|
MMS re-assesses North Aleutian basin Promising source rocks, large potential trap structures, feasibility of exporting LNG all support the economics of gas production By Alan Bailey Petroleum News
Much has changed in the economics of oil and gas since 1995, when the Minerals Management Service last assessed the petroleum potential of Alaska’s North Aleutian basin. Since that time oil prices have shot upwards and natural gas has assumed a heightened economic importance.
In its new assessment of the basin, published in February 2006, the agency has completed a detailed, up-to-date evaluation of the petroleum geology and petroleum economics of the basin. In its report, available at www.mms.gov/alaska/re/re-ports/NAB06/nab2006.htm, the agency has confirmed a long-held view that the basin is gas prone, but has upped the mean estimates of technically recoverable natural gas from 6.79 trillion cubic feet to 8.82 tcf. At a gas price of $6.96 per thousand cubic feet 5.85 tcf of gas are likely to be economically recoverable, and that volume could go as high as 16.55 tcf. At a price of $12.10 per thousand cubic feet the mean estimate for economically recoverable reserves goes to 8.40 tcf and could be as much as 22.77 tcf. 17,500 square miles The North Aleutian basin, also known as the Bristol Bay basin, occupies about 17,500 square miles of territory under the northern coastal plain of the Alaska Peninsula and the waters of Bristol Bay. The basin consists of up to about 20,000 feet of Tertiary-age strata in a sunken area of basement rocks that forms an east-west aligned trough on the north side of the Alaska Peninsula. The basin floor slopes towards the basin center at a moderate angle on the north side and much more steeply on the south side.
MMS has included the smaller Amak basin, to the west of the North Aleutian basin, in its assessment. However, the MMS estimates of oil and gas resources only apply to those portions of the basins in federal lands on the outer continental shelf, outside the state waters along the coast of the Alaska Peninsula.
Well and seismic data indicate that thick sequences of the highly porous and permeable sandstones of the Oligocene-Miocene Bear Lake-Stepovak formations occur within the Tertiary sequence of the basin. These sandstone formations would make excellent reservoirs for oil and gas. Other potential reservoirs include sandstones of the early Eocene to early Oligocene Tolstoi formation and the early Pliocene to Holocene Milky River formations, according to the MMS assessment.
The MMS report says that the COST No. 1 stratigraphic test well, drilled in 1982-1983 in one of the deepest parts of the basin, offshore Port Moller, provides evidence that the Tertiary sequence also contains good petroleum source rocks. Analysis of rock samples from that well showed total organic carbon contents with petroleum source potential ranging from poor to very good, the report says. Cook Inlet comparison The strata of the Tertiary in the North Aleutians appear broadly similar to the terrestrial Tertiary strata of the Cook Inlet basin to the northeast, where biogenic gas has accumulated in the Tertiary sandstone reservoirs of major oil and gas fields.
In another analogy with Cook Inlet, the Tertiary of the North Aleutian basin overlies Mesozoic rocks — geologists have determined that the oil in Cook Inlet oil fields originated from the middle Jurassic Tuxedni formation of the Mesozoic rock sequence.
Similar Mesozoic strata to those under the Cook Inlet outcrop on the Alaska Peninsula along the southern and south-western margins of the North Aleutian basin. These strata contain good potential petroleum source rocks and are associated with some well-known oil and gas seeps.
But on the northwest side of Cook Inlet a major regional fault, known as the Bruin Bay fault, separates petroleum-bearing Mesozoic sedimentary rocks to the southeast from barren Mesozoic volcanic rocks to the northwest. Geologists can only trace the Bruin Bay fault at the surface as far southwest as Becharof Lake, at the northeast end of the Alaska Peninsula. And, in the absence of knowledge of where the fault goes to the southwest of Becharof Lake, geologists have long speculated whether petroliferous sedimentary Mesozoic strata or barren Mesozoic volcanic rocks lie under the deeper sections of the North Aleutian basin.
The MMS, in its new assessment, has postulated that the Bruin Bay fault runs close to the northern coastline of the Alaska Peninsula before heading west, offshore from a point to the northeast of Port Moller.
MMS has based this interpretation of the Bruin Bay fault on two lines of evidence. First, a significant and sudden change in the pattern of magnetic anomalies on either side of the proposed fault line would appear to indicate a transition from sedimentary rocks on the south side of the fault to volcanic rocks to the north. Second, the absence of the characteristic seismic patterns of Mesozoic sedimentary strata in seismic cross sections that depict the offshore basement suggests that the basement consists of volcanic rocks.
The MMS interpretation of the location of the Bruin Bay fault forms a crucial component of its new assessment, because it leads to the conclusion that there is no oil or gas of Mesozoic origin in the assessment area, other than in the extreme southwest of the area. And the assumed absence of Mesozoic oil in most of the area provides a major reason for believing that the North Aleutian basin is gas prone. Major Tertiary structures Another crucial component of the new assessment is the MMS interpretation of the structures depicted in offshore seismic cross sections. The MMS geologists have interpreted basement structures under the basin as huge fault blocks that were probably associated with early subsidence of the basin. Sunken blocks lie beneath the deepest sequences of Tertiary strata, including some of the oldest formations of the Tertiary sequence. Younger Tertiary strata lie draped across the tops and sides of the basement blocks between the sunken blocks. These draped strata form giant dome-shaped structures up to 133,000 acres in area.
And, as the primary oil and gas play in the North Aleutian basin, MMS postulates that petroleum formed in the Tertiary in the depths above the sunken blocks has migrated upwards into the sandstones of the Bear Lake-Stepovak formation in the draped domes above the raised blocks.
But, would conditions in the deeper rocks have been conducive to petroleum formation and what combination of oil and gas might have formed?
There is evidence from wells that the deeper rocks have thermal maturities sufficient for petroleum generation. The Becharof Lake No. 1 well southwest of Becharof Lake, for example, produced some thermogenic gas at depths below 5,500 feet. And, according to the MMS report, “thermally mature Tertiary strata reach thicknesses of 1,127 feet in the area of the Becharof Lake No. 1 well.” Samples from the 17,155 foot deep COST No. 1 well, offshore in the deepest part of the basin, show vitrinite reflectance values corresponding to thermal maturities within the oil and gas window below a depth of somewhat more than 10,000 feet.
All of this evidence points to the likelihood of “petroleum kitchens” of thermally mature rocks in the deep Tertiary strata above the sunken basement fault blocks. The Tertiary strata that are draped across the raised blocks are likely to be thermally immature. Gas-generating coals Although some of the Tertiary rocks within the petroleum kitchens contain abundant organic hydrocarbons, many of the hydrocarbons seem to occur in the form of coal. After looking at several methods for assessing the oil-generation capabilities of coal samples from the COST No. 1 well, the MMS analysts have concluded that the coal would produce gas rather than oil.
“The elemental data at hand indicate dominance of gas-prone type III kerogens in coal and non-coal lithologies alike. Oil-prone algal coals, if present, were not sampled by the North Aleutian Shelf Cost 1 well,” the MMS report says.
Although that result points to the generation of gas, the deepest part of the COST No. 1 well, below 15,620 feet, does contain rocks with abundant oil-prone kerogens and did have some oil shows. However, the MMS report presents evidence suggesting that even in this part of the well, known as the amorphous interval, the potential for the generation of liquid hydrocarbons was quite low.
“Based on these data, the ‘amorphous’ interval in the COST well is viewed as primarily a source for gas,” the report concludes.
MMS has also presented evidence that the Tertiary drape structures containing Bear Lake-Stepovak reservoirs over the raised basement blocks would have formed in time to capture and store petroleum bubbling up from the kitchens deep in the chasms between the raised blocks.
And with large trap structures, MMS thinks that this Bear Lake-Stepovak play could include some big hydrocarbon accumulations — MMS geologists have estimated that the largest pool could contain 4.65 tcf of gas, nearly twice as much as the largest gas field in the Cook Inlet. The mean estimated resources in the play are 406 million barrels of oil and condensate and 5.586 tcf of gas. Five other plays The Bear Lake-Stepovak play was the only play that the 1995 MMS assessment used to calculate the resource potential of the North Aleutian basin. However, the 2006 assessment recognizes five other plays:
• A Tolstoi play, involving the same petroleum source as the Bear Lake-Stepovak, but with the petroleum trapped in sandstones of the Tolstoi formation. The Tolstoi play might hold 123 million barrels of oil and condensate and 2.5 tcf of gas.
• A Black Hills uplift-Amak basin play involving Tertiary reservoir rocks over Mesozoic sedimentary strata, including oil and gas source rocks, in the southwestern part of the planning area. This is a relatively high-risk play that might contain 155 million barrels of oil and condensate, and 0.312 tcf of natural gas.
• A Milky River biogenic gas play, involving sandstone reservoirs in the Plio-Pleistocene Milky River formation but thought to contain very little technically recoverable gas.
• A Mesozoic deformed sedimentary rock play, involving folded and faulted Mesozoic strata south of the presumed western extension of the Bruin Bay fault, in the southwestern part of the planning area. This play is thought to be oil prone within the planning area but might only hold about 38 million barrels of oil condensate and 0.017 tcf of natural gas.
• A Mesozoic buried granite hills play, involving oil and gas from a Tertiary source in reservoirs consisting of fractured volcanic rocks of the Mesozoic basement of the North Aleutian basin. This is a high-risk play with potential resources of 30 million barrels of oil and condensate and 0.206 tcf of natural gas.
So, what does all of this mean in terms of potential oil and gas development?
From its geologic analysis MMS has identified 74 potential oil and gas prospects within the North Aleutian basin planning area. Taking these prospects and applying some statistical analysis to estimate additional, unidentified prospects in each play, MMS analysts derived estimates of technically recoverable oil and gas for the whole planning area. The calculations took into account oil and gas recovery factors for each hydrocarbon pool, using parameters such as estimated porosities, water saturations and reservoir pressures. The analysis also incorporated assessments of risk and uncertainty for both individual prospects and complete plays.
In assessing the economic potential of the area, MMS assumed several offshore fields connecting through a trunk pipeline to the Alaska Peninsula west of Port Moller. The pipeline would extend to an LNG facility at Balboa Bay on the south side of the peninsula. Analysts assumed that LNG exported from the North Aleutian basin would ship to the U.S. West Coast, Hawaii or perhaps the Asian Pacific Rim. The Cook Inlet might also become a destination for some of the LNG.
The analysts also assumed that it would be possible to load into tankers at Balboa Bay any produced oil and condensate, for shipping to the Cook Inlet, or perhaps Valdez.Using these development scenarios, the analysts determined that meaningful volumes in excess of 1 tcf of economically recoverable natural gas require prices greater than $4.54 per thousand cubic feet. But a viable gas industry from the North Aleutian basin would probably require developable gas reserve of 5 tcf. That would require a gas price of $6.50 per thousand cubic feet, a realistic possibility given current gas prices well above that level.
“If market prices can be sustained at the current level or higher, a large fraction of the North Aleutian basin gas endowment could ultimately be economically recoverable,” the MMS report concludes.
| 