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 But regardless of whether a North Slope gas line is eventually constructed, boosting oil production remains a top priority at Prudhoe Bay — with perhaps 25 billion barrels of original oil in place, just a small percentage increase in oil recovery from the field’s massive subterranean reservoirs can amount to the production of a major amount of useful product that would otherwise remain underground.
“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 But overlaid onto that original infrastructure, new technologies have achieved the breakthroughs in oil recovery that have extended the life of the field — although production has dropped to about a quarter of its peak rate, the field still produces about 440,000 barrels of oil per day.
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 And critical to threading production wells through ever more elusive pockets of oil are drilling technologies such as coiled tubing drilling, in which a motor-driven drill bit draws a continuous length of steel tubing through a new well bore augured out from the side of an older well.
“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 Various techniques for injecting fluids into the reservoir, to coax or force more oil into production wells, also continue to play a crucial role in boosting oil production. Each technique, as it comes into use, adds to the impact of previously used techniques, thus causing an incremental growth in oil recovery, Utsler said.
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 Natural gas produced from the field and then re-injected above the oil in the reservoir has been a key mechanism for maintaining reservoir pressure at Prudhoe. However, in recent years natural gas mixed with natural gas liquids to form what is called miscible injectant has been used as a solvent to clear residual oil from the reservoir rock.
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 addition to producing light oil from the main Prudhoe Bay reservoir, BP has been developing viscous oil, oil that can be moved by itself but is too thick to produce economically by conventional means. But with relatively low flow rates and high-cost facilities, high state production taxes combined with low oil prices have put the dampers on viscous oil development, especially on a large-scale project planned for the western part of the Prudhoe Bay unit, Utsler said.
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 In parallel with investigating new ways of producing oil from Prudhoe Bay, BP has embarked on a program of infrastructure renewal at the field, Utsler said.
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 And planning and engineering design work has started for subsequent field upgrades, involving the modernization of the aging oilfield facilities, including the possible installation of facilities designed for gas production if a North Slope gas line is built.
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.”
|