Interwell EOR Pilot Proves Advantages of Polymer Flooding
This paper discusses an enhanced-oil-recovery (EOR) polymer-flood pilot at the Captain field in the UK North Sea during 2011–2013.
This paper discusses an enhanced-oil-recovery (EOR) polymer-flood pilot at the Captain field in the UK North Sea during 2011–2013. The polymer flooding accelerated 6 years of potential waterflood recovery to 1 year and minimized potential water injection and handling by 25.2 million STB. A polymer incremental recovery of 16% original oil in place and improved sweep of 4.7 million STB demonstrated the advantage of using polymer EOR for viscous oils. Finally, the pilot data provided sufficient information to deliver a reliable subsurface assessment for the full-field project. These data also provide evidence that chemical-flood pilots not only can be economical but also can compete economically with waterflooding in some challenging locations when designed and operated efficiently.
The Southern Upper Captain Sandstone (SUCS) reservoir is a complex channel infill of a localized canyon eroding the underlying Mid Captain Shale (MCS) and Lower Captain Sandstone (LCS). The canyon was created when two megaslump scars merged into a linear valley cut, giving the reservoir its characteristic shape. The slump scar process also triggered deposition of debrites (a mixture of MCS and LCS sediments) of poor reservoir quality, isolating the underlying LCS from the subsequent SUCS canyon fill.
Fluids from the Captain field are unlike those normally encountered in black-oil reservoirs. The fluid is a low-gravity oil with a relatively low dissolved-gas/-oil ratio. The oil is heavily biodegraded with some property gradation across the field. There is an apparent general increase in biodegradation from east to west. The oil in the SUCS is analogous to that in the main part of the Upper Captain Sandstone (UCS). Pressure/volume/temperature and special core-analysis laboratory data reveal a highly unfavorable calculated endpoint mobility ratio equal to 31. The following field observations support the adverse mobility ratio:
- Strong coning tendency
- Early water breakthrough
- Modest oil-rate decline
- Long oil-tail production in waterflood-recovery profiles
- Sharp oil-saturation changes between unswept and swept regions
- Injected water slumping to the base of the reservoir, advancing along the base of the sand, and bypassing the oil
Pilot Objectives, Mechanisms, and Implementation
The polymer flood for the field was originally envisioned in the field-development plan, and the concept was included in the original facilities design to enable a field trial. The major challenge in deploying a polymer flood is field implementation. Though onshore polymer flooding may be considered a mature technology, field experience is difficult to transfer and the offshore environment adds another level of complexity.
Polymer flooding must be performed in stages, requiring field trials or pilots before fieldwide application. To this end, a polymer pilot was conducted in the SUCS, a suitable semi-isolated area of the field with a single well development analogous to the main UCS reservoir. Such isolation allowed clear interpretation of polymer-flooding results. A dedicated injection well was drilled to support the existing single producer in 2009, with a goal of initiating the operator’s first offshore interwell polymer pilot. The objective of the pilot was to reduce key uncertainties for a potential future full-field project at Captain field. Specific objectives included the following:
- Validate chemical performance in the field to justify full-field application
- Demonstrate an irrefutable production response associated with polymer injection
- Minimize disruption to ongoing topsides operations
- Demonstrate ability to inject and sustain polymer injection
- Validate logistical solution for polymer transport, transfer, and topsides inversion for the volumes and rates required
- Measure and record the data necessary to reduce influential EOR project uncertainties
- Achieve the three mechanisms of a successful polymer flood: accelerated oil production, incremental oil production as the result of improved polymer sweep, and minimized water production and injection
Before and during the pilot chemical injection, production logging tools were run in the injector and producer to measure their respective outflow- and inflow-phase profiles along the horizontal completions. The complete paper includes a full suite of surveillance data and their use in quantitative interpretation. The authors also show innovative uses of the data in their interpretation methods.
Pilot Chemical Selection and Design
The pilot strategy was justified through a value of imperfect information assessment. The selected strategy led to a phased approach in which an initial injectivity test was followed by a single interwell pilot. This was intended to gain proof of concept at a field scale and to assess process performance. The aquifer and gas-cap contacts in the reservoir were avoided to reduce chemical exposure and uncertainties that would have complicated interpretation. The pilot strategy was also designed to update project economics and assess the need for further pilots or injectivity tests to resolve project uncertainties, particularly the reservoir effect on enhanced recovery. Fig. 1 shows a tornado diagram of these uncertainties and their potential effect on net present value (NPV).
Project economics were based on an early assessment of indicative incremental recovery factors at Captain field and a high-level cost estimate for full-field polymer facilities. The range in incremental recovery was obtained from an extensive study scaled to field conditions. A mix of liquid- and powder-based polymers was expected to be used in the field. Post-pilot, all uncertainty ranges were reduced except oil price.
While both liquid- and powder-based hydrolyzed polyacrylamide polymers were screened, ultimately an emulsion was selected for the pilot to use the original liquid-polymer design installed on the wireline perforating platform and the floating production, storage, and offloading vessel. Polymer flooding reduced remaining oil saturation to 27.9 and 22.4% in Ottawa and Captain reservoir sands, respectively.
Designing the optimal slug is an economic decision that balances enhanced recovery with chemical costs and processing rate. Additional factors influencing the decision, apart from oil price and chemical cost, are well completion and spacing, reservoir permeability, and oil viscosity. From an economic perspective, the optimal polymer viscosity for the Captain chemical EOR pilot was found to be 20 cp, corresponding to a concentration of approximately 2,000 ppm of the chosen polymer. This viscosity, combined with the aqueous-phase relative permeability of the field, yields a target mobility ratio with the crude oil of less than 2.
Injectivity-test objectives were to determine whether the target injection rate and polymer viscosity could be achieved and if the polymer injection equipment was functioning as designed. First polymer injection took place in October 2010 when an injectivity test was conducted upon the completion of the waterflood baseline. A total of 440 tons of emulsion polymer was injected with no signs of well plugging, which confirmed the ability to transport, mix, hydrate, and inject high-quality polymer under field conditions. As anticipated, significant pressure increases both at the wellhead and downhole were observed during the injectivity test because of the injection of high-viscosity polymer. The well sustained polymer injection at the target rates for the duration of the test. The complete paper includes a detailed discussion of the pilot injectivity test and the results of the pilot polymer flood. Water avoidance and a post-pilot surveillance well are also discussed.
Before and during the pilot chemical injection, production logging tools were run in the injector and producer to measure their respective outflow- and inflow-phase profiles along the horizontal completions. These logs confirmed that polymer promotes crossflow to make injection rates more uniform along the wellbore. The operator also drilled a post-polymer observation well in the swept zone between the pilot wells. Logs from this well established remaining-oil saturations to polymer that were used to confirm calculations for polymer-flood volumetric sweep. The post-polymer-flood oil saturations confirmed the performance of the polymer flood.
The pilot met the objectives of reducing key uncertainties for the overall project within a specific time frame. The injectivity test also validated the ability to sustain injection of high-quality polymer over an extended period of time by direct and indirect measurements. Minimal effects in terms of treating polymer returns were observed, and the use of a liquid emulsion polymer allowed an uptime in operations greater than 99%.
Even though the pilot was not designed to be economical, it provided positive NPV and demonstrated both acceleration (from better oil displacement) and improved recovery (from increased sweep) by polymer flooding. The three mechanisms of a successful polymer flood were satisfied. Waterflood recovery was accelerated by polymer flooding. Incremental oil was produced, and in more volume than was expected, because changing the displacing phase fluid mobility with the viscosified polymer increased volumetric sweep. A typical success metric for polymer flooding is that active polymer usage per barrel of incremental oil produced is below 5 lbm/bbl. The Captain EOR pilot achieved a value of 2.7 lbm/bbl. Finally, decreased water production reduced water handling and lowered operating costs.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190175, “Results of the UK Captain Field Interwell EOR Pilot,” by Annette Poulsen, SPE, Adam Jackson, SPE, Nicolas Ruby, SPE, and Karl Charvin, Chevron; Michael Shook, Mike Shook and Associates; Varadarajan Dwarakanath, SPE, and Sophany Thach, Chevron; and Mark Ellis, prepared for the 2018 SPE Hydraulic Fracturing Technology Conference, Tulsa, Oklahoma, USA, 14–18. The paper has not been peer reviewed.