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Vol. 18, No. 31 Week of August 04, 2013
Providing coverage of Alaska and northern Canada's oil and gas industry

BP looks to new development at Prudhoe Bay to help stem decline

Although major effort in stemming oil production decline from the giant Prudhoe Bay field on Alaska’s North Slope goes into finding and developing ways to tease as much oil as possible from the parts of the field that have been the focus of production since the field first came on line in 1977, effort is also being devoted to producing additional oil from technically challenging areas of the field which have hitherto seen relatively little development activity. With much of the “easy oil” already removed from the field, these additional areas can potentially play a significant role in adding more barrels of oil to Prudhoe Bay output.

During a July 18 interview with Petroleum News, Scott Digert, BP’s Alaska subsurface manager, explained about two promising development areas: an area referred to as Eileen West End/Northwest Eileen in the northwestern part of the field, and the Sag River formation, a thin reservoir unit above Prudhoe Bay’s main Ivishak reservoir.

Western Prudhoe Bay

Digert said that the extreme western part of the field is one of the few areas that has yet to be fully developed. In the west BP has been drilling into the Ivishak reservoir as part of an expansion project for Z-pad, a pad originally constructed for the development of Borealis, a satellite field within the Prudhoe Bay unit. In this part of the Prudhoe Bay field the Ivishak reservoir is in a lower position than in the more central part of the field and is partially separated from that central part by some geologic faults. Consequently, the extreme western part of the Ivishak has limited pressure communication with the main field area, Digert said.

New wells in the more western part of the field have been filling out new patterns for waterflood, the technique whereby water injected underground is used to flush oil from the reservoir, Digert said. Although there is a relatively thin oil layer in the area, it has proved possible to drill some quite successful wells, with improved seismic data enabling a better understanding of the geology and allowing the identification of potential drilling targets. Although interspersed with impervious shale horizons, the reservoir sands in this region respond well to waterflood, with the patterns oriented to allow good waterflood performance along the many faults and fractures that intersect the reservoir, Digert said.

Farther to the west, in Northwest Eileen, the oil column becomes very thin, with just 30 feet or so of oil between the top of the reservoir and the oil-water contact at the base of the oil. Development of this thin oil resource will require horizontal drilling, Digert said. And there are concerns about water production: A tarry layer than tends to seal the base of the oil column from underlying water in the main part of the field does not appear to act as effectively as a seal in the extreme west, he said.

So, given the issues relating to expensive and complex drilling into a thin oil column, coupled with a risk of water encroachment, BP is still evaluating the potential to extend its activities farther north and west, with financial and oil tax questions playing into that development decision, Digert said.

Sag River

BP is also evaluating new development opportunities in the Sag River formation, a reservoir formation just 20 to 40 feet thick, about 100 feet above the main Ivishak reservoir. Because all wells drilled into the Ivishak have to pass through the Sag River, people have known about the Sag River oil resource for many years. But given the ease of developing the Ivishak compared with the Sag River, a thin formation with rocks significantly less conducive to the flow of oil than the Ivishak, the Sag River has not seen as much development during the history of the field to date.

One phase of Prudhoe Bay development did include the perforation in the Sag River of production wells drilled into the Ivishak, enabling the comingling of some Sag River oil with Ivishak oil, Digert said. But perforating the Sag River in these wells did not adequately produce the Sag River, as it did not compete effectively with the Ivishak for flow in the wellbores, generally only forming perhaps 1 or 2 percent of the oil production rates, he said.

And it does appear that fluids in the two reservoirs are in communication with each other, probably through fractures and faults that pervade the rocks — despite the lack of Sag River production, the oil content in the Sag River has depleted over the years in parallel with the depletion in the Ivishak, Digert said.

Test wells

In recent years BP has begun drilling 2,000- to 4,000-foot horizontal production wells through the Sag River formation, with the wells located just below the field’s gas cap and dedicated to Sag River production, Digert said. With pressure transmitted from the gas cap driving oil production through these wells, the wells have proved fairly successful and are competitive in terms of production rates with wells currently drilled in the Ivishak, he said.

However, given the need for gas-cap pressure support for oil production, it will likely only be possible to place two or three rows of wells of this type around the gas cap area, Digert said. So, BP has been drilling some new Sag River “proof of concept” wells, using long horizontal production wells paired with long horizontal injectors, with the injectors designed to drive oil production in areas where gas-cap pressure support is weak. These complex and difficult wells traverse 6,000 to 8,000 feet horizontally through the Sag River formation, crossing multiple geologic faults, with the drillers having to relocate the reservoir each time the drill bit passes through one of the faults.

Given that the drillers need to know what geology to expect as a well crosses a fault, these wells particularly test people’s ability to use seismic data to resolve subsurface geologic structures, Digert said.

So far BP has drilled one pair of test wells from drill site 17 and another pair at drill site 13. The company has started trying the use of miscible injectant, a mixture of natural gas and natural gas liquids, in the injector well at both drill sites and has found the pairs of wells to perform effectively, Digert said.

Multi-stage fracking

In a more structurally complex setting at drill site 13 the company has been using multi-stage fracking — the technique used for developing shale gas and oil elsewhere in North America — to try to achieve acceptable oil production rates. Essentially, working backwards from the far end of the production well, the drillers ran a separate hydraulic fracturing job in the first six of eight reservoir sections between the major faults that the well encountered, Digert explained. Now, after some initial problems bringing the well into production, five of the sections in the well are producing nicely, he said.

And although this well has proved extremely expensive to drill and bring into production, lessons learned, including tests using either miscible injectant or water injected through the injector well, will enable evaluations of the extent to which pressure support for oil production can transmit from the injector well to the production well in the difficult Sag River reservoir. BP does, however, anticipate miscible injectant gas to likely be more effective than water as an injectant, given the relative facility with which gas can flow through the complex fractures and faults in the reservoir, Digert said.

Large development?

The Sag River tests could lead to a large new development in the Sag River, accessing the formation over the more peripheral area of the field. In fact, the possibility of a major new Sag River development forms part of the justification for BP’s intent to increase its Prudhoe Bay drilling rig fleet from seven to nine, Digert said.

But Sag River wells will be expensive and questions remain over whether sufficient subsurface pressure support can be achieved and whether the wells will prove economically viable. This viability may be improved by the recent tax changes,

In a June 26 presentation to the Resource Development Council, BP Alaska President Janet Weiss talked about the possibility of 200 new wells and somewhere in excess of 200 million barrels of new oil production from a Sag River development project, with a 16-well development program scheduled for 2015 and 2016. Weiss linked the viability of this and other major field development programs, and to expanded well work programs, at Prudhoe Bay to recent changes in the Alaska oil production tax, with the company deciding to invest an additional $1 billion in the field.

Major gas sales?

BP is also considering the possibility of future major gas sales from the Prudhoe Bay field, should a pipeline for delivering that gas to market come to fruition. According to BP’s latest plan of development for the field, the company will continue to use natural gas in its traditional role of maximizing oil production from the field, but the company is also considering field depletion models involving the offtake of gas for major sales, and evaluating the potential impact of gas sales on overall field production.

—Alan Bailey



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More Prudhoe Bay infrastructure upgrades

Inspections and upgrades of pipelines and other infrastructure continue in the Prudhoe Bay field on Alaska’s North Slope, following some major pipeline replacements after pipeline corrosion caused an oil spill in 2006.

BP spokeswoman Dawn Patience told Petroleum News in a July 26 email that BP uses x-ray equipment, ultrasound and visual inspections as part of an on-going program to ensure pipeline integrity.

“BP has a measurable safety and reliability program for pipeline assurance on the North Slope,” Patience said. “It includes frequent inspections and applied technology. … BP does more than 110,000 inspections for corrosion under (pipeline) insulation and about 160,000 total pipeline inspections a year.”

Pipeline work

According to BP’s latest Prudhoe Bay plan of development some pipeline replacement has continued, with the replacement of one of the pipelines in the field and the replacement of a fuel gas line in 2012. The company has also been doing pipeline inspections using pigs, the cylindrical devices that are passed down the insides of the lines — the company inspected four oil sales pipelines, 16 three-phase cross-country pipelines, five produced water injection pipelines, one seawater injection pipeline and three natural gas pipelines in 2012, the plan says. And most of the scheduled follow-up work for pipeline anomalies identified from similar inspections in the past two years has been completed, the plan says.

Work is also in progress to make it possible to do inspections with pigs in some other lines where pigs could not previously be used, the plan says.

Infrared technology

Patience said that for a number of years BP has been monitoring pipelines from the air using infrared technology that can detect hydrocarbon vapor and temperature anomalies. The company has recently developed a means of fitting the infrared equipment on security vehicles, thus enabling ground-based infra-red monitoring, including the monitoring of areas of pipelines not visible from a vehicle cab and monitoring during variable weather conditions, Patience said. Infrared and video images from inspections are downloaded into a computer-based geographic information system, she said.

According to the development plan BP has also been upgrading the seawater treatment plant that provides water for injection into the Prudhoe Bay reservoir — the injected water maintains reservoir pressure and flushes oil from the reservoir rock. Upgrades have improved the reliability of the plant, reduced downtime and enabled better management of dissolved oxygen levels in the water, the plan says.

—Alan Bailey