Method for Laboratory and Field Evaluation of a Proposed Polymer Flood
- Richard E. Castagno (Conoco Inc.) | Russell D. Shupe (Conoco Inc.) | M. Duane Gregory (Conoco Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1987
- Document Type
- Journal Paper
- 452 - 460
- 1987. Society of Petroleum Engineers
- 5.6.5 Tracers, 5.2.1 Phase Behavior and PVT Measurements, 5.6.4 Drillstem/Well Testing, 4.1.2 Separation and Treating, 1.2.3 Rock properties, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 5.7.2 Recovery Factors, 4.1.9 Tanks and storage systems, 4.3.4 Scale, 5.3.4 Reduction of Residual Oil Saturation, 5.5 Reservoir Simulation, 3.1.1 Beam and related pumping techniques, 3.4.5 Bacterial Contamination and Control, 1.6.9 Coring, Fishing, 5.4.1 Waterflooding, 1.8 Formation Damage, 5.7.5 Economic Evaluations, 5.2 Reservoir Fluid Dynamics
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Summary. The relevant components of a proposed polymer flood in the Tensleep reservoir of the Frannie Phosphoria-Tensleep Unit in Park County, WY, were investigated. Laboratory testing consisted of polymer injectivity, stability, retention, and effective viscosity measurements. On the basis of polymer viscosity and retention tests, a polysaccharide polymer was chosen over a polyacrylamide polymer for extensive laboratory polymer was chosen over a polyacrylamide polymer for extensive laboratory evaluation and field pilot tests. Field testing included injectivity, biological stability, and in-situ viscosity measurements. Pressure falloff tests following variable-rate injection of a polysaccharide polymer solution indicated the presence of a non-Newtonian, low-mobility bank. Even though good injectivity was obtained during injection of a 15% PV polymer slug, the proposed field project was not done. This was primarily polymer slug, the proposed field project was not done. This was primarily because of low in-situ (reservoir) polymer solution viscosity and lack of proven microbial control in the near-wellbore region. proven microbial control in the near-wellbore region. Introduction
This paper presents the details of work to determine the feasibility of a polymer flood in the Tensleep reservoir of the Frannie Phosphoria-Tensleep Unit. The method of evaluation covered broad range of Phosphoria-Tensleep Unit. The method of evaluation covered broad range of laboratory and field investigations and should be generally applicable for any proposed polymer flood. Practical considerations for the polymer solution are that (1) it must be injectable into the reservoir, (2) it must survive, and (3) it must be able to move through the reservoir and provide the required viscosity. Field tests were done to verify injectivity, biological stability, and in-situ viscosity. Fall-off tests, done after injection at variable rates, were conducted to investigate the non-Newtonian behavior of the polymer bank in the reservoir. Falloff test results and in-situ viscosity estimates were given previously. A three-dimensional reservoir simulation, not covered in this paper, used field-generated data to project an oil production schedule for the final economic analysis.
Reservoir Characteristics. The Frannie Phosphoria-Tensleep Unit is located in Park County, WY, and Carbon County, MT. The Tensleep reservoir at Frannie was discovered in 1928. By the mid-1940's the productive limits of the reservoir were essentially defined and developed on 10-acre [40 x 103-m2] spacing. The southern portion of the reservoir was developed on 20-acre 180 x 103-m2] spacing because of high water production from natural water influx. The Tensleep formation is a northwest/southeast-trending anticlinal structure on the east flank of the Big Horn basin. The reservoir is composed of five sandstone layers, approximately 200 ft [61 m] thick, divided by shale and shaley dolomitic stringers. Formation temperature averages 90 deg. F [32 deg. C]. The analyses from 23 cores were used to determine the reservoir rock characteristics. The analyses showed that the reservoir had two rock or permeability systems, with median permeabilities of 6.5 and 137 md (total weighted average of 38.8 md). The two rock systems were intermixed in the vertical column with the upper portion of the rock having higher average permeability than the lower portion. The lower-permeability system, with a median porosity of 9.5%, contained about 40% of the reservoir PV (phi h) porosity of 9.5%, contained about 40% of the reservoir PV (phi h) and only 5% of the reservoir's flow capacity (kh), while the more permeable system, with a median porosity of 16.3 %, contained 60 % permeable system, with a median porosity of 16.3 %, contained 60 % of the PV and 95% of the total flow capacity. Capillary pressure curves showed that the initial water saturations for the lower-permeability system and the higher-permeability system were 19.5 and 9%, respectively, with a weighted average of 13.2% for the total reservoir. Ultimate recoverable reserves should be 124 million STB [19.7 x 106 stock-tank m3] of oil, or almost 50% of the original oil in place (OOIP), leaving almost 126 million STB [20 x 106 m3] of oil not recoverable by present secondary recovery methods. For this reason. the Frannie field has a large potential for tertiary recovery.
Fractional Flow Curves. Initially, fractional flow calculations were made to determine the amount of additional recovery expected from a polymer flood (Fig. 1). The calculations were based on relative permeability curves derived from clean-core experiments. Polymer permeability curves derived from clean-core experiments. Polymer flood recoveries were predicted for a range of polymer-to-oil viscosity ratios. For instance, at a ratio of 1, a wide separation in the two fractional flow curves (waterflood and polymer flood) was observed (Fig. 1). This indicated an excellent chance for increasing the displacement efficiency by substituting polymer solution for water as the displacing phase. The objective of polymer flooding would be to improve the displacement efficiency by lowering the mobility of the displacing fluid. No significant increase in oil recovery was expected as a result of an increase in volumetric sweep efficiency. At Frannie, the water-flood has an unfavorable mobility ratio (M less than or equal to 1 is favorable), and the viscosity ratio of the oil (15 cp [15 mPas]) to injected water (0.77 cp [0.77 mPas]) is about 19. If the viscosity of the injected fluid were increased to equal the oil viscosity (mu p/mu o = 1), the mobility ratio would improve dramatically. The change in mobility ratio could produce an estimated 5 million STB [795 x 103 m3] of oil (2% of the OOIP) according to the fractional flow prediction.
Polymer Selection Polymer Selection Brines Used in Frannie Study. Four different brines were used during the laboratory evaluation of polysaccharide and polyacrylamide polymers for the Tensleep reservoir. Frannie injection polyacrylamide polymers for the Tensleep reservoir. Frannie injection brine (FIB) was nearly identical in composition to the low-salinity, high-hardness reservoir interstitial water. Because FIB was unstable in air owing to the presence of H2S, a chloride-based Frannie injection brine (CBFIB) was formulated as a stable substitute for FIB. Field Madison Brine (FMB) was a stable, low-salinity alternative to FIB.
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