Planning and Implementing a Large-Scale Polymer Flood
Authors: Weiss W.W. , Baldwin R.W. 
Published: December 2007

The motive for the Eliasville polymer flood originated while planning a waterflood in its light oil. limestone reservoir. Adverse reservoir waterflood characteristics were identified before unitization, and laboratory work was undertaken to demonstrate the benefits of reducing water mobility by increasing water viscosity with polyacrylamide polymers. Computer simulations polyacrylamide polymers. Computer simulations incorporating polymer properties from laboratory work and known Caddo waterflood performance were used to design the polymer flood slug size and polymer concentration. Three injection tests were conducted to determine polymer injectivity. Pressure transient tests were used to polymer injectivity. Pressure transient tests were used to measure the in-situ polymer viscosity. One of the injection tests included an off-pattern producing well that permitted an estimation of polymer retention and incremental permitted an estimation of polymer retention and incremental oil recovery in a short time. On the basis of injection tests and simulation work, a large-scale polymer project was implemented. The optimum slug size required 30 million lbm [0.17 kg] of emulsion polymer. Facilities used to mix and feed this large amount of polymer are described. A low-shear polymer flow control method was developed to ensure maximum fluid viscosity at the formation perforations. Product specifications were verified before accepting delivery, and injection fluid quality was monitored in laboratories constructed for the project. Early production response to field-wide polymer injection is comparable to that observed at the off-pattern producing well during the injection test. While the early field producing well during the injection test. While the early field response is encouraging, the effects of saltwater injection on slug integrity and increased pattern size on oil recovery are still to be determined.

Introduction

The 3,900-acre [15 782 805-m 2 ] Eliasville Caddo Unit, operated by Sun E and P Co., is a Caddo reef pool in the Stephens County regular field in Stephens County, TX (Fig. 1). The field was discovered during Jan. 1920 and produced 7,459,000 bbl [118 590 m3] of solution gas- produced 7,459,000 bbl [118 590 m3] of solution gas- drive primary oil through 1975. Caddo waterflood operations in Stephens County were initially undertaken during the 1960's but high water-cut oil production in the absence of a stabilized oil bank was disappointing. Mobil Oil Corp. was the first to attempt to improve Caddo waterflood performance with polymer. Mobil conducted an unpublished pilot polymer flood in the Curry Unit during 1969. The pilot was expanded to the majority of the unit in 1973. During 1973, Texaco conducted pilot Caddo waterflood and polymer flood tests in the Parks Ranch Unit; neither test was expanded. The Mobil and Texaco tests were conducted before the advent of government-sponsored EOR incentive programs. A decision to form the Eliasville Caddo Unit was reached, and water injection began March 1977. A study undertaken in 1976 indicated that increasing the displacing fluid viscosity would improve the pore-to-pore, areal, and vertical sweep efficiencies.

Reservoir Description

Caddo lime is a lower Pennsylvanian age reef formation found at 3,200 ft 1975 ml at Eliasville. Lithologically the rock is described as a randomly fractured, finely crystalline, styolitic tan limestone with vugular and in tergranular porosity. Oil is trapped by the overlying Strawn shale. Porosity determined by log analyses averaged 13.2%, air permeability averaged 11 md, varying from 0.1 to 234 md. Typical Caddo development is illustrated in Fig. 2 by the interpretation of the logging response for Well 132. Currently, production is confined to the upper interval. Oil/water relative permeability curves depicted in Fig. 3 represent the two-phase flow characteristics. Notice that small increases in water saturation can result in rapid increases in water mobility and accompanying decreases in oil mobility. Oil moves very slowly once water breaks through in this rock. The family of representative capillary pressure curves in Fig. 4 have been converted from an pressure curves in Fig. 4 have been converted from an air/brine system to a reservoir oil/water system at room temperature. The 39 degrees API [0.83 g/cm3] paraffinic crude has a dead oil viscosity of 3 cp at 115 degrees F [0.003 Pas at 46 degrees C]. Oil/water interfacial tension is 15 dynes/cm [0.000002 N/m] and the advancing contact angle on glass is about 112 degrees, indicative of the wettability found in many carbonate reservoirs. Connate water contained 165,000 mg/L [165 000 mg/dm3] total dissolved solids. Possum Kingdom Lake injection-water total dissolved solids content is seasonal but averages 1,200 mg/L 11200 mg/dm3, including 400 mg/L [400 mg/dm 3] (Ca + Mg). Saturations at the start of secondary production were 53% So, 35% Sw, and 12% Sg.

Process Design Process Design Polymer flood design included laboratory tests to screen Polymer flood design included laboratory tests to screen commercially available polymers, computer simulation to forecast potential reserves, and field injectivity tests to verify laboratory polymer characteristics.

JPT

P. 720