Providing coverage of Alaska and northern Canada's oil and gas industry
August 2007

Vol. 12, No. 33 Week of August 19, 2007

Engineering ingenuity returns big payoff

Prudhoe Bay teams develop enhanced oil recovery techniques over three decades that succeed beyond their wildest dreams

Rose Ragsdale

For Petroleum News

Getting more oil out of the ground is a technical challenge that teams of engineers tackled from Day 1 on the North Slope.

More than 30 years later, the brainstorming that produced and perfected a series of remarkable techniques goes on.

But the story of enhanced oil recovery on the slope is a tale not only of creativity but also of converting big problems into bigger solutions.

In the early days of production at the giant Prudhoe Bay field, enhanced oil recovery was a relatively routine exercise. With an estimated 23 billion barrels of crude in place, the gleeful owner companies were awash in oil. Starting with what in hindsight seems a modest field development plan — 500 wells with 160-acre spacing — to produce 9.6 billion barrels of oil, they crafted a strategy that relied on conventional EOR technology used in oil fields since the 1940s.

Crude production would be helped along with supplementary water injection to keep up pressure in the reservoir. The Prudhoe Bay owners built a seawater treatment plant to help supply water for the process, and added produced water and gas liquids from the depths of the reservoir as volumes became available.

But advances in EOR technology, and a suddenly plentiful resource enabled engineers to boost crude recovery dramatically. Today, Prudhoe Bay’s owner companies have drilled more than 1,300 wells, and plan hundreds more.

“At that time, it was envisioned that we would have a gas pipeline built within five years to ship North Slope gas to market,” said Gordon Pospisil, technology manager for BP Exploration (Alaska) Inc., Prudhoe Bay’s current operator.

“When the world did not provide an opportunity to sell gas off the North Slope, it changed our world quite a bit,” he said.

So much natural gas

Suddenly, Prudhoe Bay engineers found themselves coping with ever increasing quantities of natural gas coming out of the ground with the oil and no place to put it.

They began to pump substantial quantities of gas back into the reservoir along with the water, and soon built a series of gas handling facilities — GH1, GH2 and GH3 — completed in the late 1980s and early 1990s.

As more Arctic fields were discovered and developed, operators also jumped at the chance to boost production from these smaller reservoirs with injections of plentiful gas from Prudhoe. Point McIntyre, Milne Point, Endicott and Kuparuk are all fields that drew on the gas riches at Prudhoe Bay to enhance oil recovery.

Along with the multimillion-dollar projects that made this possible, field owners invested in a huge central gas facility to cool gas to temperatures as low as minus 40 degrees Fahrenheit. The unit processes more than 8 billion cubic feet of gas daily, enough to meet all of the natural gas demand of London or Tokyo.

NGLs make a difference

The CGF also allows operators to separate out heavier gas components as natural gas liquids, while the remainder of the gas is injected back into the reservoir.

The process, which works best in colder temperatures, not only allows the owners to boost field production; it also contributes output in NGLs of about 50,000 barrels per day.

“If we hadn’t had the Central Gas Facility, the NGLs would still be a part of the gas reserves on the North Slope,” observed Pospisil.

Over the years, the small increments of NGLs have added up, said BP spokesman Daren Beaudo.

“Nobody’s been sitting on that gas, or warehousing it. It’s been working mightily for us,” he said.

Total NGLs output over 20 years at Prudhoe Bay? More than 500 million barrels.

A real EOR winner

Engineering teams, meanwhile, set to work perfecting another known technology for use on the North Slope. Taking other portions of the gas stream, they blended gas and methane gas to create miscible injectant, or MI, a special solution designed for sweeping oil from underground reservoirs.

“Think in terms of salad dressing,” said Pospisil. “If you just inject water, the water and the oil have a sharp interfacial tension, and the water tends to bypass the oil. If you inject gas, miscible gas in particular, the solution helps to sweep residual oil out more efficiently to the producers.”

Working closely, reservoir, production and drilling engineers, came up with the concept through trial and error of drilling fishhook-shaped wells around oil-producing wells in a certain pattern.

“We would inject that fishhook-shaped well with a ‘bulb’ of MI, and we would get a response from the nearby production well. We would see these cycles of increased oil production, so we kept on injecting bulbs of MI along the entire length of the well,” Pospisil recalled. “This dramatically increased the amount of oil we could get out.”

A bulb is a quantity of miscible injectant that forms a bubble within the reservoir. As it expands, the bubble pushes oil toward production wells.

Making a good idea great

But Prudhoe Bay engineers didn’t stop there. They continued to experiment and soon took the MI process a step further. They created something they call miscible injectant sidetrack, or MIST.

MIST is a system of wells drilled between injector and producer wells in a pattern that further boosts crude output from a field.

By 1996, slope engineering teams were ready to launch an aggressive third phase of EOR at Prudhoe Bay and other North Slope fields using MIST. It involved integrating the drilling of production and injection wells to improve oil recovery. At Prudhoe, they started at the central core of the field and moved toward the western part of the field to Northwest Eileen and continued until the system encompassed Prudhoe Bay satellite fields, Aurora, Borealis and Polaris.

“In each one of those satellites (small fields with 40 million to 200 million barrels of crude in place) in the early days, it would have been difficult to justify doing an MI process. But they are part of the Greater Prudhoe Bay complex, so we were able to use MI,” Pospisil said. “We’re also doing that in the Point McIntyre reservoir.”

The producers also are in the early stages of using MI in developing shallower viscous and heavy oil deposits at Orion and Polaris in the Schrader Bluff interval of the western Prudhoe Bay area.

Innovations keep coming

In each new application, the engineers and geologists monitor the process and continue to develop new ideas for improvements.

“We have periodic meetings around each field to brainstorm ideas for pushing EOR to the technical limits,” Pospisil said. “Then we pick through these ideas for the gems as opposed to the clunkers.”

A review of Society of Petroleum Engineer archives turned up more than 300 technical papers written on EOR ideas for Prudhoe Bay, according to Pospisil.

From this continuous brainstorming, three more promising EOR ideas have emerged recently.

The first is “Bright Water,” a system of injecting a polymer down hole that reduces the viscosity of oil and causes water pouring into the reservoir to avoid areas with high permeability and go where the remaining oil is located.

“We hope to implement Bright Water on a wide scale if we can demonstrate further success in some of the trials. We’re still investigating it as part of (BP’s) worldwide technology effort,” Pospisil said.

Another new EOR possibility is low salinity, or Lo Sal, waterflooding. In trials currently under way at Endicott, BP engineers are injecting water into the reservoir that has less salt than that typically used to boost oil production.

“In waterflooding at Prudhoe Bay, we initially used seawater, and then produced water,” Pospisil said. “But we found that with low salinity water, we’re more effective in moving oil off the water.”

The situation is analogous to washing dishes in seawater or very hard water, he said. Removing grease from the dishes is much harder to do than it would be in soft water or H2O with less salt.

“Using low salinity water, we’ve seen significant increases in crude recovery, more than 20 percent increases in tests,” Pospisil said.

BP is currently testing the use of reverse osmosis to remove salt from seawater and researching the feasibility of building a large-scale water injection plant on the North Slope.

The company also has secured a rare patent for the Lo Sal technology. Typically, BP works with vendors who patent new technologies.

“It’s a potentially ground-breaking technology that BP is spearheading in Alaska for worldwide application,” said John Denis, BP’s resource manager for North Slope fields other than Prudhoe Bay.

“The company is trying to prove the technology at Endicott and Milne Point” for use in existing fields like Prudhoe Bay and in new fields under development such as BP’s Liberty prospect, Denis said.

“Liberty will come on stream about the time that the Lo Sal technology is fully mature,” he added.

If the tests are successful, North Slope producers also plan to put Lo Sal technology to work at Prudhoe Bay and the satellite fields.

“Within Prudhoe Bay, we’ve recovered 11.5 million barrels of crude, or about half of the 23 billion barrels in place. That leaves a very large target remaining,” Pospisil said.

Win-win EOR with CO2?

Prudhoe Bay’s owner companies are also investigating the use of carbon dioxide as an EOR agent. Trillions of cubic feet of gas reserves in the field have a CO2 content of about 12 percent. CO2 is considered a greenhouse gas that is harmful to the environment.

Currently, the CO2 is produced along with gas and re-injected into the reservoir where some of it is permanently trapped.

When Alaska succeeds in building a gas pipeline system to market North Slope reserves, the producers will need to separate and dispose of the potentially harmful CO2. Or they can come up with a way to reuse it, said Pospisil.

Of the estimated 33 trillion cubic feet of gas reserves at Prudhoe Bay, some 4 trillion cubic feet is CO2. The field would produce about 400 million cubic feet per day of CO2 once gas sales begin, he said.

“We could re-inject it, but a better option would be to direct it to other fields where it could be a part of viscous or heavy oil recovery,” Beaudo said.

CO2, however, presents a considerable challenge; it is highly corrosive, Pospisil added.

Doing it right

Charles Thomas, Ph.D., a U.S. Department of Energy representative who has participated in a number of enhanced oil recovery studies, praised EOR efforts on the North Slope.

“Prudhoe Bay got into gas and water injection — it started very early (in the field’s life), which was the right thing to do,” he said. “As technology came along, it was either applied or developed at Prudhoe Bay, where it was all put together in a very intelligent way.”

Thomas said EOR enabled producers to boost recovery estimates of crude from Prudhoe Bay from about 9 billion barrels at the start of Prudhoe Bay’s development to 10.2 billion in 1986, and to more than 14 billion barrels today.

Miscible injectant projects at Kuparuk also have helped to increase production at that field, which is the second-largest in North America and also contains heavy oil, he said.

Exploring newer frontiers

Continued slope research is focused on the heavy oil, Thomas said.

“Outside of finding new fields, we’re looking at enhanced oil recovery in heavy oils, which is a major target of about 25 to 30 billion barrels of oil,” Pospisil said.

Recovering 3 billion to 5 billion barrels of this crude would be quite a prize, the owners say.

Biotechnology and nanotechnology offer new promise for the future, according to Tony Meggs, BP group vice president for technology. On the biotech side, researchers want to produce a microorganism that will gobble up all residual oil in the reservoir and return it to the surface. Nanotechnology also could produce new EOR materials, he said.

Continuing the flow of crude through the trans-Alaska oil pipeline is crucial to Alaska’s oil industry. Thanks to advances in EOR technology, the producers stand a good chance of keeping the oil flowing for many years to come and doing it without significantly increasing its footprint in the Arctic.

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