A piece of the methane hydrate puzzle

Known to exist in vast quantities in many parts of the world but with as yet no means of commercial production, methane hydrate could eventually become a prolific source of natural gas. This winter’s test of the production of methane, the main component of natural gas, from the Iġnik Sikumi No. 1 methane hydrate test well on Alaska’s North Slope represents a notable step for methane hydrate research in that, among other achievements, it succeeded in producing methane from hydrate for a record-breaking duration of 30 days. However, determining the next steps in researching gas production from hydrates will depend on the analysis of data obtained from the test, David Schoderbek, ConocoPhillips director, gas hydrates, told Petroleum News May 10. A team involving ConocoPhillips, the U.S. Department of Energy, and the Japan Oil, Gas and Metals National Corp. conducted the test. Methane hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside an ice-like lattice of water molecules. The material is only stable within a narrow range of temperatures and pressures: Move the temperatures and pressures outside that range, and the material dis-associates into methane and water. Using carbon dioxide Researchers have been investigating the possibility of extracting methane from hydrate by de-pressuring a subsurface hydrate accumulation, thus moving the hydrate out of its stability range and causing dis-association of the material. However, ConocoPhillips with its partners has been researching an alternative approach involving the injection of carbon dioxide into the hydrate, causing the carbon dioxide to exchange with methane in the hydrate lattice. The process releases methane while also trapping carbon dioxide inside the hydrate. Schoderbek said that in laboratory tests scientists had successfully displaced all methane from hydrate samples by flooding the samples with carbon dioxide over an extended time period. This technique, if replicated in the field on a commercial scale, might provide a means of sequestering unwanted carbon dioxide as well as enabling natural gas production from the hydrates. According to information in the Department of Energy website, the use of carbon dioxide for gas production from methane hydrates could present additional benefits: The procedure does not liberate water from the hydrates, would not impact the mechanical stability of the hydrate deposits and, unlike de-pressurization of the hydrates, would not cause the formation of pore-clogging ice or secondary hydrates as a consequence of dis-association-induced cooling. The purpose of the test with the Iġnik Sikumi well was to see if the results from the laboratory test could be replicated in field conditions, Schoderbek explained. Test location The North Slope is an especially suitable location for this type of test because of the known existence of hydrate accumulations in cold rocks under the permafrost, with a high saturation of the hydrates in clean sandstone close to an existing oil and gas infrastructure, Schoderbek said. ConocoPhillips used log data from existing wells to home in on a suitable site for the test well, eventually opting for a location next to an existing well pad within the Prudhoe Bay unit. The test location was close to wells known to have passed through methane hydrate deposits under the permafrost, in a situation where subsurface pressures and temperatures appeared close to those used in the laboratory tests. The well location was conveniently close to infrastructure on the existing well pad. At the same time the use of an ice pad as a base for the drilling would avoid any conflict with regular oilfield operations, Schoderbek said. The research team used subsurface and seismic data to extrapolate the position of hydrate bearing sands from under the existing well pad out to the location of the test well. Drilled in 2011 ConocoPhillips drilled the well in April 2011 to a depth of 2,597 feet, 900 feet below the permafrost and also below the base of the hydrate accumulations. Subsequent well logging with gamma ray, resistivity, sonic, density, and magnetic resonance imaging logs provided necessary data for the characterization of the methane hydrate reservoir, in particular for determining the hydrate and water saturations in the pores of the subsurface reservoir sands. “That allowed us to make a higher quality estimate of what conditions would exist during the test,” Schoderbek said. “So we were able to narrow down what the basis of the (test) design needed to be.” This winter, having completed the test design, the team rebuilt the ice pad; re-entered and perforated the well; and installed a downhole screen to prevent sand from clogging the well bore. The team then injected a mixture of nitrogen and carbon dioxide into the methane hydrate reservoir over a period of 13 days, thus replicating what had been done on a smaller scale in the laboratory. Gas mixture For this phase of the test, the nitrogen and carbon dioxide were transported in liquid form to a built-for-purpose gas mixing skid at the well site. In the skid the liquids were gasified and pressurized for injection down the well. The team also mixed in a couple of other gases to act as markers, used later to determine how much of the injected gas returned to the surface during the production phase of the test. After injecting the gases into the subsurface rock formation, the team spent a couple of days converting the well for production by, among other things, re-directing the gas injection equipment and installing a downhole pump in the well — the pump, powered by produced water from the Iġnik Sikumi wellbore, would be necessary to cause fluid to flow to the surface from the producing formation. In the production test the downhole pump drove a mixture of methane, carbon dioxide, nitrogen and tracer gases to the surface, where the production of the various gas types was measured. No delay The team had determined that there would be no technical advantage to shutting in the well long enough to allow the complete replacement of methane in the hydrate by carbon dioxide as had been done in the laboratory test, Schoderbek explained. By the time that the gas injection process had been completed, the reservoir close to the well bore — the section of the reservoir that would likely produce first — would have already been permeated with carbon dioxide, he said. The measurement of what came out of the well in comparison with what was pumped in would enable the effectiveness of the carbon dioxide replacement to be determined. With the pressure in the reservoir drawn down by the downhole pump, the procedure transitioned from a test involving carbon dioxide replacement of methane to a multi-day test of methane production through depressurization. Data analysis Chemical engineers, reservoir engineers and reservoir modelers are now analyzing the huge volumes of data obtained from the test to determine the extent to which methane production resulted from carbon dioxide exchange rather than depressurization, Schoderbek said. Until this data analysis has been completed and the results of the test assessed it will not be possible to say what might be an appropriate next step, or for that matter what the research timeframe might be, he said. And, with many uncertainties remaining regarding the practicalities of large-scale methane hydrate development, the possibility of commercial gas production from the resource is still many years away. “The hydrate resource, globally, could be larger than all conventional hydrocarbons, but turning it into a reserve is far into the future,” Schoderbek said. http://www.petroleumnews.com/pnads/307447534.shtml