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January 2008

Vol. 13, No. 4 Week of January 27, 2008

AOGCC doesn’t foresee oil loss at Prudhoe

Senate Resources hears that with aggressive production prior to a major gas sale, there should be minimal impact on oil

Kristen Nelson

Petroleum News

Gas: It’s the crown prince of the Prudhoe Bay field.

At some point there will be a gas pipeline and that gas will be sold.

Right now “Prince Gas” plays an important role, along with water, in support of “King Oil.” Gas is reinjected to maintain pressure, used in enhanced oil recovery and burned to fuel oil recovery. Natural gas liquids stripped from the gas are sold down the trans-Alaska oil pipeline, increasing the volume of liquids.

Once gas sales begin, what will happen to the remaining oil at Prudhoe?

Commissioner Cathy Foerster of the Alaska Oil and Gas Conservation Commission, one of the state agencies responsible for oversight of oil and gas, told the Senate Resources Committee Jan. 18 that two of the commission’s missions, preventing hydrocarbon waste and encouraging ultimate hydrocarbon recovery, come into play in gas discussions.

Foerster told the committee AOGCC is working “to help prepare the state for the eventual sale of our North Slope gas resource.”

Some oil loss will occur

“There will likely be oil losses in any gas-sale scenario,” Forester said. The smaller the volume of gas sold the less the oil loss will be, she said. The later the gas is sold, the less the oil loss will be — which also ties into how aggressively BP produces the oil between now and a gas sale.

On a conversion basis of 6,000 cubic feet of gas to one barrel of oil, with 24 trillion cubic feet of gas in the Prudhoe gas cap “there are 4 billion barrels of oil equivalent in that gas cap.” The remaining recoverable oil is just shy of 2 billion barrels. Whatever the remaining producible oil is when gas sales begin, “when we sell the gas we will not lose all of the remaining oil; rather, we’ll lose a fraction of it,” she said.

“We will want to sell whatever volume is needed from Prudhoe Bay; and we want to sell it whenever it is needed to ensure that the gas line is a go,” Foerster said, assuming “that the Prudhoe Bay operator aggressively produces as much oil and puts in place as much mitigation for losses as possible before the gas sales begin.”

She said BP is aggressively producing the oil by using horizontal, extended-reach multilateral drilling to reach oil from old wellbores that have produced what they can; by injecting water into the gas cap; and by EOR. BP has been testing injecting water into the gas cap and is expanding it based on results of the study.

Assuming BP continues to accelerate oil production, avoids “major unplanned shutdowns” and develops and implements “strategies to mitigate oil losses” then “by the time we get a gas line, the oil volumes left at risk at Prudhoe Bay … will not be sufficient to derail a gas pipeline,” she said.

Gas in use at Prudhoe

Prudhoe Bay gas is estimated at about 24 tcf. Currently that gas, produced along with the oil, is reinjected to maintain the reservoir pressure. Before it is reinjected, natural gas liquids are stripped out of the gas and a portion of the NGLs are blended with the oil and shipped down the trans-Alaska oil pipeline.

Foerster said the sale of NGLs “has already yielded about half a billion barrels of oil sold.”

In addition to maintaining reservoir pressure, reinjected gas also strips oil out of the gas cap through “a process called vaporization” which will yield about 2 billion barrels of the total 13 billion barrels expected to be recovered from Prudhoe Bay, she said.

About a third of a billion cubic feet of gas per day is mixed with NGLs and reinjected for enhanced oil recovery. “EOR is yielding an additional one-half billion barrels of oil from Prudhoe Bay and its satellites,” Foerster said.

Gas and NGLs are also exported to other North Slope fields, so Prudhoe Bay gas is contributing to “greater ultimate recovery of oil in other North Slope fields.”

Less than half a billion cubic feet of gas a day are used for fuel.

Some 7 bcf to 8 bcf a day of gas is produced in the oil, along with water, which is also reinjected to maintain reservoir pressure.

“So that oil rim that’s in the middle is being squeezed from below and above — below by the water and above by the gas — to keep the pressure high enough so that the oil can continue to flow,” Foerster said.

Initial estimate 9 billion barrels

In 1977, at the beginning of production, it was expected that Prudhoe Bay would produce 9 billion barrels, about 7 billion from primary recovery, another billion from waterflood and another billion from gas cycling.

Today the expectation is 13 billion barrels.

The reservoir didn’t grow, Foerster said, but the field’s owners made investments and there have been technological advances.

In most reservoirs if you just drill the wells and open the valves ultimate production will be 20-25 percent, she said. At Prudhoe ultimate recovery is expected to be close to 60 percent.

While there will continue to be improvements in technology, Foerster said she didn’t expect recovery to go much above 13 billion barrels because “the low-hanging fruits have all been plucked.”

Water is the largest volume of what’s currently produced. Foerster said when she worked at ARCO they called Prudhoe a water field. “It used to be an oil field, but now it’s a water field because you’re producing more water than you are oil.”

With a given size of facilities, and less oil, you hear people say that there should be room to process other people’s oil, Foerster said.

“The facilities are full. They’ve always been full and they probably always will be full,” she said.

“But at the onset they were full of oil and now they’re full of oil, water and gas.”

Processing costs are the same whether you’re processing oil or water — “and it costs the same to pull it out of the ground,” she said. You just make less money because you’re not selling the water, only the oil, but have to process everything.

When to sell gas?

As to when that gas should be sold, Foerster said that since Prudhoe Bay gas is being used to maintain pressure, “the later we start to sell the gas, and the more aggressively BP (the Prudhoe Bay field operator) has been in producing the oil in the meantime, the less oil will be left in the reservoir at risk of being lost to decreased pressure or other reservoir mechanisms associated with selling the gas.”

She said the commission also wants to see EOR projects at Prudhoe Bay and other North Slope fields continue “as long as they’re yielding increased oil recovery.”

Even after gas sales begin, “we can still use some of the available gas for EOR,” Foerster said, because carbon dioxide will have to be stripped out of the gas and the CO2 “can and should” be used for EOR.

Fuel usage at Prudhoe Bay is about 460 million cubic feet a day, Foerster said, the equivalent of about 77,000 barrels a day of oil. That 77,000 barrels of oil equivalent, she said, “is being used to produce about 395,000 barrels of oil” per day, so “every equivalent barrel of fuel is used to produce more than five barrels of oil.”

She said fuel usage at Prudhoe Bay might be worth continuing even when Prudhoe oil produced dropped below the level of fuel required to produce that oil because of the role Prudhoe plays in supporting its satellites and other fields on the North Slope.

The biggest use of fuel gas is running the gas compressors used to reinject gas and pumps to put water back into the reservoir, both to maintain reservoir pressure, she said.

The commission’s role

The commission sets gas offtake rules for producing fields.

The rate for Prudhoe Bay was set in 1977 at 2.7 billion cubic feet a day.

When there is a gas line, if the Prudhoe Bay operator wants a gas offtake greater than 2.7 bcf a day, it will have to request a change to the existing rule, Foerster said.

“However, if when we get a gas pipeline, 2.7 bcf a day of offtake — including fuel and export to other fields — is sufficient for Prudhoe Bay, then the Prudhoe Bay operator will not have to come back to us for permission to do anything at Prudhoe Bay.”

Because Point Thomson is an undeveloped pool there are no rules in place and “a gas offtake allowable rule would be part of the greater process of determining all the rules by which the pool would be developed,” she said.

Point Thomson — cycling an issue

While Prudhoe Bay is in production and the commission has done a reservoir study, Point Thomson is not in production and the commission has not done a study on that reservoir, Forester said.

Point Thomson is commonly referred to as a gas field she said: “But in engineering vernacular it’s what we call a gas condensate reservoir or a retrograde condensate reservoir.

“And under the definitions in the AOGCC regulations, it’s an oil field.”

Looking at technical issues — “not getting into financial concerns or politics” — cycling the gas and removing the liquids before selling the gas is “always, always the way to achieve greater ultimate recovery and prevention of waste from a gas condensate reservoir,” Forester said.

All of the fluids “are in a gaseous phase” in a gas condensate reservoir and when you lower the pressure—as by flowing the gas to the surface—“the oil falls out and that oil falls out in the reservoir and some of it as the gas is produced will fall out in the wellbore and in the production facilities, so as pressure drops in a gas condensate reservoir, oil drops out.”

The oil that drops out in the reservoir as the pressure drops “doesn’t come to the surface; it stays in the reservoir forever,” she said.

“And it tends to drop out where the pressure is the lowest. And where the pressure is the lowest is right next to the wellbore.” Forester said the oil falls out in pore spaces next to the wellbore, plugging up the pore spaces and making it difficult for the gas to move to the wellbore.

In cycling, the gas is brought to the surface, run through a gas plant, the liquids are stripped out and the gas is pressured and reinjected into the reservoir, keeping the pressure high enough in the reservoir that the oil doesn’t drop out.

Losses of both liquids, gas

Estimates of recoverable liquid hydrocarbons at Point Thomson range from 200 million to 400 million barrels, Forester said. While you could look at that as a small loss to get 8 tcf of gas, Foerster said “we have time, right now, to be developing Point Thomson, cycling the gas and recovering those liquids,” allowing recovery of the liquids now and gas once a gas pipeline is in place.

The state, under the terms of its net production tax, also has a financial stake in how Point Thomson is developed, Foerster said. Work “will likely need to be done over and over again to move that liquid out of the way and enable those gas wells to keep producing. So if we’re a partner in those operating costs and we’re doing something that causes liquids to drop out around the wellbore, then every time that the operator goes back in and spends money to move that liquid out of the way so the gas can keep coming, we’ll be paying.”

Either choice will involve costs, Forester said. Cycling — producing the liquids first and reinjecting the gas — “will likely add significant capital costs (to Point Thomson development) which the state would again share” under its net production tax. Because of the high pressure in the Point Thomson reservoir, “you’d have to pressure the gas up to about 10,000 pounds to get it down into the reservoir. … And that’s why it’s expensive.”

ExxonMobil, the Point Thomson operator, initially proposed gas cycling, but most recently has said it wouldn’t cycle. The commission has begun a Point Thomson reservoir study and Forester said at the conclusion of that study the commission expects “to know enough about Point Thomson to decide whether or not we agree with” ExxonMobil’s position that the gas shouldn’t be cycled.

Right now there is time to develop Point Thomson with a gas cycling project which would produce the oil and recycle the gas. “But the longer Point Thomson remains undeveloped the less time we will have,” she said.

The oil pipeline from Badami could be extended to Point Thomson, but infrastructure for drilling and production has to be put in place at Point Thomson and then the wells have to be drilled. Because the reservoir pressure is so high, the wells will be expensive, she said.

Economics need to be considered

Foerster said she doesn’t know the economics at Point Thomson.

“I don’t know that there’s a profit to be made on the oil; all I know is that the physics say that the only way to get the majority of that oil is to cycle.”

The economics at Point Thomson “will have to be considered” and the commission will consider economics “to the extent that our statutes allow us to consider economics,” Forester said. AOGCC has asked for a legal opinion through the Attorney General’s office “on how we can consider economics in our mission” because AOGCC’s statutes do not mention costs. “Money’s not part of what we do — but for realistic recovery we’re going to have to be able to know to what degree we can look at economics,” Forester said.






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