Another test of methane hydrates on the North Slope, a potential huge new gas resource, is being planned.
State officials are in discussions with the U.S. Department of Energy and the Japan Oil, Gas and Metals National Corp., or JOGMC on possible joint-sponsorship, and talks are planned with North Slope producers about potential sites for a test within one of the operating units on the Slope, Commissioner of Natural Resources Mark Myers said.
A technical evaluation of different sites is now underway, Myers said. Drilling within an existing industry unit is preferable for cost reasons but sites on nearby unleased state lands set aside for hydrate research are also being evaluated; those are lacking in infrastructure and less is known about the potential for hydrate accumulations, however.
Myers, a former head of the U.S. Geological Survey and Alaska Oil and Gas Division director, has long been intrigued with the possibility of that hydrates could eventually be a huge new energy resource. He now sits on the U.S. Department of Energy’s hydrates advisory board.
Both the DOE and the U.S. Geological Survey have been extensively engaged in hydrates work, Myers said. The DOE advisory board’s recommendations for continued work focuses on not only as hydrates as a potential energy resource, but also as a hazard (drillers can unexpectedly drill into a hydrate, causing shallow gas blowouts) and the contribution that hydrate melting, mainly offshore, and release of methane, a potent greenhouse gas, could be making in global climate change.
JOGMC, a Japanese industry group that participated in previous North Slope hydrates work and has also been engaged in hydrates research offshore Japan, may take part in helping fund a new slope test. The cost of the well could reach $30 million.
Hydrates are crystalline structures of ice and methane, the main component of natural gas, which form at shallow depths under certain temperature and pressure conditions. They are known to exist offshore in many parts of the world including offshore Japan, India, the U.S. Gulf of Mexico, and in permafrost areas of the Arctic.
On the North Slope they have formed beneath and in some cases within, the permafrost, or the permanently-frozen soil and rock that underlies much of the Slope.
Hydrates can hold large amounts of methane. The U.S. Geological Survey has estimated that about 84 trillion cubic feet of methane could be technically produced from hydrate-prone permafrost areas of the North Slope.
In another study, 12 trillion cubic feet of methane capable of being technically produced were estimated to be in hydrates in the immediate central North Slope area, in the Prudhoe Bay, Milne Point and Kuparuk River fields.
The challenge is finding ways to produce the methane from the hydrates, a problem government and industry scientists have focused on in recent years.
As it turns out, the North Slope is an ideal laboratory for research and tests because of the presence of infrastructure like roads, which lowers costs compared with working in roadless areas like Canada’s Mackenzie River delta, where hydrates have also been found.
The Arctic onshore hydrates are also in sandstone formations, which would be technically easier to produce from than the fine-grained sediments in which offshore hydrates are often found.
There are big stakes in this, Myers believes. If the methane can be produced economically it would add a huge new gas resource to backstop a planned North Slope natural gas pipeline, he has said.
At present, the known and proven conventional natural gas reserves of the slope, estimated at about 35 trillion cubic feet, or tcf, are enough to keep the planned Alaska LNG Project at capacity for about 15 years. After that, additional gas supplies will have to be available, state officials have said.
While there are large potential and undiscovered conventional gas resources on the Slope — 100 tcf is an estimate often cited — methane from hydrates could almost double that if technical problems can be overcome.
So far there have been three hydrate test wells on the North Slope and one in Canada, in the MacKenzie Delta, with each test advancing scientists’ understanding of hydrates and how the methane might be produced.
The test being discussed now would be the first long-term production test, possibly lasting 18 months to 24 months, Myers said.
The Canadian test, at the Mallik well in 2007, drilled into a hydrate and showed that methane could be produced, although it was a short, six-day test. At Prudhoe Bay, an early test by Anadarko Petroleum to do a hydrate production test was unsuccessful when the company did not find the hydrate where it was thought to be.
There is learning from failure, however, and scientists reworked their research and developed new seismic techniques to more effectively locate hydrates. That was successful and hydrate were successfully located in the Milne Point field, then operated by BP, where that company drilled a second test in 2007, the Mt. Elbert well. Hydrate cores were successfully extracted for research.
In 2011 ConocoPhillips operated a third hydrate test on the slope in the Prudhoe Bay field, Ignik Sikumni No. 1, which involved an actual production test that was done for 30 days.
ConocoPhillips tested two possible production techniques at Ignik Sikumni, one involving the gradual depressurization of the hydrate, which allows the hydrate to thaw and the methane to escape (but also potentially destabilizing, or melting, the hydrate) and a second technique involving the substitution of carbon dioxide for the methane in the hydrate, a technique aimed at preserving the structure of the hydrate.
In the chemical “exchange” of CO2 for methane, the methane could be produced and the hydrate could be kept intact, in its frozen state, by injecting the C02. Keeping the hydrate intact can be important because thawing the hydrate could create side-effects, like subsidence at the surface where the hydrate is shallow, which most are.
The CO2-methane “displacement” technique also has an advantage of creating a potential for permanent sequestration of C02 in the frozen hydrate. CO2 is a “greenhouse” gas that scientists say contributes to global warming.
If a natural North Slope gas pipeline is built the C02 in the conventional natural gas on the slope, constituting about one-eighth of the Prudhoe Bay gas resource, will have to be extracted there and uses for it, or places to put it, will have to be found.
ConocoPhillips’ test was encouraging for both techniques but its duration was not long enough to answer a lot of other questions. A big question is whether a “freeze-back” might occur as a hydrate is depressured that could plug up the hydrate, preventing a flow of methane, according to Paul Decker, a senior geologist in the state Division of Oil and Gas.
Myers said several sites for the possible upcoming test are under consideration, including locations within the Prudhoe Bay and Milne Point units, where hydrates are known to occur, as well as on nearby tracts of unleased state lands where hydrates are possible but have not been confirmed.
The test would likely cost less if done within one of the industry units because infrastructure would be available. However, permission from the unit operators, the producing companies, would have to be obtained, and the test would have to be planned so that it does not impair operations in the unit, Myers said.
There is also the element of geologic risk, that the hydrate might not be there, which would be lower for a test well in Prudhoe Bay or Milne Point where the presence of hydrates has been confirmed.
So far there have been some positive reactions from Prudhoe Bay unit owners, Myers said. Discussions have been held with ExxonMobil, one owner of Prudhoe Bay, which was positive, he said. Talks with BP and ConocoPhillips, the other major owners, are scheduled.
There are four or five possible sites for a hydrate test in Prudhoe Bay and at least two sites in Milne Point, but permission there would have to come from Hilcorp Energy, now half owner and the operator of that field.
Myers said a long-term production test is important for a number of reasons.
“It would give us a chance to understand the physics and chemistry (of the hydrate) and what to see happens to the permeability in the sands (the small spaces that allow gas fluids to flow) and how a sandstone reservoir would really perform,” he said.
“The modeling that has been done (based on previous shorter tests) has been encouraging but we need to validate the modeling.”
Meanwhile, people ask why the government should provide funding for research like this and why industry isn’t leading.
Industry has contributed and even led projects in the past, but the very long lead-time for the development of a brand new resource like methane from hydrates can make it difficult for companies who typically have shorter-term strategies, particularly in an environment like today’s.
“Most people see any commercialization of hydrate production as several decades out,” Myers said.
But there can be surprises. The U.S. Department of Energy and U.S. Geological Survey did a lot of the initial research into coal-bed methane, or gas from coal seams, as well as producing gas, and oil, from shales.
Once the basic science was understood industry moved quickly to commercialize the potential, Myers said. Hydrate methane production could happen faster than people now believe, he said.
Offshore hydrates will take longer to test and someday produce because costs will be higher. Hydrates are known offshore Japan and in the U.S. Gulf of Mexico but in waters depths of 6,000 feet or so, which means offshore drilling equipment must be used.
Chevron Corp. led a testing program to locate hydrates in the Gulf of Mexico but although hydrates were found in sand formations, which would in theory make good reservoirs, no cores were taken and Chevron has since dropped out of the program, according to Ray Boswell, head of the U.S. DOE’s hydrates program.
Overall, the results were encouraging enough that the University of Texas has stepped in to work with the U.S. DOE to continue the program, the extraction of cores being the next step, Boswell said.
In another development, JOGMC, the Japanese consortium, led its own hydrate test drilling program offshore Japan, drilled a well and conducted a short-term production test, Boswell said.
The results were again encouraging enough that Japan’s government, which funded the tests, is likely to approve more work. JOGMC has participated in past North Slope tests, and may do so again, because what is learned in a long-term production test can be applied offshore Japan, Boswell said.