The Success Story Of First Ever Polymer Flood Field Pilot To Enhance The Recovery Of Heavy Oils On Alaska\u27s North Slope

The primary goal of the first ever polymer flood field pilot at Milne Point is to validate the use of polymers for heavy oil Enhanced Oil Recovery (EOR) on Alaska North Slope (ANS). The specific objectives are systematic evaluation of advanced technology that integrates polymer flooding, low salinity water flooding, horizontal wells, and numerical simulation based on polymer flood performance data. Accordingly, under the co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on August 28, 2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Unit (MPU) on ANS. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the J-pad flood pattern. Since July 2020, HPAM concentration was reduced to 1,200 ppm to control injectivity and optimize polymer utilization. Filter ratio tests conducted on site ensure uniform polymer solution properties. Injectivity is assessed by Hall plots, whereas production is monitored via oil and water rates from the two producers. Water samples are analyzed to determine the produced polymer concentration. Supporting laboratory core floods on polymer retention, injection water salinity, polymer loading, and their combinations on oil recovery, match rock, fluid and test conditions. A calibrated and validated numerical multiphase reservoir model was developed for long-term reservoir performance prediction and for evaluating the project\u27s economic performance in conjunction with an economic model. Concerns related to handling of produced fluids containing polymer are addressed by specialized experiments. As would be expected in a field experiment of this scale, barring some operational and hydration issues, continuous polymer injection has been achieved. As of September 30, 2022, a total of 1.41 million lbs. of polymer or 2.99 million bbls of polymer solution (~18.8% of total pore volume), placed in the pattern serves as an effective indicator of polymer injectivity. During the first half of the pilot period, water cut (WC) drastically reduced in both producers and over the entire duration, the deemed EOR benefit over waterflood was in the range of 700-1,000 bopd, and that too at a low polymer utilization of 1.7 lbs./bbl. Low concentration polymer breakthrough was observed after 26-28 months, which is now stabilized at 600-800 ppm in congruence with the WC. Although as indicated by laboratory experiments, polymer retention in core material is high; ~70% of the injected polymer propagates without any delay, while the remaining 30% tails over several PVs. History matched simulation models consistently forecasts polymer recovery of 1.5-2 times that of waterflood, and when integrated with the economic modeling tool, establish the economic profitability of the first ever polymer flood field pilot. Produced fluid experiments provide operational guidance for treating emulsions and heater-treater operating temperature. Over a duration of ~4.5 years important outstanding technical issues that entail polymer flooding of heavy oils have been resolved, which forms the basis of the success story summarized in the paper. The first ever polymer pilot is deemed as a technical and economic success in significantly improving the heavy oil recovery on ANS. The pilot has provided impetus to not only apply polymer EOR throughout the Milne Point Field, but has paved the way for additional state-funded research targeting even heavier oils on the ANS. The combined success of this work and the future work will contribute to the longevity of the Trans Alaska Pipeline System (TAPS)

Microsoft Word - SPE 105907.doc

Abstract This paper considers whether foams can be superior to polymers for improving vertical sweep efficiency in reservoirs. Our focus is on vertical sweep improvement during waterflooding and chemical flooding rather than gas flooding. Both linear and radial flow geometries were considered, with and without crossflow. We found that foams can provide improved sweep compared to polymer solutions if (1) foam forms in high permeability zone(s) but not in low permeability zone(s), (2) no crossflow occurs between high and low permeability zones, AND (3) the foam resistance factor in the high permeability zone(s) is sufficiently high to overcome the permeability contrast and the unfavorable mobility ratio between the gas bank and the oil/water bank in the less permeable zones. Foams will generally not be superior to polymers under other circumstances unless gravity effects provide a fortuitous benefit. Other limitations for foams must be recognized, including (1) challenges with formulating foams to meet the above requirements, (2) limitations on foam propagation, especially due to surfactant retention, (3) compression costs during foam injection, and (4) limitations on foam stability under reservoir conditions. The paper also examines limitations for polymers. Historically, permeability reduction by polymers was advocated as advantageous since reduction in polymer mobility was greater than anticipated based on solution viscosity. However, this permeability reduction generally increases with decreasing permeability, thereby diminishing sweep efficiency. Applications in linear flow (i.e., fractured wells) can be reasonably forgiving of this effect if the permeability contrast and the polymer solution resistance factors are sufficiently large. For radial flow (i.e., wells that do not intersect fractures) with crossflow between layers, the effect has little consequence. However, for radial flow with no crossflow, the effect is quite damaging to sweep

Microsoft Word - SPE 115142.doc

Abstract This paper estimates injectivity losses associated with injection of EOR polymer solutions if fractures are not open and considers the degree of fracture extension if fractures are open. Three principal EOR polymer properties are examined that affect injectivity: (1) debris in the polymer, (2) polymer rheology in porous media, and (3) polymer mechanical degradation. Using Berea sandstone cores (100-600 md) and various filters and filter combinations, an improved test was developed of the tendency for EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers. Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft. For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea. Considering the polymer solutions investigated, satisfactory injection of more than 0.1 PV in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm 3 /cm 2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects where polymer solutions are injected