Journal of Petroleum Technology August 2012 : Page 50

Production Method for Methane Hydrate Sees Scientific Success Joel Parshall, JPT Features Editor The testing flare burns brightly during a methane hydrate production test of the Ignik Sikumi No. 1 well on the Alaskan North Slope. The orange structure at right is the well house. Photo courtesy of ConocoPhillips. A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and opera-tional standpoint in a recent research experiment on the Alas-kan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with Cono-coPhillips and Japan Oil, Gas, and Metals National Corporation. A proof-of-concept test was conducted between 15 Febru-ary and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO 2 ) to exchange and release methane (CH 4 ) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization. “The test objective was to perform injection and flow-back from a single well to validate that the CO 2 /CH 4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, tech-nology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO 2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new tech-nology, rather than an attempt to produce gas at commercial rates,” Boswell said. CO 2 Mixture Injected in Reservoir The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, 50 JPT • AUGUST 2012

Production Method For Methane Hydrate Sees Scientific Success

Joel Parshall, JPT Features Editor

A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and operational standpoint in a recent research experiment on the Alaskan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with ConocoPhillips and Japan Oil, Gas, and Metals National Corporation. A proof-of-concept test was conducted between 15 February and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO2) to exchange and release methane (CH4) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization. “The test objective was to perform injection and flowback from a single well to validate that the CO2/CH4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, technology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new technology, rather than an attempt to produce gas at commercial rates,” Boswell said. CO2 Mixture Injected in Reservoir The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, Including high-resolution in-line gas chromatography. Over a 13-day period, a carbon dioxide/nitrogen mixture was successfully injected into the 30-ft-thick reservoir interval, saturated with methane hydrate, without loss of injectivity. This was followed by a production stage in which the pressure was held above the stability pressure of the in-situ methane hydrate. CH4 was produced during this stage, and initial data analyses indicated that CO2 exchange was achieved. Ongoing analyses of the extensive datasets acquired at the field site are under way to determine the overall efficiency of simultaneous CO2 storage/CH4 production from the reservoir. As part of the demonstration, the depressurization phase of the test extended for 30 days. The longest previous field test of depressurization to extract gas from hydrate lasted 6 days as part of a Japanese-Canadian testing program at the Mallik well in Canada’s Northwest Territories during 2007 to 2008. Methane hydrate represents “a vast, entirely untapped resource that holds enormous potential for US economic and energy security,” the DOE said in announcing the outcome of the Ignik Sikumi test in May. Globally, gas hydrate resources are often touted as immense, but much of the resource occurs at low concentrations in fine-grained sediments and thus poses great challenges to potential production. However, Arctic and deepwater settings are known to hold large stores of gas hydrate in the form that recent research indicates is recoverable with existing technologies: hydrate in sand-dominated reservoirs in which hydrates reach high concentrations. Interest in hydrate production has grown, following a published assessment by the US Geological Survey (USGS) in 1995 of in-place methane hydrate volumes on the ANS. In 2007, the NETL, the USGS, and BP Exploration Alaska carried out a hydrate research project in the Milne Point field on the ANS. A wireline reservoir test of an openhole well confirmed that gas could be produced through reservoir depressurization and enabled further determination of reservoir productivity. With this and other information, the USGS in 2008 assessed the mean volume of technically recoverable methane hydrate on the ANS at 85 Tcf, the world’s first assessment of gas hydrate that is producible with existing technologies. New Research Planned The Ignik Sikumi well test will provide critical information to advance the NETL’s efforts to evaluate various potential methane hydrate production technologies. The next stages of NETL research will focus in part on evaluating gas hydrate production over longer durations, likely through depressurization, with the goal of making sustained production economically viable. While this may take years, the DOE said that it also took years for the early shale gas research and technology demonstrations backed by the department in the 1970s and 1980s to develop into economically viable production methods. The DOE recently announced two major new steps in its methane hydrate research effort. The department has made USD 6.5 million available in fiscal 2012 for research into technologies to locate, characterize, and safely extract natural gas from methane hydrate formations such as those in the Arctic and along the US Gulf of Mexico coast. Projects will address • Characterizing deepwater gas hydrate by means of direct sampling and/or remote sensing field programs. • New tools and methods for monitoring, collecting, and analyzing data to determine reservoir response and environmental impacts related to methane hydrate production. • Clarifying methane hydrate’s role in the environment, including responses to warming climates. In a second initiative, the DOE is requesting USD 5 million in the fiscal 2013 budget to further gas hydrate research domestically and in collaboration with international partners. The exact nature of the research is being determined. However, a longer methane hydrate extraction test on the ANS is envisioned on an existing gravel-bed pad that can accommodate year-round operations. Such an effort would likely require engaging private-sector and international partners.

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