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Vol. 19, No. 28 Week of July 13, 2014
Providing coverage of Alaska and northern Canada's oil and gas industry

Continuing development

Drilling & oil recovery procedures keep oil flowing from Kuparuk satellites

Alan Bailey

Petroleum News

Although much attention on Alaska’s North Slope tends to focus on Prudhoe Bay and Kuparuk River, the huge legacy oil fields of the region, continued exploration and appraisal around these fields has led to the development of a number of more modest-sized fields. Referred to as “satellites,” and feeding oil and gas into the production facilities of their larger cousins, these fields make valuable contributions to North Slope oil production.

In a series of updated plans of development filed with Alaska’s Division of Oil and Gas, Kuparuk field operator ConocoPhillips has provided insights into how the Kuparuk satellite fields, in particular, are being managed, to maximize the recovery of oil from various oil pools within the Kuparuk River unit.


The Tarn field, discovered from exploration drilling conducted in 1997 and brought online in 1998, had produced a total of 109 million barrels of oil by the end of 2013. In 2013 the field produced oil at an average rate of 5,600 barrels per day, the Tarn development plan says. In that year the field had 38 active production wells and 23 active injection wells. However, some development drilling scheduled for 2013 was deferred into 2014 because of drilling rig issues, the plan says.

The plan says that, with recent studies having indicated some new development opportunities, both for infilling existing developments and for developing the perimeter of the field, ConocoPhillips plans to drill four new wells and two sidetracks to existing wells in 2014 and 2015. The wells will involve horizontal and slanted drilling, while one well, a production well, is expected to require multi-stage fracturing, the plan says.

The original development plan for Tarn involved the injection of miscible injectant, a mixture of natural gas and natural gas liquids, into the field reservoir, to maintain reservoir pressure while flushing oil from the reservoir rock. Although this type of injectant is often alternated with water injection in a process called water-alternating-gas, or WAG, laboratory tests of rock from the Tarn reservoir indicated the likelihood of reservoir damage, should water be injected, the plan says.

But the subsequent discovery of better quality reservoir rock following some development drilling led to the implementation of a full-scale WAG program, using miscible injectant. The use of this program in conjunction with a field simulation model has resulted in an effective response from production wells, the plan says.

Reservoir simulation

Reservoir simulation studies are helping understand the benefits both of continued development drilling and of changes to the enhanced oil recovery program at Tarn, the plan says. And a full-field model has been developed for forecasting future production and for identifying development opportunities. A high-resolution 3-D seismic survey conducted in 2008 is being interpreted and incorporated into the reservoir model. This survey is also providing insights into the movement of fluids in the Tarn reservoir, the plan says.

Although ConocoPhillips had originally anticipated that miscible injectant injected into the Tarn reservoir would help lift oil to the surface through production wells, problems relating to paraffin deposition caused the company to install hydraulic jet pumps as an alternative “artificial lift” technique to aid oil production. But, as more water starts to break into the production stream, it may be possible to revert to the original gas-lift concept, the plan says. With water associated with the pumping technique creating some corrosion issues in the wells, gas lift techniques are planned for new wells.

And as the field matures, some production wells are being converted for injection operations, the plan says.

In addition to developments within the existing Tarn field, ConocoPhillips has been evaluating opportunities in two other related discoveries, the Cairn and the Esker prospects, the plan says.


The Tabasco satellite field was discovered in 1985 during development drilling for the Kuparuk field. Development of the satellite started in 1998.

Total cumulative production through to the end of 2013 was 17.9 million barrels of oil. The average oil production rate in 2013 was 1,711 barrels per day.

An original plan to drill up to 19 Tabasco development wells was scaled back to seven production wells and two injection wells, because of a problem associated with water in the reservoir. To date, 12 wells have been drilled in the field, with five producers and two injectors being on line in 2013. Three deviated production wells have been shut in because of high water production and other problems, the plan says.

ConocoPhillips says that in 2014 it plans to continue to seek ways of producing more oil from Tabasco through an improved oil recovery program and through the drilling of additional development wells. The company says that it is currently using waterflood to maximize oil recovery and that the use of horizontal wells on the periphery of the field has minimized water production. Reservoir modeling suggest that the injection of lean gas, polymer and water has the potential to better sweep oil from the reservoir at Tabasco - further modeling and some laboratory testing is being considered to evaluate this approach, with a rework of the field model targeted for 2014-2015.

Meantime, ConocoPhillips says that it will monitor the performance of a newer completion strategy used in three existing production wells at Tabasco, as a guide to the design of possible future development wells.


In early 2000, exploration drilling discovered the Meltwater field, about nine miles south of Tarn. Field development began in 2001, with the field coming online in November of that year.

By the end of 2012 cumulative total oil production reached 17.7 million barrels, while the average production rate in 2013 was 1,971 barrels per day. Of the 19 wells drilled in the field, 11 production wells and four injection wells were active at the end of 2013, the plan says.

Initially ConocoPhillips used a WAG approach with miscible injectant for oil recovery from Meltwater. But since 2009, when the field’s water injection line went out of service because of corrosion concerns, the field has operated through the continuous injection of just miscible injectant, the Meltwater plan says. Having discovered that gas injection is particularly effective at Meltwater, ConocoPhillips plans to maximize oil recovery using gas injection for the foreseeable future. And the gas/oil ratios of individual production wells will be monitored, to assess the performance of continuous miscible injectant usage, the plan says.

Low pressures

From the outset of production from Meltwater, ConocoPhillips has experienced difficulties with anomalously low reservoir pressures, a problem that the company eventually attributed to a loss of injection fluids through one of the subsurface rock intervals. As a consequence, in 2012 the company adopted a new reservoir management strategy involving the placement of upper limits on injection pressures, the Meltwater plan says.

However, observed pressure communication between an injection and a production well has indicated the presence of a linear feature in the subsurface that allows the rapid flow of injected fluids.

ConocoPhillips uses a variety of artificial lift techniques on a well-by-well basis at Meltwater, including the use of hydraulic jet pumps, gas lift and plunger lift systems. The company is reviewing its future options for artificial lift in the field. In addition the company has been analyzing some new seismic data to identify new Meltwater development opportunities, including the possibility of coiled tubing sidetrack wells, the development plan says.

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Development continues to evolve at West Sak

Faced with the challenge of retrieving viscous oil from relatively shallow and unconsolidated reservoir sands in the company’s West Sak development, above the Kuparuk River field on Alaska’s North Slope, ConocoPhillips has tried an evolving series of production techniques, according the latest West Sak plan of development.

The field went into production in 1997. By the end of 2013 cumulative oil production was 67.5 million barrels. The average production rate during 2013 was 15,772 barrels of oil per day, the plan says.

Initial development

Initial West Sak development involved the use of vertical injection and production wells, with waterflood used to sweep oil from the underground rock reservoir. Multi-stage fracturing with gravel packing, or fracturing in combination with epoxy resin, was used to control the sand that tended to enter the production well bores. Downhole electric submersible pumps and progressive cavity pumps drove oil up the well bores to the surface.

Beginning in 2000 ConocoPhillips tried a new production technique at West Sak involving the use of multilateral, horizontal production wells, in which more than one well bore was driven horizontally through the reservoir from a single well bore drilled steeply from the surface. This approach evolved into the use of horizontal wells for water injection, as well as for oil production.

In a 2003 development program, undulating horizontal production and injection wells were drilled, with the undulations enabling a single horizontal well to access more than 100 vertical feet of reservoir sands. Slotted liners in production wells limited the entry of sand into the well bores, while downhole jet pumps drove oil towards the surface. The lengths of the horizontal lateral wells averaged 6,000 feet.

In 2004 ConocoPhillips drilled nine wells in West Sak, including the first tri-lateral wells, with three lateral wells running horizontally from a single steeply inclined well bore, the development plan says.

Multiple laterals

In 2005 the drilling strategy changed, with ConocoPhillips abandoning the undulating well design and, instead, using parallel multiple lateral wells to target individual reservoir sands — the company had experienced drilling and well performance inefficiencies, as the undulating wells passed through shale layers between the sands, the plan says.

Following exploration and delineation drilling between 2004 and 2006, in 2008 a first phase of development in the more northeasterly part of the West Sak area began. Horizontal water injection wells in this development used new technology to hydraulically isolate two sand horizons and improve the injection process. The multilateral junctions in the wells were of a new, advanced type, allowing improved injection control.

Along with evolving well designs, ConocoPhillips has tried different downhole pump designs, in particular to deal with the problem of sand entering and plugging wells. The plan of development says that evaluation of well completion designs continues for northeast West Sak, with the use of gas for the artificial lift of oil in production wells being a possible alternative to downhole pumps. And the pace of development has slowed while the results of recent developments are evaluated. Two new wells were started in November 2013 and the planning of six new wells involving a variety of completion technologies will continue in 2014, the development plan says.

Further developments

A development team is also evaluating the possibility of four new multilateral producers and 15 vertical injectors in the eastern part of the northeast West Sak area.

ConocoPhillips has also been conducting a pilot project, testing the use of viscous reducing water-alternating-gas enhanced oil recovery in West Sak. The Alaska Oil and Gas Conservation Commission recently approved the full-scale use of this recovery technique in the West Sak oil pool. The commission also approved an extension of the pool, to adjust the pool boundary and to add some further reservoir sands above the existing West Sak sands.

—Alan Bailey