We know that the gas hydrates under Alaska’s North Slope contain vast quantities of valuable natural gas. But finding a practical and economic way of tapping into this giant resource presents some major challenges.
Gas hydrates concentrate natural gas by combining methane with water to form a solid crystalline substance under certain temperature and pressure conditions. The hydrates have enormous gas carrying capacity, because when they break down or disassociate they can yield 164 to 180 times their volume of free gas.
And there’s known to be a gas hydrate stability zone, in which the pressures and temperatures are conducive to the formation of the hydrates, under wide areas of Alaska’s North Slope. Moreover, with a productive petroleum system in the region, researchers have assessed the possibility of as much as 519 trillion cubic feet of natural gas in the form of gas hydrates under the permafrost of northern Alaska.
Confirmed accumulations occur in the so-called Tarn and Eileen trends that lie in an area over parts of the Prudhoe Bay, Milne Point and Kuparuk River oil fields — drilling programs associated with these oil fields have found gas hydrates near the surface. The U.S. Geological Survey has estimated that the two trends together contain as much as 100 tcf of natural gas.
However, only two gas hydrate test wells have been drilled on the Slope: the Northwest Eileen State No. 2 well drilled above the Prudhoe Bay field in 1972 and the Hot Ice well drilled south of Prudhoe Bay in 2002/2003. The Northwest Eileen State No. 2 well discovered the Eileen trend and the Hot Ice well did not encounter gas hydrates.
North Slope investigation
A team from industry, government and university has been investigating the known gas hydrate deposits in the central North Slope. BP Exploration (Alaska), ASRC Energy Services, Ryder Scott Co., USGS, the U.S. Department of Energy, the University of Alaska Fairbanks and the University of Arizona have all collaborated in this project, which completed an initial phase of seismic calibration, reservoir modeling and economic evaluation in 2004.
The team wanted to assess “whether there was a commercially viable prize out there,” Scott Digert, subsurface team leader for BP, told Petroleum News. “Could you actually produce these things in a commercially viable way?”
The results from the first phase of the work have been very encouraging, Digert said.
The team also established some new seismic techniques for locating hydrates in the subsurface.
“We think that we can actually identify the presence of gas now in the shallow seismic,” Digert said.
Stratigraphic test well
The project is now entering a data collection phase, to obtain detailed field data about the gas hydrates deposits. As a means of data acquisition BP is designing a shallow stratigraphic test well for possible drilling this winter between two well pads at the Milne Point field — a final decision on the drilling has yet to be agreed with DOE.
If the drilling goes ahead the well will test the effectiveness of the seismic techniques established in phase one of the project — the well will drill into a gas hydrate prospect identified from seismic data, Digert said. Verifying the accuracy of the seismic techniques should enable more accurate pinpointing of gas hydrate prospects.
However, sampling and logging from the well should also provide invaluable information, such as the amount of free gas associated with the hydrates.
“We’ll also get some very good data that needs to be gathered around what is the saturation of the hydrate in the formation, what is the water saturation within that hydrate bearing zone,” Digert said. “It could be that we have some free water present.”
Gas hydrate workshop
In mid-August the Alaska Department of Natural Resources and USGS convened a gas hydrate workshop in Anchorage to review the status of data acquisition and evaluation; gas hydrate reservoir modeling and production testing; and industry synergies and opportunities.
Workshop participants from government, industry and academia confirmed that gas hydrate research now needs subsurface data acquisition and test drilling. A dedicated gas hydrate test well would provide critical geologic and engineering data, the workshop participants concluded.
The participants also discussed the potential for acquiring gas hydrate data from “wells of opportunity” — wells drilled through the gas hydrate zone to deeper targets. This type of data acquisition would involve costs additional to conventional drilling and logging but “the group concluded that in some cases the risk and cost associated with the gas hydrate data could be justified if the operators were able to see a cost-benefit of the proposed effort,” according to the workshop proceedings.
Production techniques
The workshop reviewed the current status of reservoir modeling for gas production from hydrate reservoirs. The simplest production technique involves reducing the reservoir pressure by extracting free gas adjacent to the hydrates. The pressure reduction causes the gas hydrate to start to disassociate into methane and water. Continued extraction of gas then keeps the reservoir pressure low and causes more and more hydrate to break down.
Where there is no free gas, it is necessary to apply heat or chemicals to disassociate the hydrates. For example, raising the reservoir temperature by pumping heat down well bores will release gas.
Computer models of these production techniques have provided valuable insights into production viability and some researchers have also conducted laboratory tests into disassociating hydrates. However, results from a gas hydrate test well in the Mallik field of the Mackenzie Delta have highlighted complexities in real gas hydrates that are difficult to simulate in a computer or a laboratory.
These complexities point to the need for field trials of gas hydrate production, using a prototype production facility. This facility should be on a field scale, rather than a well scale, “to obtain a better field scale response; to establish and observe trends in reservoir pressure, disassociation and thermal properties; and to perform actual production testing,” according to the workshop proceedings.
And the workshop participants emphasized the benefits of testing a gas hydrate production facility over an extended time period, to fully simulate the operation of a producing gas hydrate field.
Some way to go
This type of testing remains some way down the road for the central North Slope project. If the results from the stratigraphic test well prove promising the next step could involve production testing, Digert said. But the stratigraphic test well planned for this winter is unlikely to be suitable for production testing and additional drilling would probably be involved.
So huge questions remain regarding how much, if any, of the gas hydrates that exist can be produced economically. In fact participants at the gas hydrate workshop concluded that “much more is known about the occurrence of gas hydrates than their sustained economic production.” And the participants agreed on the need for a high level of cooperation between government, industry and researchers from other organizations, if this valuable resource is to be successfully exploited.
But will the giant gas hydrate resources on the North Slope ever come out of hibernation?
“It’s a very large in-place number … and we need to understand now what does that mean for an actual resource — is that 0 percent recoverable or 50 percent recoverable? — that’s what we’re really trying to find out,” Digert said.
