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New model needed Lower Cook Inlet geology differs from upper, developed area, says Boyd Kristen Nelson Petroleum News Editor-in-Chief
The Minerals Management Service has a lower Cook Inlet oil and gas lease sale scheduled for May 19 in Anchorage.
Whatever happens, it probably won’t be what happened in October 1977.
At the 1977 sale, the first in lower Cook Inlet, 27 companies bid some $400 million for 87 of the 135 leases offered, and started exploring the next year, drilling 10 wells and three redrills from drillships, jack-ups and semi-submersibles by 1985.
Ken Boyd told Petroleum News that he doesn’t expect this year’s sale to be that kind of a barn burner.
For one thing, the drilling ended, the leases are gone and there is no production from the lower inlet.
In addition to the oil price bubble bursting, the companies who drilled wells variously named Guppy and Coho (Marathon), S. Arch and Bede (Phillips), Hawk, Ibis and Raven (ARCO Alaska) and Falcon and Shelikof (Chevron), discovered that lower Cook Inlet doesn’t have the same geology as upper Cook Inlet.
Boyd said the price of oil, which was high and expected to stay high, was a driver in the 1977 sale. “I think the expectation was that the oil prices were never going to go down,” he said.
So were the big structures in lower Cook Inlet, structures like those that yielded major finds in upper Cook Inlet in the 1960s — “these big reverse faults, these huge very obvious structures that you could see on seismic,” said Boyd, who came to Alaska with Marathon in 1978 and later spent 10 years at the Alaska Division of Oil and Gas, as deputy director and then as director, and who is now a consultant for EnCana, which is prospecting North Slope and Foothills acreage. Different geology In the 1970s, Boyd said, companies “were probably using an upper Cook Inlet model for a lower Cook Inlet sale.” Other than a stratigraphic well drilled by ARCO, “there were no wells down there … and nobody really knew very much, and so they used the same model.”
In upper Cook Inlet, Boyd said, “if you have the Jurassic rocks and you have Tertiary rocks sitting on top of them, you’ve probably got an oil field.”
It may not be commercial, but it probably is an oil field, because the Jurassic Tuxedni formation is the source rock for the oil and the Tertiary Hemlock and Tyonek form the reservoirs that hold the oil.
“And if the Cretaceous gets in there” in the middle in the upper inlet, “then you probably don’t have an oil field,” because the Cretaceous prevents oil from getting into the reservoir rocks.
“But in the lower Cook Inlet … the Cretaceous seems like it might be the reservoir,” Boyd said.
The Tertiary thins out as you move south, he said, and there is almost none in the body of the MMS sale area, so what is the source rock in the upper inlet, doesn’t continue into the lower inlet. New view needed for lower inlet Boyd said he thinks anybody going to this year’s sale is going to have to rethink the way they explore.
They’re going to have to “forget about the upper Cook Inlet model, except in a few places.”
And, “you can mainly forget about these big structural plays. Maybe not forget about them, but maybe they’re not as important.”
Instead, he said, companies should do what has been done on the North Slope, “look for these stratigraphic plays.”
Prudhoe Bay and Kuparuk, Northstar and Milne Point and Endicott, “the great old fields of the North Slope,” were all discovered relatively early, he said, and then there was “this sort of dead period … when people couldn’t find anything.” And then, with the advent of 3-D seismic, companies started to have exploration success on the slope again, but with stratigraphic plays, finding Badami on the east, Tarn and Meltwater south of Kuparuk, and Alpine to the west. No good seismic for area Can you pull the same rabbit out of the hat in lower Cook Inlet? Boyd asked.
“Is the same rabbit available to be pulled out of the hat in lower Cook?”
It’s hard to know because there is very little 3-D seismic in lower Cook Inlet.
“Most of the seismic is very old and it’s very, very lousy,” he said. “So the database is pretty weak” going into the sale.
There are records from the wells, and MMS said in its draft environmental impact statement for the Cook Inlet planning area that three of the wells found oil in the Cretaceous. Two had significant shows in the late Cretaceous, but tested non-commercial flow rates; the third well had shows but was not tested. All of the wells at the 10 prospects tested (13 wells including three redrills) were plugged and abandoned. No leases from the 1977 lease sale remain, nor do any from a second sale, in 1981, which brought in $4.4 million from two bidders for 13 leases of 153 offered. Ten wells were drilled on leases from the first sale, three on leases from the second. A third sale of a portion of lower Cook Inlet, in 1997, offered 101 blocks but only two, now part of the Cosmopolitan unit off Anchor Point, were taken in that sale. Reservoir quality an issue In addition to demonstrating that oil didn’t exist where companies expected to find it, Boyd said the drilling turned up a “huge problem, geologically, in lower Cook Inlet … There are zeolites, in particular one called laumontite.”
Laumontite is a mineral that “deposits in the pore spaces,” destroying the porosity of what might have been good quality reservoir rock.
This is different than permeability, the ease with which oil moves between pore spaces, Boyd said: laumontite cement plugs the pores in the rock, so you don’t have a reservoir to hold the oil.
If the oil didn’t go into potential reservoir rock cemented with laumontite, did it go somewhere else? These, he said, are “the usual kind of questions you have to go through” when you try to figure out whether an area might produce hydrocarbons, and, he said, the laumontite question is probably not something you could figure out from seismic — if you had seismic. Different players than upper Cook Inlet Not only are lower Cook Inlet rocks different than upper Cook Inlet rocks, but Boyd said he expects the players would be different, too. Upper Cook Inlet is attracting mature basin players, he said, smaller companies which are developing smaller fields and producing reserves around older fields.
But there is no infrastructure in lower Cook Inlet, and the costs to work there will be high.
Drilling from onshore won’t really be an option, he said, and costs of $15 million to $18 million have been discussed just to bring in a drillship or semi-submersible to work in water depths ranging up to 600 feet.
MMS estimates a mean of 600 million barrels of economically recoverable oil at $30 oil prices. If that was one field, he noted, it would be in the range of Alpine, but perhaps in 200 feet of water some 25 miles from shore.
A small company, he said, probably couldn’t handle the “huge risks, the huge up-front costs,” and then the challenge of getting oil or gas to shore.
And with only poor data available, “it’s going to be a tough first go,” he said.
Good seismic is a necessity if you’re looking at stratigraphic plays, he said, and 3-D seismic is very expensive.
He said he hopes “somebody has the wherewithal to go out there and give it a shot, and at a minimum get some decent (seismic) data shot out there,” and either figure out that “this won’t work, will never work, or … maybe if we looked over here, maybe if we look at this kind of thing.”
Boyd also said he wonders if the players who come to the lower Cook Inlet sale could be a clue to the kind of companies that might be interested in the state’s Bristol Bay sale. Bristol Bay is onshore, and the basins are very different, he said, but there also hasn’t been much success with the rocks there and it’s pretty far away from infrastructure.
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