2020s Prudhoe gas sales could be well timed

As North Slope field ages, gas reinjection will be losing part of oomph some 50 years after Prudhoe oil production began in 1977

Bill White

Researcher/writer for the Office of the Federal Coordinator

Why pressure matters

It’s wrong to picture oil in a reservoir as a vast underground lake waiting to be siphoned dry.

Rather, oil and gas lie in tiny pores of certain kinds of porous rock, such as sandstone and conglomerate at Prudhoe. And they move to wells via minute connected pathways in the rock, resembling something like a map of the human nervous system.

Simply put, oil pushes through those pathways and rises to the surface because the pressure inside the wellbore is less that the reservoir pressure.

As oil leaves the reservoir, the remaining reservoir contents become less compact; what’s left sort of relaxes. If the pressure falls too much, oil production stops.

The reservoir will offset some of this pressure decline automatically, the text “Fundamentals of Petroleum” notes.

For example, the rock itself will expand - ever so slightly.

Water and oil still in the reservoir will expand a bit more than the rock.

Some gas dissolved in the oil - called “solution gas” - will bubble out of the oil as the pressure falls, just as carbon dioxide bubbles free when a soda bottle is first opened and the pressure is reduced.

Finally, expanding the most is a layer of mostly natural gas that lies above the oil - a layer called the gas cap.

Of Prudhoe Bay’s original 26 trillion cubic feet of gas, 18 trillion was in the gas cap. The other 8 trillion was in solution. The gas cap also held some oil, as we will see.

But these natural changes in pressure have their limits and do not offset all of the pressure loss that occurs as oil leaves the reservoir.

Prudhoe Bay’s original reservoir pressure was 4,335 psi (pounds per square inch). Today it’s about 3,300 to 3,400.

Less pressure means less oil production. This is true for several reasons:

As pressure drops, more of the hydrocarbons dissolved in the oil will fizz out and become vaporous rather than the liquids they were under higher pressure. The industry term is “oil shrinkage.” That’s just the nature of their chemistry - a change in temperature or pressure can transform a hydrocarbon from a liquid to vapor, or vice versa.

As pressure drops the oil becomes thicker, or more viscous, without those lighter hydrocarbons that have fizzed out. The more viscous the crude, the less of it that flows to wells.

Without the lighter hydrocarbons, less NGLs are produced for the oil pipeline. Also, less are produced to make miscible injectant, so less of that cocktail is available to produce stubborn, clinging oil from the reservoir.

Pressure is to Prudhoe what gravity is to rainfall. It is a dynamic behind most strategies that produce Prudhoe’s oil.

Falling pressure

This has occurred even as billions of barrels of liquids have been extracted and sent to market.

The reason is due to ingenuity and engineering muscle, as well as billions of dollars, the Prudhoe producers have invested over the decades to manipulate what happens in Prudhoe’s nearly 600-foot-thick oil-and-gas zone.

As was said, Prudhoe Bay’s original reservoir pressure was 4,335 psi, about 30 percent higher than today’s pressure.

When oil production began in 1977, the pressure started falling about 70 psi a year.

After massive water and gas injection began in the mid-1980s, the pressure decline slowed, falling about 25 to 35 psi a year.

The Prudhoe reservoir - in 3-D - looks sort of like a messy sandwich made by a 2-year-old, with the top and bottom bread slices only partly covering the filling. Prudhoe’s gas cap overlies only the northeast part of the oil column. The water underlies much of the rest of the oil column.

Between them, the injected water and gas act like a pincer, squeezing the oil column from above (gas) and below (water). The miscible injectant works with the water: The water flushes oil (and helps pressure the field), then miscible injectant loosens the remaining oil, and finally more water flushes the now loosened oil.

The miscible and gas injections were enlarged after a series of major plant expansions in the 1990s. But although they dealt with growing gas production and produced more oil, Prudhoe’s pressure continued to drop 25 to 35 psi a year, as expected.

Officials with the Alaska Oil and Gas Conservation Commission were concerned about the falling pressure. They are charged with regulating Prudhoe and other fields to ensure as much oil and gas as possible are produced.

In 1992, the commissioners instructed the Prudhoe producers to investigate options to slow the pressure drop further and report annually.

The producers already had formed teams to take on the problem.

Old idea, new life

•Obtaining natural gas from another field, such as from Point Thomson, for injection at Prudhoe.

•Injecting a natural gas substitute, such as nitrogen.

•Burning something other than natural gas to fuel the oil field so that more gas would be available for reinjection.

•Ramping up water injection.

Imposing any new program is a tricky business when melding it with a whole program of expensive strategies that already work at Prudhoe.

As two ARCO engineers wrote in a paper, “Reservoir Management of the Prudhoe Bay Field,” presented at a 1997 Society of Petroleum Engineers technical conference (ARCO Alaska helped develop Prudhoe and is a predecessor company of ConocoPhillips):

“Progressive development of a fine-tuned, highly integrated facility reservoir system steadily increased the complexity of evaluating new projects that would potentially disturb an existing balance.”

By 2001, the Prudhoe producers had their solution to the reservoir’s falling pressure.

They would inject massive amounts of water - not into the reservoir periphery where water injections already occurred, but into the top ... into the gas cap.

The idea - called simply “gas cap water injection” - wasn’t new within the industry. In the early 1970s, when the companies were mulling how to develop Prudhoe, it was even plugged into a reservoir simulator model for the field, an ExxonMobil engineer, Lynn Schnell, told the AOGCC in 2001.

The injection began in 2002. The producers pump about 520,000 barrels a day of seawater into the eastern part of the gas cap. They inject that water as far away as possible - more than two miles - from the nearest oil wells and natural gas injection wells. The injected water front is slowly pushing westward toward these wells.

Sometime in the mid-2020s, the injection will end. The water front basically will stop migrating, according to a 2001 AOGCC conservation order about the program.

The front will have reached the northern oil-producing wells in what is known as Prudhoe’s “gravity drainage area” - think of that area as the mother lode. The gas-cap’s methane will be compressed into a tighter, mostly water-free space over the gravity drainage area. The field will be primed to start drawing off some of the gas.

The 2002 gas cap water injection program did more than “mitigate pressure decline.” It stopped the decline.

Prudhoe’s pressure has stabilized at not quite 3,400 psi. In fact, Prudhoe is now gaining 1 to 2 psi of pressure a year.

The program’s other goal is to produce more oil.

The seawater injection is on target to produce an extra 170 million to 200 million barrels of hydrocarbon liquids from Prudhoe, the industry says.

“The increased pressure resulting from GCWI [gas cap water injection] improves every (oil) recovery mechanism operating in the field,” Bharat Jhaveri, a reservoir engineer with BP, told the AOGCC in 2001.

Target: relict oil

The gas-cycling “vaporization” of hydrocarbon liquids won’t have much life left either. Most of the vaporization possible will have occurred in the preceding 50 years.

Vaporization has targeted two kinds of hydrocarbons in particular.

One is called “relict oil.” This is the oil in the gas cap that never drained down into the oil column when oil and gas were separating over millions of years. BP, which runs the Prudhoe field, likens relict oil to “the final amount of ketchup in an upturned bottle” that no longer flows.

Prudhoe’s gas cap originally had a lot of relict oil, about 1 billion barrels.

The other key vaporization target has been about 3 billion barrels of residual oil, condensate and other hydrocarbon liquids left behind as oil is produced, the oil column shrinks and the gas cap expands. Some of these are hydrocarbons that fizzed out of oil as the reservoir pressure fell.

Unlike the gas coming up the wells with oil, the reinjected gas going back into the reservoir has been stripped of its hydrocarbon liquids. That is done by chilling the produced gas in a giant plant. Remember, temperature changes will cause some vapors to become liquid, and these natural gas liquids that drop out of the produced methane are sent to market via the trans-Alaska oil pipeline or made into miscible injectant. What’s left, the bulk of the gas stream, is what the industry calls “dry” or “lean” gas, mostly methane - the same gas that burns in home furnaces.

This injected lean gas now has capacity to absorb more hydrocarbon liquids as it passes over them in the reservoir. Rinse and repeat.

The same principle is at work when a damp towel hung on a Phoenix clothesline at 100 degrees dries faster than at the same temperature in humid Houston - the dry desert air has more capacity to absorb the towel’s moisture.

Prudhoe’s gas cap has been expanding - and the oil column shrinking - since 1977. By the mid-2020s, the gas cycling will have touched most of the relict and residual oil. In fact, most already has been produced. This can be seen in Prudhoe’s NGL production. Although the flow of natural gas up wells has been relatively steady since NGL production peaked in 1997, the volume of NGLs extracted from that gas stream and sent to the oil pipeline has fallen about 50 percent since then because there are less and less NGLs to capture.

The cost of gas sales

Gas not piped south to the LNG plant would be handled as it is today: some would power the fields, some gas liquids would go to market or be made into miscible injectant, most of the produced gas would be reinjected for gas cycling.

Pressure in the Prudhoe reservoir would start falling.

That would mean some hydrocarbon liquids would get left behind because of oil shrinkage, more viscosity, less miscible production and less vaporization.

How much less is unclear from the public record.

What is clear is that had major gas sales begun earlier, Prudhoe would have produced much less oil.

Cathy Foerster, a petroleum engineer and current state oil and gas commissioner, has said that if the gas pipeline proposed for the early 1980s had started, it’s possible that Alaska’s North Slope would be finished today as an oil realm, instead of having perhaps decades of production left.

In 1991, Lod Cook, then chief executive of ARCO, told the U.S. secretary of energy in a letter that, “If major gas sales of two billion cubic feet per day were to begin late in this decade, the loss of recoverable crude oil would be about one billion barrels. If such sales were delayed until 2005, the loss still would be about one-half billion barrels. In short, early sale of gas from the North Slope will substantially reduce the amount of available domestic oil from the Prudhoe Bay Field.”

In 2009, a National Energy Technology Laboratory report considered oil loss due to a contemplated 3.44 bcf-a-day gas pipeline starting in 2018. The study predicted 234 million barrels lost from Prudhoe over time, offset by 400 million barrels of new oil and condensate production from the Point Thomson field, which would be developed to tap its gas for a gas pipeline.

The trade-off of some lost oil production due to significant gas sales will be studied in coming years by the Prudhoe producers and Alaska Oil and Gas Conservation Commission regulators.

Ultimately, the commissioners, charged with maximizing the recovery of Alaska’s resources, will decide whether the approach to managing Prudhoe is ready to pivot, whether it’s time for major gas sales.

Certain to be part of their calculation will be the fading effectiveness of some long-used strategies for producing the famous field’s oil.

Editor’s note: Part 1 of this story appeared in the Feb. 15 issue of Petroleum News. This is a reprint from the Office of the Federal Coordinator, Alaska Natural Gas Transportation Projects, online at www.arcticgas.gov/prudhoe-gas-sales-2020s-could-be-timed-well-aging-oil-field.