Moving the goal post at Prudhoe Bay

Advanced technologies continue to increase expectations for oil recovery; upgrades for future gas production may cost billions

Alan Bailey

Petroleum News

Evolving oilfield technologies have greatly extended the life of the giant, BP-operated Prudhoe Bay field on Alaska’s North Slope and are set to enable continued oil production from the field for decades to come, Mike Utsler, BP senior vice president for greater Prudhoe Bay, told Petroleum News June 9. Since it first went into production in 1977, the field has remained at the fulcrum of the North Slope oil industry, underpinning the viable operation of the trans-Alaska oil pipeline and, hence, viable production from other North Slope oil fields.

And Prudhoe Bay could also prove to be the fulcrum field for gas exports through a proposed North Slope gas line. That raises the question of converting Prudhoe Bay in part to a gas field, a conversion that would involve billions of dollars of cost in modifying the field facilities for joint oil and gas production, Utsler said.

“Many of these (existing field) facilities were built for light oil, not gas, production,” Utsler said. “So they were built with the purpose of separating oil, to sell oil to the pipeline, and to deal with gas and water as the byproducts to re-inject into the reservoir.”

The field facility modification costs would be additional to the cost of developing the export pipeline itself, and to the cost of the associated gas treatment plant, and would not be recoverable from the gas line tariff, Utsler said.

More oil

“Its original development plan called for drilling 900 wells, producing those wells to depletion over a period of 20 to 25 years, and then abandoning the field,” Utsler said. “We’re here 32 years later, still the largest producing oil field in North America.”

More than 2,500 wells have been drilled in the field, and cumulative oil production already greatly exceeds the originally estimated 9 billion to 10 billion barrels.

“We envision a field with more than 50 years of future. … We’ve just produced 12 billion barrels and expect that we will recover with current technology 2 billion to 3 billion more barrels,” Utsler said.

And although over the years the field facilities have been upgraded and expanded, the field remains largely built off 1960s and 1970s technologies.

“It in itself is a testament to the engineers and geoscientists, and many, many companies that were involved in the evolution and development of greater Prudhoe Bay,” Utsler said.

New technologies

One of the production boosting technologies is state-of-the-art seismic data acquisition, in which micro-electronics and increasingly powerful computers have enabled the production of ever-more detailed three-dimensional images of the subsurface by recording the echoes of sound waves generated by vibrators at the surface. Repetition of 3-D seismic surveys at periodic intervals gives rise to 4-D seismic data, data that help geoscientists and reservoir engineers to trace the flow of oil, water and gas through the field reservoir, thus enabling the tracking of pockets of oil and gas, pockets bypassed by earlier oil production but potential targets for future drilling.

“Most recently, this winter, we’ve just finished completing a very large seismic acquisition program across approximately 35 percent of the greater Prudhoe Bay field,” Utsler said. “This 3-D seismic also gives us limited 4-D seismic capability that is enabling us to continue to refine and enhance our abilities to image where the oil, the water and the gas in the reservoirs are.”

Drilling techniques

“Greater Prudhoe Bay in the ‘80s and ‘90s was the proving ground for coiled tubing drilling technology and the ability to drill horizontally from a vertical well bore … into the reservoir, to penetrate farther and farther away from that original well bore to access greater volumes of previously unrecovered hydrocarbons,” Utsler said.

The use of directional and horizontal drilling, using both coiled tubing and conventional drilling techniques, has enabled wells to maximize their contact with the reservoir. Multilateral wells, involving the drilling of several deviated wells at depth from a vertical well bore, enable several portions of a reservoir to be accessed from a single well bore, thus dramatically reducing drilling costs.

“Where a vertical well might cost in the neighborhood of $6 million on average … a multilateral off of that may cost us anywhere from $2.5 million to $3 million,” Utsler said.

In Prudhoe Bay in 2008 BP drilled a second hexalateral well involving six lateral wells from a single well bore.

“That’s an Alaska record and, we believe, a North American record,” Utsler said. “… We’re currently evaluating all the way up to a decalateral (with 10 laterals) over the next two to three years.”

BP also anticipates improving its overall drilling efficiency through the use of new rigs that Parker Drilling and Doyon Drilling are building for BP’s use on the North Slope. The first of those rigs, the Doyon rig, will be delivered in 2010, Utsler said.

Oil recovery

Waterflood, in which a mixture of produced water and seawater is injected into the bottom and sides of the reservoir, and in patterns within the reservoir, has proved for many years to be a key technique in flushing oil out of the subsurface rocks. However, as the water moves the oil into isolated locations within the field reservoir, the ability to thread a directionally drilled well through perhaps an 18-inch reservoir window three to four miles out from the well’s surface location has proved key to mopping up as much oil as possible.

A new trademarked Bright Water technique is now taking waterflood a step further than previously possible by using polymer chemicals within the water to control the path that the water takes through the subsurface rocks, blocking access to already-used paths of least resistance and diverting the water through untapped portions of the reservoir.

“As a proprietary process it’s extremely exciting,” Utsler said. “… We’re doing on average eight to 10 of this type of application per year now, in which we’re seeing very encouraging continued results and sustainable increased oil production.”

LoSal™, another proprietary technique for using water to flush oil out of a reservoir, involves the use of low-salinity water but is still under test in the Endicott field. If the tests prove successful, BP plans to deploy the technique in other fields.

“That’s also got a very exciting potential in greater Prudhoe Bay,” Utsler said.

Gas injection

And BP sees potential to use carbon dioxide, another enhanced oil recovery material that acts as a solvent, to further scrub the reservoir. The company is working with the University of Alaska Fairbanks to use actual well cores from Prudhoe Bay to laboratory test the potential effectiveness of carbon dioxide in the field reservoir rocks, Utsler said. Then, by feeding the laboratory results into BP’s computer-based field model, the company will be able to assess the impact of carbon dioxide on oil recovery, he said.

The use of carbon dioxide could boost Prudhoe Bay production by anywhere from 1 to 5 percent, with an increment of just 3 to 4 percent in recoverable oil resulting in an additional 1 billion barrels of production, Utsler said. However, even assuming that the carbon dioxide enhanced recovery works at Prudhoe Bay, the required operation would be expensive.

“It is a costly process because you first have to remove and capture the carbon dioxide,” Utsler said. “The carbon dioxide when mixed with water becomes very corrosive and so you have to redesign your facilities and the piping and the downhole to accommodate the (carbon dioxide) injection.”

On the other hand, a gas treatment plant at the upstream end of a North Slope gas line would have to remove carbon dioxide from gas to be exported from the slope, thus providing a ready source of the gas — natural gas from Prudhoe Bay has a carbon dioxide content of about 12 percent, Utsler said.

Viscous oil

In particular, state production tax deductable costs, fixed at 2006 cost levels plus 3 percent per year for inflation, limit tax benefits to whatever was in place in 2006, rather than applying to new developments, he said.

“In these challenging times of lower oil prices again, where every dollar is critical in terms of its value of investment return, we and our working interest owners are slowing our development of viscous oils, and slowing our development of heavy oils,” Utsler said. “… It was a $2 billion, 250 million-barrel (viscous) oil development in greater Prudhoe Bay, but those economics no longer justify the pace of development of that resource.”

However, BP is continuing its research into the development of heavy oil in the expectation that future rising oil prices and improved production technologies will eventually justify heavy oil production.

Infrastructure renewal

Upgrading of the pipeline infrastructure is already under way, using lessons gleaned from the 2006 transit line oil spill and recognizing that much of the existing pipeline system was designed to handle much larger oil throughputs than at present — pipelines with higher capacities than are needed tend to have slow fluid flow, with attendant heightened risks of solids deposition and corrosion.

“Greater Prudhoe Bay has over 1,600 miles of pipelines and a significant effort since 2006 has been put into evaluating, inspecting and understanding the long-term pipeline requirements,” Utsler said.

Right-sizing the critical pipelines will involve replacing some lines, upgrading others and abandoning some, he said.

The second step of field renewal, the upgrade of the automation, fire protection and current gas handling facilities, will recognize advances in electronic and computer technology that have happened since the field was built 30 years ago, advances that will enable improved operational efficiency.

“The systems are … safe and reliable to operate today, but much of the hardware is no longer made,” Utsler said. “Computer control panels that were the size of rooms can now be on a laptop.”

Facility upgrades

For example, supplying sufficient electrical power to operate new facilities, including a North Slope gas treatment plant, and to operate new enhanced oil recovery programs, would likely require the 39-year-old Prudhoe Bay power plant, the largest power plant in Alaska, to be replaced or redeveloped.

“That’s something we’re evaluating,” Utsler said. “Where will be the new sources of electricity to meet heavy oil needs, to meet the gas plant needs, and to meet the ever growing need of the infrastructure on the North Slope?”

But the question of whether gas will be exported from the Slope will drive a major decision point in long-term Prudhoe Bay field investment.

“Facilities consolidation, roads and pads consolidation, that type of longer-term renewal, really is dependent on what the future holds with regards to gas,” Utsler said. “… These would be massive investment levels, in the billions of dollars, that would be required … to develop both gas and oil handling for the next 50 years.”

And Utsler sees a bright future for the Prudhoe Bay field.

“Prudhoe Bay has been an amazing resource for the State of Alaska, for the United States of America and certainly for those of us who’ve had the privilege and the opportunity to work in, with and on Prudhoe Bay,” Utsler said. “It has an amazing future in front of it.”

The transition to gas at Prudhoe Bay

Re-injected gas is used to maintain the pressure in the Prudhoe Bay reservoir.

“The minute you take gas out of the reservoir you will be taking pressure out of the reservoir and, therefore, you will be accelerating the decline of light oil production, and viscous oil production potentially,” Utsler said.

It would be possible to partially offset the pressure decline by injecting carbon dioxide extracted from the produced gas in the gas treatment plant at the upstream end of the gas line, and by expanding water injection in the field.

However, these approaches would not fully compensate for the drop in gas injection, leaving the possibility of some otherwise recoverable oil remaining stranded in the reservoir. Enhanced oil recovery techniques might be used to tease this stranded oil from the ground, but BP also sees a program of accelerated drilling over the next 10 years, prior to the start of gas sales, as a potential means of maximizing ultimate oil recovery.

BP is using a sophisticated computer model of the Prudhoe Bay field, encapsulating data from 2,500 well penetrations and well core data from across the field, to analyze various oil and gas production scenarios, by testing how the field would respond to different fluid movements and pressure changes, Utsler said.

“We have built what is recognized as one of the world’s most sophisticated what are called full-field reservoir models,” he said.

—Alan Bailey

Managing lifting costs at Prudhoe Bay

The Prudhoe Bay field faces the same cost issue as any other aging oil field: As production declines, total field and oil transportation costs are spread across fewer barrels of oil, thus potentially increasing the per-barrel cost of “lifting” the oil and making the oil less profitable, with the oil ultimately becoming uneconomic to produce. The question inevitably becomes one of managing the costs without compromising safety or environmental protections.

The first key to managing lifting costs is to ensure the efficient use of people, Mike Utsler, BP senior vice president for greater Prudhoe Bay, told Petroleum News June 9.

“It’s really about how do we get the right number of people with the right skills applied doing the right work sequence, from a maintenance (standpoint), from an operations standpoint, from a small projects development (standpoint), in a continuous improvement cycle,” Utsler said.

A second key is the use of technologies such as state-of-the-art, high efficiency power generation turbines. And in the long term BP is looking into opportunities for process automation, he said.

Establishing partnership approaches between the field operator and the State of Alaska, and between the operator and the service industry, is also a key to cost management, Utsler said. Systems and processes need to be seamless and streamlined, even though managing a multiplicity of service providers can prove very complex. At the same time oil industry legislation and regulation bring operational costs: Safety and environmental protection need to be applied in an efficient manner.

“We more than anybody want a safe and reliable operation, but it is working in partnership,” Utsler said.

—Alan Bailey

BP continues its heavy oil research

BP is moving into the next phase of its research into the development of North Slope heavy oil, a form of oil with a consistency of chocolate syrup, not producible by conventional means and with a wellhead value perhaps $8 to $15 below that of conventional crude, Mike Utsler, BP senior vice president for greater Prudhoe Bay, told Petroleum News June 9.

In September 2008 BP successfully demonstrated the production of heavy oil from the Ugnu formation at Milne Point S-Pad on Alaska’s North Slope, with a technique called cold heavy oil production with sand, or CHOPS, involving the use of a downhole pump with an augur-like rotor sucking a mixture of sand and oil up a vertical production well, with the oil being separated from the sand at the surface.

This initial production test did not demonstrate that heavy oil could be produced viably: Viable production would require high production rates combined with acceptable production costs, perhaps involving the use of horizontal wells and new designs of processing facilities.

Specialized production facilities for further tests of heavy oil production have been under construction in Anchorage, and BP has drilled a horizontal well at Milne Point for the testing, Utsler said. BP wants to test the feasibility of sustained production from a horizontal well and to test two other types of well completion he said.

“The next well testing of the horizontal CHOPS well is being planned for this September,” Utsler said. “The facilities are in construction in various parts of the town and will be shipped to the slope between July and August, with then a long-term test of the horizontal heavy oil well planned for September (and) over the (following) six to nine months.”

Heavy oil would have to be mixed with light oil for shipment down the trans-Alaska oil pipeline, and there is an estimated 20 billion barrels of heavy oil in place under the North Slope.

“It’s an unproven technology, but we remain encouraged by our preliminary results,” Utsler said.

—Alan Bailey