Vilje


Production line Gas lift line


Water injection and disposal line Umbilical


East riser base


West riser base


Boa


South riser base


Kneler B Kneler A Alvheim FPSO East Kameleon


Critical Components Besides their ability to enhance drainage effi- ciency and boost cumulative oil recovery, ICDs offer the industry relatively inexpensive, low-risk components for technology-driven strategies. They can be easily added to development programs that include sand control and horizontal wells. In the Norwegian sector of the North Sea, engi-


neers at Marathon Petroleum Company (Norway) LLC concluded that the recoverable reserves in the relatively thin oil columns of the Alvheim and Volund fields were directly and consistently linked to the amount of net pay exposed to the wellbore (left). To establish maximum contact, Marathon therefore drilled single-, dual- and trilateral wells with horizontal sections ranging in length from 1,082 to 2,332 m [3,550 to 7,651 ft]. The Marathon team realized that to fully


Volund


> Layout of Alvheim and Volund fields in the Norwegian area of the North Sea. [Courtesy of Marathon Petroleum Company (Norway) LLC.]


the PeriScope bed boundary mapper—was used to steer a smooth wellbore trajectory. The longer lateral came online without the


assistance of gas lift at 2,300 bbl/d [366 m3/d] of oil and a water cut of about 10%. This level of water production was expected from mobile water in the oil rim and is not associated with breakthrough from the water leg. The second well, drilled updip from the first, required gas lift to clean up and initially produced about 1,900 bbl/d [302 m3/d] with 20% water cut.


30,000 25,000 20,000 15,000 10,000 5,000 0


Jun 16, 2008


Aug 08, 2008


Production from both wells compared favor-


ably with that from other deviated wells in the area drilled conventionally through the stacked sands of the field. However, even including costs of the additional technology—rotary steering sys- tem, LWD and ResFlow ICDs—the overall project cost was 15% less than it would have been using traditional well construction methods. In addi- tion, increased sweep efficiency gained by well placement and ICDs has increased the asset value by an estimated 100,000 bbl [16,000 m3] of oil.


Actual oil production rate Predicted oil production rate Actual water cut Predicted water cut


OSWIN09/10—Rick, story #2—Figure 07


80 70 60 50 40 30 20 10 0


Sept 24, 2008


Nov 13, 2008


Jan 02, 2009


Feb 21, 2009


Date


> Production improvements. In Well 24/6-B-1CH of the Alvheim field, the 13-m oil column with an active aquifer was produced at a higher drawdown than originally planned. As shown in the graph, the resulting higher production volumes were achieved without significantly increasing water cut over predicted values, which is indicative, if not conclusive, that an even inflow profile was achieved.


34


Apr 12, 2009


Jun 01, 2009


Jul 21, 2009


Sept 09, 2009


exploit the benefits of the correlation of recover- able reserves to net feet of reservoir contact, it was important that the entire length of the comple- tions contribute to production. Early in the project they decided to use both ResFlow nozzle-type ICDs and helical-type ICDs in all production wells—a total of 10 wells at Alvheim and 1 at Volund. As a result of this technology-based approach


and the favorable geology, Marathon has increased its booked reserves at Alvheim from 147 million to 201 million bbl [23 million to 32 million m3] of oil and from 196 to 269 Bcf [5.5 billion to 7.6 billion m3] of gas. The fields have been in production less than


two years, and the completions include numerous technologies, making it difficult to attribute specific results to a single methodology. However, overall water production at the Alvheim floating, production, storage and offloading (FPSO) facility is less than originally expected. A good example is the 24/6-B-1CH well, which has a 13-m [43-ft] oil column and an active aquifer. The well has been produced at higher rates than originally planned without significant onset of, or increase in, water production (left). Both these outcomes, though their causes are inconclusive, suggest ICD success in maintaining an even flow profile. When one completion planned as a single lat-


eral evolved to a trilateral, engineers also learned a valuable lesson concerning planning for the use of ICDs and multilateral installations. Because the actual completion departed from the original plan, the flow rate was different than predicted. The ICDs chosen for these installations were of a design type that could not be readily changed, and thus optimized, on location. The result was gas and water coning earlier than expected in both laterals.


Oilfield Review


Oil production rate, bbl/d


Water cut, %


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