 6, 2004).

16) Energy Information Administration, Annual Energy Outlook 2003 With Projections to 2025, Document No. DOE/EIA-0383(2003), January 2003.

17) "Potential Supply of Natural Gas-2002," Report of the Potential Gas Committee, Potential Gas Agency, Colorado School of Mines, Golden, Colorado, pp. 1-12 (Dec. 31, 2002).

18) Henry R. Linden, "Rising expectations of ultimate oil, gas recovery to have critical impact on energy, environmental policy - Part I," Oil & Gas Journal, Vol. 102, No. 3, pp. 18-28 (Jan. 19, 2004).

19) Evaluation of Innovative Fossil Fuel Power Plants With CO2 Removal, Electric Power Research Institute, Palo Alto, CA, and U.S. Department of Energy, Office of Fossil Energy, Germantown, MD and NETL, Pittsburgh, Pa., Interim Report, Document No. 1000316, December 2000.

20) Henry R. Linden, "Bridging the Carbon Gap: Fossil Fuel Use for the 21st Century," Public Utilities Fortnightly, Vol. 140, No. 21, Nov. 15, 2002, pp. 32-41.

21) Barbara Shook, "Dream of Gas Displacing Coal Proves Fleeting," Natural Gas Week, Vol. 20, No. 37, p. 8 (Sept. 13, 2004).

22) Suzanna Strangmeir, "Industry Debates Best Use of Coal Gasification Technology," Natural Gas Week, Vol. 20, No. 31, pp. 1, 18, 19 (Sept. 6, 2004).

23) Wilford G. Bair, "IGT - The First 50 Years 1941-1991, A History of the Institute of Gas Technology," Chicago, Illinois, 1991 (since 2000 merged into Gas Technology Institute, Des Plaines, Illinois).

24) Alex V. Milkov, et al., "Gas Hydrates at Minimum Stability Water Depths in the Gulf of Mexico: Significance to Geohazard Assessment," Gulf Coast Association of Geological Societies Transactions, Vol. L, pp. 217-224 (2000).

25) Iraj Salehi, "Natural Gas Hydrates, Resource of The Future," TIPRO Mid-Winter Policy Meeting, Jan. 13 and 14, 2003, Austin, Texas.

26) Jeff Johnson, "Coal-Fired Power Generation May Get Cleaner," Chemical and Engineering News, Vol. 82, No. 38, pp. 36-37 (Sept. 20, 2004).