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.
Tarn 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.
Tabasco 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.
Meltwater 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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