|
Alaska gas hydrate well nears key test ConocoPhillips, DOE partner on project to unlock ‘fire in the ice’ bonanza through exchange of carbon dioxide, methane molecules Wesley Loy For Petroleum News
ConocoPhillips Alaska Inc. is seeking permission for a key test of its exploratory well targeting natural gas hydrates at Prudhoe Bay.
Hydrates are a solid, crystalline form of gas, usually methane, mixed in sandstone and water. A combination of cold and pressure keeps the gas as a solid.
The test will involve injecting tons of carbon dioxide down the well in an effort to free methane from hydrate-saturated sandstone.
The process involves exchanging CO2 molecules for methane molecules within the hydrate. The aim is to produce methane gas, leaving the CO2 sequestered inside the hydrate structure.
Laboratory studies have indicated this exchange will work, but it hasn’t been tried in the field.
ConocoPhillips on Oct. 17 submitted an application for the CO2 injection to the Alaska Oil and Gas Conservation Commission, which regulates drilling activity.
DOE partnership Gas hydrate represents a potentially huge new energy resource, with vast deposits in the Gulf of Mexico, off the Pacific and Atlantic coasts, and on Alaska’s North Slope.
The U.S. Geological Survey has estimated 85 trillion cubic feet of undiscovered, technically recoverable gas resources exist within hydrates in northern Alaska. That compares to the 35 tcf of known conventional gas in Prudhoe Bay and other North Slope fields.
The Ignik Sikumi No. 1 exploratory well is the result of a partnership between ConocoPhillips and the U.S. Department of Energy’s National Energy Technology Laboratory. The well’s name is Inupiaq for “fire in the ice.”
ConocoPhillips spudded the well on April 5 and reached total depth of 2,597 feet on April 16, an AOGCC well completion report shows.
It was drilled on an ice pad adjacent to the BP-operated Prudhoe Bay unit L-pad and temporarily suspended.
The plan now is to re-enter the well during the upcoming winter drilling season and run the production test, an online DOE project overview says.
“The production testing program will consist of CO2 injection and shut-in for exchange with methane to be followed by stepwise depressurization and flowback,” the overview says. “Once the exchange test objectives are met, the intent is to use the wellbore for continued production testing, including extended depressurization, potentially through the end of that winter season.”
First-time test Planned total funding for the project includes a DOE contribution of $20.9 million, with ConocoPhillips contributing $5.3 million. The upcoming production field trial is the most expensive phase of the project.
DOE and ConocoPhillips have said the Ignik Sikumi project will test, for the first time outside a lab, patented production technology for exchanging CO2 and methane molecules.
A joint DOE-ConocoPhillips data sheet said: “The trial will answer two basic questions: First, does the laboratory-proven exchange mechanism work in the field, with minimal sand and water production? Secondly, what kind of rates and exchange efficiency is demonstrated?”
The company’s application to the AOGCC for an “enhanced recovery injection order” offers additional details about the well and the planned experiment.
ConocoPhillips plans to inject a mixture of CO2 and nitrogen, with a total injection volume of about 20 tons.
“The source of the liquid CO2 is storage tanks and trucking from Fairbanks via Air Liquide to a CO2-approved ground vessel at the wellsite,” says the AOGCC application submitted by David Schoderbek, gas hydrates director for ConocoPhillips Alaska. “Nitrogen and carbon dioxide will be mixed on-site in a gas mixing skid. The maximum amount pumped daily will vary with formation permeability but 10 tons or 2356.2 gallons (56.1 barrels) is the maximum volume estimated. The gas is predicted to exchange with the methane molecules and stay in zone in the formation.”
The injection will go into the hydrate-saturated Sagavanirktok Upper C Sand, with proposed well perforations for injection at 2,243 to 2,273 feet.
No commercial development The targeted injection zone is between the overlying permafrost and the underlying Ugnu formation.
Plans don’t include hydraulic fracturing, so downhole pressures will be monitored to manage injection rates and avoid exceeding the strength of the rock, the AOGCC application says.
No underground sources of drinking water exist beneath the permafrost in the Ignik Sikumi No. 1 area, the application says.
The CO2 is expected to reach less than 15 feet into the Sagavanirktok Upper C Sand.
The Ignik Sikumi No. 1 site was carefully chosen to avoid any “hydrate dissociation” caused by the historic production of hot conventional fluids through nearby L-pad wells.
“Following a 10-14 day injection period, draw down will commence and produced fluids, including methane, will be flowed through surface well testing equipment where the produced gas will be heated, separated and measured,” the AOGCC application says. “Produced methane will be vented/flared onsite.”
The well likely will be abandoned once the CO2 pilot project is complete.
“No plans for future experimentation or commercial development exist at this time,” the application says.
| 