|
3.5 tcf: ! or ? Escopeta announces a historic Cook Inlet discovery; officials remain skeptical Eric Lidji & Kay Cashman Petroleum News
Escopeta Oil Co. is touting what would be one of the largest natural gas discoveries in the history of the Cook Inlet basin, but public officials expressed early skepticism about the news and wouldn’t say whether a meeting with the company alleviated their concerns.
The Houston-based independent issued a statement on Nov. 4 saying it had discovered approximately 3.5 trillion cubic feet of gas in place at its offshore Kitchen Lights unit.
Escopeta and its contractors based the estimate on the results of the top half of Kitchen Lights Unit No. 1, the first well of a five-well exploration program planned for the unit.
Escopeta began drilling KLU No. 1 in early September using the Spartan 151 jack-up drilling rig, and suspended operations for the year at 8,805 feet on Oct. 28 because of seasonal restrictions caused by winter sheet-ice flows in the region, the company said in its statement. Officials originally gave the company until Oct. 31 to suspend drilling operations for the year, but later extended the deadline until mid-November because of later than expected good winter weather.
Gas shows ‘impressive’ KLU No. 1 discovered approximately 46.7 billion cubic feet of gas in place, according to Bruce D. Webb, vice president of governmental and regulatory affairs for Escopeta.
“The gas shows were very impressive,” Webb said.
The unfinished well encountered 670 net feet of producible sands in the Sterling and Beluga formations bearing 536 million cubic feet of gas in place per acre, according to logging by Schlumberger Ltd. and analysis by NuTech, and “geophysical interpretations” suggest those sands extend for more than 6,500 acres around the well, Escopeta said.
When Escopeta resumes operations in the spring, it plans to continue drilling KLU No. 1 to a total depth of about 16,500 feet, into the Jurassic formation.
“Escopeta is very excited by the results of this well, especially since we are only halfway down to the planned total depth. We still have to drill through the Tyonek gas formations, and then into the Sunfish and Hemlock oil formations, on our way to the Jurassic,” Webb said.
However, “the results from just the top half of our first well are sufficient to commence planning and engineering for commercial gas production,” Webb added, and Escopeta is “currently in the preliminary design stages of an accelerated natural gas development scenario that could bring new gas deliverability to Cook Inlet as early as 2013.”
Optimism and skepticism Given the concerns about declining production in Cook Inlet, and the attempts by policymakers to address those concerns, the announcement drew considerable applause.
“I am pleased that Alaska is seeing the results of tax credit legislation that provides incentives for explorers and producers to continue investing in Alaska,” Gov. Sean Parnell said in a statement on Nov. 7, referring to Senate Bill 309 passed last year, but he also noted that “additional wells are required to confirm the company’s estimates.”
The three members of the Alaska congressional delegation released a joint statement calling the discovery “a critical step in exploring Cook Inlet and vindication of the congressional delegation’s efforts to address Jones Act issues related to the company’s use of a foreign-flagged vessel to deliver a specialized drilling rig to Alaska.” (Escopeta is challenging a $15 million fine from the U.S. Department of Homeland Security for bringing the Spartan 151 jack-up rig to Alaska, allegedly without a valid waiver of the federal Jones Act that requires ships moving between domestic ports to be built, manned and flagged by U.S. crews.)
The size of the discovery, as well as details about its operations, and the timing of the release after the close of business on Friday, prompted two of the state’s highest-ranking oil and gas officials to raise an eyebrow in an Anchorage Daily News article on Nov. 7.
“They have made a bold claim and right now the division can’t substantiate either way, positive or negative. It definitely is an encouraging sign but they’re going to need several more wells to prove up what the true potential is,” Division of Oil and Gas Director Bill Barron said.
Cathy Foerster, one of three commissioners on the Alaska Oil and Gas Conservation Commission, echoed Barron’s sentiment in harsher terms, saying, “It’s possible their numbers are good. It’s possible their numbers are bad. In fact, we think making an announcement of this kind, with so little firm data, is irresponsible.”
Looking to avoid dry hole rumors Escopeta, ironically, said it released the news when it did to prevent skepticism.
The company did not set casing for the well through the productive zone, as is common for discovery wells, but instead plugged the well with cement at around 4,900 feet.
Concerned that “detractors” might use that information to publicly hypothesize that Escopeta drilled a dry hole at KLU No. 1, the company chose to make an announcement about its discovery sooner rather than later, Vladimir Katic, Escopeta’s general manager in Alaska, told members of the Anchorage Mayor’s Energy Task Force on Nov. 8.
“We came out with the facts. We can confirm those facts,” Katic said.
Asked to respond to the Anchorage Daily News article, Katic said Foerster’s claim that Escopeta acted irresponsibly was “damaging to the company and to the personnel that worked on this project,” but Webb, who wrote and distributed the press release, said he agreed with Barron, to a point: “It is a bold statement, but they haven’t seen the data yet.”
Escopeta executives finally met with Division of Oil and Gas officials on Nov. 9, but Barron declined to discuss the details of the meeting with Petroleum News, because the well is a tight hole.
Possible, but unlikely A 3.5 tcf discovery in Cook Inlet is entirely possible, but somewhat unlikely, according to two major resource assessments of the basin released over the past decade.
The U.S. Department of Energy estimated in 2004 that the basin potentially contained between 13 tcf and 17 tcf of undiscovered conventionally recoverable gas, in addition to the 8.5 tcf of recoverable gas already discovered at that point. That estimate used an 85 percent recovery rate. Unlike the structural traps that contained the gas found to date, that undiscovered gas, the DOE believed, would largely come from stratigraphic traps.
Operators discovered the major gas fields in Cook Inlet by accident while searching for oil. Exploration specifically targeting gas didn’t begin until the late 1990s. To date, there have been no exploration efforts in Cook Inlet focused on stratigraphic traps. The prospects in the Kitchen Lights unit include both structural and stratigraphic traps.
Because the DOE report estimated that the largest possible undiscovered field in the basin could contain around 3 tcf of original gas in place, David Hite, one of the authors of the report, told Petroleum News on Nov. 9 that the Escopeta discovery was “at the upper end of what I would consider reasonable to expect” although “not impossible.”
Earlier this year, the U.S. Geological Survey estimated that the Cook Inlet basin could contain a mean of 13.7 tcf of conventional undiscovered gas resources — Kitchen Lights is conventional — with the largest mean field size expected to be around 2 tcf.
“I might not have a problem if it was half to two thirds what they were talking about,” Hite said, (i.e. an Escopeta discovery in the range of 1.75 tcf to 2.3 tcf in place). If Escopeta is right, though, its discovery is “as big as it gets,” Hite said, saying it would be as large, if not larger, than the Kenai gas field that launched Cook Inlet production.
To relieve his skepticism, Hite said he would like to see a drillstem test and a second well, and would like to know where Escopeta drilled along the geologic structure it’s exploring and “what kind of assumptions they’re making about the nature of the reservoirs.” Acknowledging the limited amount of information made public so far, Hite said his largest concern is that the Escopeta announcement appears to assume “a blanket reservoir” at Kitchen Lights, despite the discontinuous nature of the Beluga sands.
Escopeta tested both the Sterling and Beluga formations in KLU No. 1 using a downhole wireline tool called a Modular Dynamic Tester, or MDT, according to an Escopeta official who asked not to be identified. The company has not released the results of that test.
An MDT is a tool for testing pressure within a well bore, but it can also be used as a cheaper and quicker, but potentially less accurate way to measure recoverable reserves.
“An MDT test that shows a lot of producible hydrocarbons” will always match, or at least be very close to, the results of a traditional flow test from the same well, a long-time Cook Inlet basin petrophysicist told Petroleum News on Nov. 9, “but an MDT test that does not show commercial quantities of hydrocarbons can be wrong,” he added.
AOGCC rules once required an operator to conduct a flow test to the surface to establish recoverable reserves, but in 2008 the agency set a precedent by agreeing to accept the results of an MDT test that UltraStar Exploration was preparing to drill; a well that proved to be a dry hole.
Planning for 2012 drilling The only way for Escopeta to convert skeptics is to release its MDT results or continue drilling.
The company plans to complete KLU No. 1 next spring and drill a second well at the unit next summer. Webb told the Energy Task Force that the second well would either be a delineation well near KLU No. 1 or would test another prospect in the unit. Escopeta might bring a second jack-up rig into the basin to speed up its drilling schedule, he added.
Most importantly, though, Escopeta must reach a total depth of 16,500 feet at KLU No. 1.
That depth is important because Escopeta must penetrate the Jurassic formation to qualify for a significant one-time tax credit: 100 percent of its well costs up to $25 million. The tax credit goes to the first company to drill into the Jurassic using a jack-up drilling rig.
Escopeta said its exploration program “was made possible largely” because of recent incentives to spur exploration in Cook Inlet, specifically citing the tax incentives included in Senate Bill 309, authored by Sen. Lesil McGuire. That bill included the jack-up rig credit, known as the “Stampede Amendment,” authored by Sen. Tom Wagoner.
Although it can’t claim the credit until it hits the Jurassic, Escopeta qualified for the credit as soon as its drill bit hit the seafloor. Buccaneer Alaska LLC, the local subsidiary of an Australian independent, is working to bring a jack-up rig to the basin next summer, but is not expecting to receive the credit, nor has it built the credit into its economic models. The credit is tied to the first rig to start drilling.
A potential game changer The Kitchen Lights unit is the largest unit in the Cook Inlet basin, and includes four distinct oil and gas prospects: Corsair, Kitchen, East Kitchen and Northern Lights.
The KLU No. 1 well is in the Corsair prospect.
Escopeta believes it can recover at least 50 percent of the gas in place at its leases; an average in Cook Inlet is 85 percent. If successful, that could upend market dynamics in the Cook Inlet region, where a decades-long decline in production and deliverability have prompted many business decisions.
Those include:
• The closure of the Agrium fertilizer plant.
• The pending closure of the Kenai liquefied natural gas export facility.
• Numerous proposals in the past decade to build an in-state gas pipeline — as a standalone “bullet line” or a spur line — from the North Slope into Southcentral.
• Efforts to diversify the regional supply mix through wind and hydropower projects.
Escopeta recently detailed its development options at Kitchen Lights, saying that it favored an outrigger caisson for a gas-only development that could eventually become a three-deck platform for a gas and oil development. The gas-only option could come online as soon as 2013, but only if the project faces little to no delays going forward.
| 