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Ins, outs of developing ANS gas fields MMS’s Jim Craig talks about what, and how long, it will take to develop new natural gas discoveries on Alaska’s North Slope Alan Bailey Petroleum News
The ongoing debate about a natural gas line from Alaska’s North Slope has focused attention on the economics of the line and issues such as expandability of pipeline capacity to accommodate as yet undiscovered gas. But what might be involved in bringing on stream a new gas field on the North Slope, in the Brooks Range foothills or offshore in the Beaufort or Chukchi Seas? Could such a field be viably developed? And how does all of this play into the economics and risks of gas line development?
U.S. Minerals Management Service geologist Jim Craig talked to Petroleum News April 12 about the practicalities of gas field development; Craig has been involved in MMS economic evaluations of northern Alaska oil and gas resources.
In essence, there’s relatively little difference between gas fields and oil fields, in terms of what is involved in exploration and development, Craig said. Both types of field are discovered through the use of seismic surveying and exploration drilling. Following a discovery, delineation wells clarify the extent of the petroleum pool. And field development in Arctic Alaska entails the construction of gravel pads, production facilities and an export pipeline, as well as the drilling of field development wells.
In northern Alaska, both exploration and development often require the construction of airstrips and winter ice roads.
Fewer wells But the development drilling in a gas field typically requires fewer wells than an oil field, and that could reduce field development time — the relatively wide spacing of gas production wells might drive a need for more, smaller drilling pads than would be found in an oil field.
“Because gas moves more easily through the rock (than oil), the spacing on the wells … is a lot farther apart than on an oil field,” Craig said. “As a rule of thumb it’s usually four times the drainage per well for a comparable reservoir. …So you’d drill a lot fewer wells, maybe a quarter of the wells.”
And unlike an oil field, a gas field doesn’t need injection wells to maintain reservoir pressure and drive the petroleum fluids to the production wells, Craig said.
In addition, gas well completions tend to be fairly simple, with typical wells penetrating vertically through the gas reservoir.
However, Craig cautioned against assuming that the simpler drilling requirements of a typical gas field would necessarily have a dramatic impact on overall field development time scales. Oil or gas fields usually go into production part way through the development drilling program, at a point where there are sufficient producing wells to render production viable, Craig said.
Wet gas A key factor for gas production in northern Alaska is that most gas found in the region is likely to be what geologists term “wet gas,” formed by the thermal cracking of hydrocarbon material deep underground. Wet gas contains condensates in addition to methane, the primary component of natural gas. Condensates are hydrocarbons that condense as liquids at surface temperatures and pressures.
Thermally generated gas also commonly contains incombustible impurities such as carbon dioxide, and perhaps hydrogen sulfide.
The presence of condensates and impurities will necessitate conditioning of the gas prior to delivering the gas through a long transmission pipeline, such as the proposed pipeline from the North Slope. By contrast, the “dry gas” typically found in the Cook Inlet region of Southcentral Alaska consists of almost pure methane and requires relatively little processing before transmission to market.
Proposals for a North Slope gas line envisage the construction of a massive gas treatment plant at the northern end of the line to remove the impurities from the gas, prior to gas transmission to markets outside of Alaska.
Two conditioning stages Craig said that there would likely be two conditioning stages for the North Slope gas. The first stage, at the field facility, would involve the separation of condensates and the removal of water that comes to the surface as vapor. The gas would be pressurized for shipment by feeder pipeline to the main gas treatment plant; the condensates could be re-injected into a high-pressure (or “dense phase”) gas pipeline for transport.
The second stage of conditioning, at the main treatment plant, would remove the major impurities such as carbon dioxide. Carbon dioxide would probably prove useful as an oilfield injectant for enhanced oil recovery. Other impurities would be more problematic and would probably have to be disposed of into a shallow reservoir.
“The conditioning plant would have to take all the different compositions of gas from all the different fields and condition it into one very narrow range of specs, to go through the long (export transmission) pipeline,” Craig said.
Craig said that gas gathering lines from remote gas fields would probably be buried, as distinct from oil lines, which tend to run above ground on vertical supports. Gas flow is more efficiently regulated at lower temperatures: the ground in northern Alaska would form a natural refrigerator.
Treatment of foothills gas The need for a gas treatment plant will likely raise an interesting question for a company developing a gas field in the Brooks Range foothills, a region well to the south of the central North Slope. The foothills region, where companies such as Anadarko Petroleum own oil and gas leases, is thought to be gas prone. Would it be economic to pipe unconditioned foothills gas to the main treatment plant in the central North Slope? Or would it make more sense to treat the gas locally and then pipe the treated gas the shorter distance east to enter the North Slope gas line near pump station 2 of the trans-Alaska oil pipeline?
Assuming that the regulations for the operation of the North Slope line allow gas to be injected part way down the line, the answer to this question will in part depend on the relative cost of a foothills treatment plant vs. constructing a longer feeder pipeline. But one important issue for a foothills treatment plant would be the disposal of the gas impurities — there may be no ready market for carbon dioxide produced in the foothills area, Craig said. All of the scenarios developed so far have assumed that the untreated gas would go back to a central area near the trans-Alaska pipeline pump station 1, he said.
Offshore gas fields What about a gas field offshore, say in the Beaufort Sea?
Gas does have one major advantage over oil in an offshore environment, in that it can be moved a long distance through a pipeline without first having to treat the production slurry. Shipping untreated oil, on the other hand, involves the flow of liquid (oil and water) and gaseous phases. And that raises pipeline corrosion issues and problems with flow efficiency.
Designs for new Norwegian offshore gas fields involve bringing untreated gas back perhaps 90 miles to onshore conditioning plants, Craig said.
“You can’t take unconditioned oil more than 20 to 25 miles without some risk of flow problems,” Craig said.
However, for distant offshore gas fields it would be necessary to use alcohol (or some other dehydrating agent) to stabilize water in gas from the wellheads. This would minimize problems of gas hydrates forming in the gas line and thus blocking the flow of gas. And, although the use of subsea well completions would be a likely design concept for an offshore gas field, a field very distant from shore (perhaps over 100 miles) might require a hub platform.
Associated gas Because northern Alaska natural gas tends to be “thermogenic,” the gas is often associated with oil. That association could raise issues for a company wanting to produce the gas — oil is a more valuable product than gas and, for resource conservation reasons, usually needs to be produced before the associated gas. Thus, even a relatively modest amount of oil found in conjunction with a gas pool could delay gas production for several years, until all of the viable oil has been produced, Craig said.
The relatively low value of gas compared to oil also raises questions about the viability of gas field development, especially given the fact that the cost of a gas field development may not be too different from the cost of an oil field. And that problem becomes compounded if a gas field lies a long way from the infrastructure for delivering the gas to market.
“So there may be a high gas resource potential in northern Alaska, but I think many people have lost sight of the higher costs to develop remote gas fields,” Craig said. “… That’s a real risk factor for the pipeline economics, when the last half of your production has to come from these remote expensive fields.”
And the long lead time to construct a North Slope gas line seems to pose some issues in relation to the typical 10-year duration of North Slope oil and gas leases — it might be 10 years before a gas line is completed and another 10 years before capacity becomes available on the line, Craig said.
On the other hand natural gas is, on the whole, easier to produce than oil and does not involve any risk of an oil spill. But the question of whether a gas field in northern Alaska could be developed more quickly than an oil field remains to be seen.
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