The objective of this study was to develop a cost-effective scale-controlprogram for the Rangely field CO2 project. The primary challenge was toidentify scale inhibitors to control an existing barium sulfate (BaSO4) problemat the new, low-ph conditions caused by CO2 injection. A secondary concern wasthe change in produced-water composition and increased calcium carbonate(CaCO3) scaling tendency caused by the dissolution of carbonate minerals in thereservoir rock by the low-ph CO2 injection water. Laboratory evaluationidentified several polymer-based and phosphonate scale inhibitors for the lowpH (estimated 4.5) at CO2 production wells and near-neutral pH conditions inthe surface facilities. Field tests show a good correlation to laboratoryresults. Suitable phosphonate products are preferred to polymer inhibitorsbecause their residual concentrations may preferred to polymer inhibitorsbecause their residual concentrations may be determined accurately, they aregenerally cheaper, and they have a longer squeeze treatment life.
The Rangely Weber Sand Unit (RWSU), located in northwestern Colorado, covers19,000 acres and has a cumulative oil production exceeding 720 million bbl. The California Co. (now Chevron U.S.A. Inc.) discovered the Weber reservoir in 1933but did not begin development until 1944. The field was completely developed on40-acre spacing by 1949. A secondary recovery waterflood program began in 1958following unitization. program began in 1958 following unitization. BaSO4 and CaCO3 scale began to appear in the production wells as the waterflood matured. The onset of BaSO4 scale is related to the decrease in sulfate ionconcentration caused by dilution through injection of fresher water. Sulfate-reducing bacteria further reduced sulfate concentrations. Sulfatelevels in field water fell from more than 1,200 mg/L in the original formationwater to an average of 350 mg/L and as low as 50 mg/L in some producers. Thelower sulfate ion concentration in the reservoir water released barium tore-establish the barite solubility product. At problem producers, water fromsands with high barium concentrations mixes with water from sands with highersulfate concentrations so that the BaSO4 solubility is exceeded and scale isformed. Pressure changes and fluid agitation accelerate BaSO4 and CACO3 precipitation. The RWSU has controlled the BaSO4 scale problem successfullyduring the waterflood with phosphonate and phosphate ester scale inhibitors. Scale inhibitors were applied in problem producers by flush treatments, continuous injection through capillary tubing, downhole chemical-injectionpumps, and squeeze treatments. A tertiary CO2 water-altemating-gas flood beganin Oct. 1986 in about one-fourth of the field (Fig. 1). Total field productionexceeds 500,000 BWPD and 36,000 BOPD, with about 25 % of the oil attributed tothe injection of 100 MMcf/D of CO2. The inception of the CO2 projectnecessitated a review of the selection and application of all scale inhibitors. The primary concern was that the existing BaSO4 scale problem would no longerbe controlled in the CO2 area. The literature reports that, as CO2 injectiondecreases the pH of the reservoir brine, the effectiveness of thephosphonate-type inhibitors used in the Rangely waterflood decreases. Asecondary concern was the effect that the injected CO2 might have on thechemical composition of the produced water. The literature reports that CO2 flooding can dissolve carbonate minerals in reservoir rock and thereby increasethe concentration of calcium, magnesium, iron, and bicarbonate in the producedwater. This increases the scaling tendency of CaCO3 and can alter the pH. Thisfluid/rock interaction was expected in the Weber sandstone, which containsseveral percent of calcite and ferroan dolomite cements. The objective was todevelop a cost-effective scale-control program for the CO2 project. The idealinhibitor will prevent BaSO4 program for the CO2 project. The ideal inhibitorwill prevent BaSO4 not only under low pH conditions, but also at neutral pH. This is necessary because scale inhibitor treatments are often performed before CO2 breakthrough and because reservoir heterogeneity could cause thecoproduction of low- and neutral-ph brine. Another requirement is the continuedinhibition of CaCO3 scale throughout the producing system. Production of low-phbrine delays calcite deposition downhole, but this scale has become a greaterproblem on the surface where the CO2 gas exsolves and the pH increases. Thispaper addresses the following topics: field sampling to determine theproduced-water composition before and after CO2 injection; auxiliary laboratorytests to confirm that CO2 injection dissolves carbonate minerals; laboratorytests to screen candidate scale inhibitors for the new water composition and pHfound in the CO2 project; field testing of the most promising inhibitors; andoptimization of the scale-inhibitor squeeze treatments.
This section reviews laboratory and field studies to determine the effect of CO2 injection on the produced-water chemistry and its alteration of the Webersandstone. This work is presented in more detail elsewhere.
The pH of a brine decreases with increasing CO2 pH Reduction. The pH of a brine decreases with increasing CO2 partial pressure. Fig. 2 showsthis trend for a Rangely brine (from partial pressure. Fig. 2 shows this trendfor a Rangely brine (from the Main Water Plant sampled pre-CO2 flood). Asexpected, each 10-fold increase in the CO2 partial pressure causes a decreaseof one pH unit. The calculated pH (determined with the OLI System ProChem waterchemistry software) matches these data well. Extrapolating the results of Fig.2 to 3,000 psig. typical Rangely injection well pressure, predicts a pH as lowas 3.5. This condition is expected because the CO2 mixes with the formationwater near the injection wellbore. The CO2 and brine are injected alternatelyat the injectors. This pH is estimated to increase to about 4.5 by the time thebrine reaches the production wells because of a decrease in pressure and anincrease in bicarbonate concentration.
The water composition Produced-Water Analysis in CO2 Area. The water composition remained fairly constant in the CO2 project area as the waterflood matured in the 1980's. After oil/waterseparation, produced brine was recycled for injection; very little river waterwas used as makeup. The injection brine fell to about one-third the totalsalinity of the original formation brine (33,000 vs. greater than 100,000 ppmtotal dissolved solids) owing to the gradual addition of fresher water duringthe early stages of the waterflood. Water composition was studied in detail in20 production wells in the CO2 project to monitor changes caused by thistertiary recovery process (Fig. 1, Table 1). The most obvious differences(besides lowering of pH from CO2 injection) are the increases in calcium, magnesium, iron, and bicarbonate concentrations.