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Providing coverage of Alaska and northern Canada's oil and gas industry
March 2008

Vol. 13, No. 9 Week of March 02, 2008

The enigmatic sands

Point Thomson reservoir very promising, key to opening eastern North Slope

Alan Bailey

Petroleum News

Such heard of but never seen (at least not on the surface), the sands that form the primary reservoir of the Point Thomson field on the Beaufort Sea coast could form the hub of a new oil and gas field network at the eastern end of the North Slope. According to Alaska Department of Natural Resources estimates the field contains 300 million barrels of oil and natural gas condensate and 8 trillion to 9 trillion cubic feet of natural gas. And were development of this field to proceed, the availability of pipelines and facilities might make other smaller hydrocarbon pools in and around the Point Thomson Unit viable.

The Point Thomson Unit contains 45 leases on approximately 106,000 acres of state land just west of the Arctic National Wildlife Refuge. A total of 18 wells have been drilled in or near the unit, with the Point Thomson Unit No. 1 well being drilled in 1977.

But many of the wells are tight holes from which the well data have remained proprietary. In fact, reserves estimates for Point Thomson are somewhat uncertain “because much of the critical data remain proprietary after 30 years,” U.S. Geological Survey geologist Dave Houseknecht told Petroleum News Feb. 25.

So how much is known about the petroleum geology of Point Thomson?

Thomson sandstone

The Thomson Sandstone that forms the primary field reservoir is not seen anywhere at the surface but is known to consist of what geologists term a conglomeratic sandstone — a sand body that contains large rock fragments and pebbles, Houseknecht said. And the fragments and pebbles consist mainly of dolomite, thought to have derived from what is termed the Franklinian sequence, an ancient series of rocks that forms the economic basement to the petroleum systems of the North Slope.

The nature of the sands indicates deposition in a beach or shallow marine environment, Houseknecht said.

The sands lie in depressions in the Franklinian basement, on the flanks and crest of a structural high called the Mikkelsen High. The Mikkelsen High forms the eastward continuation of the Barrow Arch, a huge regional structure that is associated with most of the major oil fields of the central North Slope, including the giant Prudhoe Bay field. But according to USGS the Thomson Sandstone has not been found in every well at the eastern end of the Barrow Arch, suggesting that the formation does not have a blanket distribution across the region.

The sandstone forms part of what geologists call the Beaufortian sequence, a set of rocks laid down during the pulling apart of northern Alaska, when the Canada basin of the Arctic Ocean opened in Jurassic and early Cretaceous times. In fact, the Point Thomson Sandstone is broadly equivalent to the Beaufortian sands that form the reservoirs of the Kuparuk River field in the central North Slope.

Deposited in hollows

These various Beaufortian sand units formed from the erosion of pre-existing rocks and the subsequent accumulation of sand in sunken blocks or eroded hollows in those older rock formations. And across the North Slope a feature that geologists call the lower Cretaceous unconformity marks a major break in sediment deposition between Cretaceous deposits such as the Thomson Sandstone and the older rocks — the lower Cretaceous unconformity forms one of the major geologic features that enabled the trapping of hydrocarbons in North Slope fields.

In the case of Point Thomson, Houseknecht characterized the field as in part a stratigraphic trap, in that the geometry of sand body that now contains the hydrocarbon pool reflects the deposition of sand into a hollow in the Franklinian basement. On the other hand, the trap is in part structural, because the elevation of the sand body on the Mikkelsen High provided a migration path for hydrocarbons into the reservoir.

And that location at the crest of the Mikkelsen High raises some interesting questions regarding the possible sources of the hydrocarbons in the Point Thomson field, Houseknecht said. USGS thinks that the hydrocarbon charge could have come from a variety of sources both to the north and the south of the field. Those sources would include the characteristic sources of the North Slope such as the Shublik and Hue Shale but to the north could include a younger Tertiary source, Houseknecht said.

“It’s an area where offshore and onshore petroleum systems may overlap or even mix,” he said.

Franklinian reservoir

And another interesting question at Point Thomson is the involvement of the Franklinian basement in the field reservoir. In its plan of development and production Exxon refers to “pre-Mississippian section,” when presumably referring to the Franklinian.

“The pre-Mississippian section directly underlies and is in pressure communication with the Thomson Sand,” the plan says. “Because of the proximity and pressure communication between these reservoirs, development of the Thomson Sand will also deplete the pre-Mississippian section.”

There does not appear to be any publicly available information about the nature of the Franklinian reservoir rocks at Point Thomson and there is more than one possible reservoir scenario. However, geologists have in the past speculated about the possibility of an oil play in the Franklinian dolomites of the eastern North Slope. Dolomites are limestone-like rocks that erode into caves and fissures — it is possible that surface erosion of the Franklinian rocks prior to the deposition of later sediments combined with fracturing of the dolomites could have created holes and fissures in which oil or gas could accumulate.

Brookian prospects

Exxon’s plan also talks about designing Thomson Sand reservoir wells “to penetrate and evaluate the Brookian in one or more potential accumulation areas.”

The Brookian is the youngest of the major rock sequences of northern Alaska and formed in Cretaceous and Tertiary times as a result of the emergence of the Brooks Range. The emerging mountain range caused sediments to flow north into a huge basin called the Colville basin under the North Slope. Sediments also poured out over the Beaufort Sea continental shelf to cover the Point Thomson area.

And oil is known to exist in the Brookian at Point Thomson. In 1975 Exxon drilled the Alaska State A-1 well in the Flaxman prospect, at the northeastern side of the current Point Thomson unit. That well tested 2,500 barrels of oil per day from Paleocene sands of the Brookian sequence, Houseknecht said. A second well at Flaxman remains a tight hole. And BP discovered oil in the Brookian at Sourdough in the Point Thomson unit in 1997.

Good news, bad news

But the fact that the Brookian is a proven oil play has proved to be a good news, bad news story.

Production from the Brookian reservoirs of the Tarn and Meltwater fields of the central North Slope has proved successful. But BP’s disappointment with the badly underperforming Badami field near Point Thomson demonstrates the geologic risk inherent in oil and gas exploration.

The reservoirs of Tarn, Meltwater, Flaxman, Badami and probably Sourdough are in layered sandstones known as turbidites, formed when mixtures of sand and water flow periodically into a marine basin — each flow typically results in a thin layer of sand that lies sandwiched between layers of fine silt or mud. At Badami the turbidite flows have resulted in sand lobes, each of which forms a reservoir compartment within the oil field. Unfortunately, the individual compartments do not connect well with each other so that, although the field overall holds sizable oil reserves, it has proved extremely difficult to sustain adequate flow rates from production wells.

It is impossible to say from publicly available information whether the Brookian prospects in the Point Thomson unit would be plagued by Badami-style issues, or whether the oil pools would perform more like Tarn or Meltwater.

The Point Thomson challenge

But the technical challenges involved in producing hydrocarbons from the Point Thomson field itself have proved a subject of intense debate in the 30 years since the field was discovered.

Although there is an oil rim in the Point Thomson reservoir, the hydrocarbons in the pool consist predominantly of natural gas and condensate. And, because of the temperature and pressure regime in the reservoir, the condensate is mixed with the gas as a gas phase. However, those same pressure and temperature conditions are such that were the pressure of the gas to be reduced, the condensate would condense out as a liquid. Hence the use of the term “retrograde condensate reservoir” to describe Point Thomson, because the condensation of a liquid when the pressure is reduced runs counter to a normal expectation of liquids vaporizing under the effect of pressure reductions.

Initially, gas production from the field would bring condensate to the surface. As the gas pressure falls at the surface, the condensate would drop out and could be shipped to market. Unfortunately, however, continued production would cause the reservoir pressure to drop, thus causing the condensate to condense as liquid within the reservoir.

There are several ways of producing from this type of field. One is to operate the field as a regular gas field, leaving liquid condensate in the ground. Another is to inject gas back into the reservoir to maintain the reservoir pressure and thus achieve maximum economic condensate recovery, before operating the field as a conventional gas field.

Producing the field as a conventional gas field would raise issues of the reservoir becoming clogged by liquid condensate and of significant quantities of condensate remaining trapped in the reservoir — condensate has a higher economic value than the natural gas.

The second approach, known as gas cycling, could significantly improve hydrocarbon recovery but is expensive and technically challenging.

It seems from Exxon’s plan of development and production that the company plans to implement a relatively small gas cycling facility, to test that approach as an initial step in developing the Point Thomson field.






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