For years, gas hydrates have been a resource that produced enormous in-place volume estimates. The U.S. Geological Survey (USGS) estimated as much as 16.7Tm³ (590Tcf; 106Bboe) in-place on the North Slope of Alaska in 1995 that covers an area of about 145,000 km² (equivalent to approximately 25 North Sea quadrants). World wide estimates also focused on in-place gas volumes because, at that time, there was not any methodology to assess what actually could be produced from these deposits.
Since these first published reports, a number of tests, experiments, and much research has been conducted on gas hydrates, allowing assessments to focus on the technically recoverable resources for the first time.
“Test results from the Mallik well and other research have pointed the way to treating gas hydrate in a much more conventional manner,” say Dr. Timothy Collett, a leading gas hydrate researcher for the USGS. “Our recently released Assessment of Gas Hydrates on the North Slope, Alaska, 2008, is based on the same geologic elements to define a Total Petroleum System (TPS) we use to assess conventional plays. We were able, for the first time, to obtain the undiscovered, technically recoverable volume of gas from hydrates for an area, in this case, northern Alaska. To this end, these resources can be discovered, developed, and produced by using current oil and gas technology.”
Naturally occurring – huge volumes
The USGS estimates about 2.4Tm³ (85Tcf; 15Bboe) of undiscovered, technically recoverable gas resources within gas hydrates in Alaska. The area is mostly Federal, State, and Native lands covering 145,000 km² (the equivalent of some 25 North Sea quadrants). ©USGSA gas hydrate is similar to ice, a crystalline solid, where the gas molecule is surrounded by a cage of water molecules. Many gases are suitable to form hydrates, however methane is by far the most commonly found in marine and polar occurrences.
Experimenting with mixtures of chlorine and water, Humphrey Davy and Michael Faraday may have been the first to discover hydrates. The 1823 paper from the Transactions of the Royal Society of London, by Faraday, discusses experiments with the chlorine hydrate. Because a hydrate had never been seen in nature, they remained an academic curiosity through the 19th century. When hydrates were found to be forming in the gas pipelines in the mid-1930s, the North American gas industry focused on ways to predict and inhibit hydrate formation. In 1970, Soviet researchers registered the possibility that gas hydrates could exist in large volumes in the earth’s crust, and, in 1972, naturally occurring gas hydrates were eventually recovered from the Black Sea.
Since that discovery, marine hydrate-containing sediments covering huge areas of the sea floor have been found in deep-sea drilling and coring in more than 50 regions of the world’s oceans and even in some large lakes (Baykal in Russia is one). Hydrates are stable in marine sediments below about 500 meters in water depth and stable in association with permafrost in Polar Regions in both onshore and offshore sediments.
Gas is greatly concentrated in hydrates where a unit volume of methane hydrate can produce about 160 unit volumes of gas at one atmosphere. Worldwide, the methane contained (in-place volumes) in gas hydrates is about twice the amount of carbon held in all the earth’s fossil fuels.
Testing the production capacity
The presence of gas hydrates is commonly identified by bottom simulating reflectors (BSRs) in oceanic sediments. ©USGS
Sampled and inferred gas hydrates occur world wide in oceanic sediment of continental margins and in permafrost regions. Inferred gas hydrates are from bottom simulating reflectors (BSRs) on seismic profiles. The Mt. Elbert and Mallik test sites are located at the top of the map. ©USGSOnce the presence of gas hydrates was confirmed and it had been shown that the volume of gas is huge, the next question was if this resource be produced and how. Significant technical issues stood in the way before gas hydrates could be considered a viable energy source. Hoping to find the answers, Canada, Japan, India, and the United State launched ambitious research projects.
“Past research has focused on three fundamental issues,” according to Dr. Collett. “Where do gas hydrates occur, how do they occur, and why do they occur in a particular setting? However, there is a fourth issue. Until recently, little had been done in evaluating the potential for viable production of gas hydrates.”
In 2002, the U.S. Department of Energy and BP Exploration (Alaska), Inc. (BPXA), in cooperation with the USGS, initiated a research program on Alaska North Slope (ANS) gas hydrates. The ultimate goal was a production test to determine if the gas hydrates could be a viable energy resource.
Three ambitious research programs have also been undertaken in the last decade next door in the Mackenzie Delta at the Mallik research site. Led by Canada and Japan, the 1150m deep Mallik 2L-38 well was completed in 1998. For the first time, cores were brought to the surface from an Arctic gas hydrate occurrence delineating approximately 120m of hydrate bearing section within coarse grained clastic sands.
A second phase of this research program was undertaken in 2002 with a broader five country partnership (Canada, Japan, Germany, USA, India) that completed three additional wells and the first production test. This would be the first time gas would be flared from hydrate.
While the 1998 and 2002 Mallik gas hydrate research projects enabled many new ground breaking studies, the flow rates were modest. Japan (JOGMEC) and Canada (NRCan) therefore decided to return to the Mallik site in the winters of 2007 and 2008 to initiate a new testing program focusing this time on a full scale production draw down test.
The world’s first
The Mt. Elbert-01 stratigraphic test well, Milne Point Unit on the North Slope of Alaska, collected the first open-hole formation pressure response data in a gas hydrate reservoir. This test and reservoir simulations are some of the first steps that could lead to production of hydrate reservoirs. Photo: Tim Collett, USGS“We have now progressed way beyond just looking at the in-place resources,” says Dr. Collett. “Gas hydrate research is now looking at more conventional prospects that can be produced by current technologies. The February 2007 22-day field program at Mt. Elbert has taught us a lot about how hydrates occur in porous media, why they occur where they do, and the location and design of long-term testing.”
The field program at the Mt. Elbert site was designed to collect as much data as possible from the gas hydrate zones. Researchers were able to obtain a full suite of open-hole well logs, over 152m of continuous core, and open-hole formation pressure response tests. They used chilled oil-based drilling fluids to maintain excellent hole conditions and thus obtain the best quality data.
“We found approximately 30m of gas hydrate saturated, fine-grained sand reservoir,” says Dr. Collett. “Gas saturations ranged from 60% to 75% mostly due to differences in reservoir quality.”
The culmination of the program was the open-hole tests. They were able to obtain reservoir pressure response data in addition to gas and water samples.
“This well clearly demonstrated that open-hole data can be safely and efficiently obtained from shallow, sub-permafrost sediments,” says Dr. Collett.
Taking an even bigger step toward the production of methane from gas hydrates was the Japanese and Canadian sponsored 2006-2008 Mallik 5L-38 research well. Just completed in April 2008, the goal was to undertake a longer production test than the 2002 Mallik project to advance new research and development studies utilizing simple depressurization of the reservoir. “The first tests were conducted during the winter of 2007,” says Dr. Scott Dallimore of the Canadian Geological Survey and lead researcher for the Mallik Program. “Sand production prevented continuous pumping. However, during a 12.5 hour interval, at least 830m³ of gas was produced. It was the world’s first gas production using large scale depressurization of a gas hydrate.”
“After some modifications to the pumping system, 2008 field operations were geared for a long duration test of the same 1093 to 1105 m depth interval tested in 2007,” Dr. Dallimore adds. “They were able to continuously pump for six days until down-hole pressures stabilized. Gas flowed to the surface and was flared while pressure, temperature, gas, and liquid flow rate data were measured.”
The Japanese and Canadian team reported that the flow rates ranged from 2,000 to 4,000m³ per day. Cumulative gas production was over 13,000m³ for the six-day test.
Eileen trend prospects
“What the Mt. Elbert and the Mallik research is telling us is that we should be able to develop gas hydrate prospects,” says Dr. Collett. “When we started the Mt. Elbert project, we first mapped 14 gas hydrate prospects in the Eileen trend (Milne Point area northwest of the Prudhoe Bay field). From 3-D seismic data and rock physics relationships conditioned by well data, we were able to predict gas hydrate pay thickness and saturation. The entire Eileen gas hydrate trend, including the 14 prospects in the Milne Point area, has approximately 0.93Tm³ (33Tcf; 5.9Bboe) gas in place with initial reservoir modeling suggesting as much as 0.34 Tm³ (12Tcf; 2.2Bboe ) recoverable.”
The Mt. Ebert prospect turned out to be the highest-ranked prospect in the Milne Point area and was selected for the field data acquisition program. This prospect had a strong and well organized seismic response. Amplitude anomalies observed in two horizons were restricted within a well defined three-way fault closure suggesting the accumulation was originally a free-gas accumulation later converted to gas hydrate through depressed thermal gradients associated with the development of permafrost.
Predictions were also made on individual reservoir sands that ranged in thicknesses of 14 to 21m. The coring and logging program closely confirmed these predictions.
Open-hole logs from the Mt. Elbert test clearly showing high resistivities in the gas saturated zones. The Unit D sand had 68% gas hydrate saturation and Unit C 89%. The low resistivity sands below the Unit C, but still in the hydrate stability zone, are water saturated. ©Tim Collett, USGSrnttttMap of the fault bounded amplitude feature (yellow to magenta, yellow being the thickest and highest concentration of gas hydrate) defining the Mt. Elbert prospect. ©Tim Collett, USGS
More exploration
The successful research approach demonstrated at the Mt. Elbert well and prospect has opened the door to more exploration and testing of gas hydrate prospects.
A 2-year program is underway to map, drill and log gas hydrate-bearing sands in the deep water in the northern Gulf of Mexico. The project is the latest phase in an ongoing Joint Industry project led by Chevron in collaboration with the U.S. Department of Energy. They hope to further test geological models and geophysical interpretations supporting the existence of high gas hydrate saturations in reservoir-quality sandstone.
Another recently completed study off the Indian continental margin has confirmed the presence of gas hydrates in four offshore basins. Not only did they find gas hydrates, they found one of the richest gas hydrate accumulations yet documented (Krishna-Godavari Basin, Bay of Bengal) and found the thickest and deepest gas hydrate stability zone near the Andaman Islands also in the Bay of Bengal.
Significant resource opportunity
Amplitude anomalies associated with the gas hydrate drilling targets at the C Horizon. The anomalies are restricted within a well defined three-way fault closure. ©Tim Collett, USGS“For years, gas hydrate research has been framed by extravagantly large numbers (see above) that refer only to the in-place volumes of methane in gas hydrates,” says Dr. Ray Boswell, Manager-Methane Hydrate R&D Programs, U.S. Department of Energy.
“These volumes are significant in an environmental context, and the climate implications of gas hydrates are a major topic of study in the U.S. effort. However, in the context of potential resources, what is most interesting is what portion of that resource is a realistic future source of gas supply. The array of recent field programs, combined with continuing work in the lab, is now providing the first insight into those technically-recoverable volumes. Although these numbers lack eye-popping appeal, they clearly indicate significant new resource opportunities that, given its global distribution, have the potential to alter existing energy production and supply paradigms,” says Dr. Boswell.
“After a decade of R&D studies at Mallik, we have addressed many scientific unknowns and established proof of concept that gas hydrate production can be sustained with the pressure draw down technique, using conventional oil and gas production techniques modified to accommodate the unique physical properties of gas hydrates,” Dr. Scott Dallimore adds.
“However, our testing at Mallik was only for six days duration. The next milestone advances in production research are likely to come through longer testing which will allow consideration of the field-scale response as well as providing a basis to consider environmental issues associated with production. It is my understanding that longer term testing programs are actively being considered in northern Alaska, the Mackenzie Delta and even in offshore settings like the Nankai Trough (offshore Japan).”
Long term endeavour
“Natural gas demand is expected to grow in the first decades of this century as production from conventional sources decline,” concludes Dr. Tim Collett. “Vast deposits of marine and arctic gas hydrate are seen as a possible source of natural gas, but there are many challenges to be overcome before widespread production of natural gas from gas hydrate are possible. The evaluation of gas hydrate as an energy source is clearly a long-term endeavour that will require significant financial investment.”
