Standard Screen
Zone 1 800 to 1,800 mD Zone 2 200 to 500 mD Zone 3 100 to 2,000 mD Total injection rate, m3/d 7,509 7,514 961 1,677 748 1,233 5,800
ICD with
Same Nozzle Size, 1.2 cm/joint, in All Zones
4,604
ICD with Different
Configuration Nozzle Size
3,570
0.9 cm/joint 0.7 cm/joint 2.2 cm/joint
820 3,128 7,518 3,500 800 3,200 7,500
> Optimizing injector ICD design. The injection rates used in the different completion scenarios of the Stær structure demonstrate that the injectors can be optimized based on permeability and nozzle design to obtain the desired rates in each zone. (Adapted from Raffn et al, reference 13.)
Target Rate, m3/d
into two segments; the injector and producer are located in Segment 1 and the second oil producer in Segment 2. The injector is a vertical well drilled through
the Not, Ile, Tilj and Åre 2 Formations and pro- vides sweep and pressure support for two hori- zontal producers. About 250 m [820 ft] deep, the injection well is an openhole completion with ResInject injection control devices, sand screens and a pack of resin-coated gravel to prevent annular flow. Engineers from Reslink and Statoil designed
Engineers suspected that the higher rates
required to clean up the entire production interval had exacerbated the heel-toe effect in the tradi- tional openhole completions. Modelers matched the production log data to a static reservoir simu- lation and replaced the ICD completion in the simulation with a standard screen completion. They then increased the rate in the standard screen completion to 15,000 bbl/d [2,400 m3/d]. That simulation indicated an extreme heel-
toe effect: The toe was contributing only 25% as much production as the heel. By contrast, simu- lated ICD completions with 15,000-bbl/d rates showed better balance of the inflow, including much higher contribution from the toe.12 These findings are significant in that they
show ICD completions allow extended well lengths in both these formations without compro- mising the balancing effect or cleanup efficiency in the lower sections of the wells. That result allows the operator to contact more formation with fewer wellbores without fear of sacrificing cumulative production.
Reversing Direction Though they are called inflow control devices, ICDs are also used to manage fluid outflow in injection wells. In some cases modeling reveals that it is more effective to place ICDs in the injec- tor well than in the producer. And in many instances installing the devices in both the injec- tor and producer wells is the best option. Injector wells often penetrate and give pres-
sure support to several reservoir intervals with varying characteristics. To avoid water break- through at production wells, reservoir engineers
designing injection projects must consider per- meability contrasts, heel-toe effect, formation damage, creation of thief zones and injectivity changes at the wellbore.13 Just as they do with inflow control, ICDs
address these challenges by balancing fluid out- flow along the entire length of the injection well- bore. If the well has a high-permeability streak, the ICD self-regulating feature prevents a signifi- cant increase of local injection rate. This ability to automatically control fluid mobility results in better water distribution and pressure support and thus enhanced areal and vertical sweep of oil reserves in all zones. It also delays water break- through, and because ICDs can control injection pressure and rate, there is minimal risk of near- wellbore fracturing. These capabilities matched the management
OSWIN09/10—Rick, story #2—Figure 12
goals of the Statoil team planning the 2004 devel- opment of the Urd field—a satellite producing to the Norne FPSO vessel in the North Sea. Placed on production in 2005, the Urd oil field contains two heterogeneous structures: Svale and Stær, which are 4 and 9 km [2.5 and 5.6 mi], respectively, from the main field. The field was developed using three subsea templates and pipelines for oil production, water injection and gas lift. Management goals for the ICD injection system included • optimizing pressure support and sweep effi- ciency for all zones
• delaying water breakthrough in high-permea- bility connected zones
• avoiding fractures that may dominate water distribution. The Stær structure was completed with one
injector containing ICDs and two horizontal oil producers containing intelligent technology for control of three zones. The reservoir is divided
36
the system. They modeled injection rates expected for three zones using different comple- tion techniques: standard screens alone, ICDs of the same nozzle size and number of nozzles per joint, and different numbers of ICDs per joint (left). The team chose to use the same nozzle configuration along the entire wellbore instead of specific ICD nozzle sizes and numbers for each zone. This choice reflected the fact that while dif- ferent designs in each zone achieved target injec- tion rates, simulations supported maximum injection rates in the upper zones.14 These simulations were run to evaluate the
economics of using ICD injectors on Stær and to select the nozzle design. Two static near-wellbore simulations were used to compare water distribu- tion: The first was based on injection into the matrix, including its permeability variations, and the second considered injection into a frac- tured zone. In the first case, the upper, high-permeability
zone received an uneven share of the injected water. However, with ICDs, peak outflow was reduced by 50% and zones with lower permeabil- ity received more water. For the second static model, a 12-m [39-ft], 20-D layer was added to
12. Sunbul AH, Lauritzen JE, Hembling DE, Majdpour A, Raffn AG, Zeybek M and Moen T: “Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency with Nozzle Based Inflow Control Devices in Sandstone and Carbonate Reservoirs,” paper SPE 120795, presented at the SPE Saudi Arabia Section Technical Symposium, Alkhobar, Saudi Arabia, May 10–12, 2008.
13. Raffn AG, Hundsnes S, Kvernstuen S and Moen T: “ICD Screen Technology Used to Optimize Waterflooding in Injector Well,” paper SPE 106018, presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, March 31–April 3, 2007.
14. Raffn et al, reference 13.
15. Tachet E, Alvestad J, Wat R and Keogh K: “Improve Steam Distribution in Canadian Reservoirs During SAGD Operations Through Completion Solutions,” paper 2009-332, presented at the World Heavy Oil Congress, Porlamar, Venezuela, November 3–5, 2009.
16. Fram JH and Sims JC: “Addressing Horizontal Steam Injection Completions Challenges with Chevron’s Horizontal Steam Test Facility,” paper 2009-398, presented at the World Heavy Oil Congress, Porlamar, Venezuela, November 3–5, 2009.
17. Fram and Sims, reference 16.
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