Large-Volume Foam-Gel Treatments to Improve Conformance of the Rangely CO2 Flood
- T.L. Hughes (Schlumberger Cambridge Research) | F. Friedmann (Chevron Petroleum Technology Co.) | D. Johnson (Chevron Petroleum Technology Co.) | G.P. Hild (Chevron U.S.A. Production Co.) | A. Wilson (Schlumberger Cambridge Research) | S.N. Davies (Schlumberger Cambridge Research)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 1999
- Document Type
- Journal Paper
- 14 - 24
- 1999. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.3.4 Scale, 3.2.6 Produced Water Management, 4.1.2 Separation and Treating, 5.4.5 Conformance Improvement, 1.10 Drilling Equipment, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 2.4.3 Sand/Solids Control, 4.1.1 Process Simulation, 5.7.2 Recovery Factors, 5.4 Enhanced Recovery, 1.6 Drilling Operations, 2.2.2 Perforating, 5.2 Reservoir Fluid Dynamics
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Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s), and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery. This paper reviews progress in the application of large-volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. During the period November 1996-November 1997 three large-volume foam-gel treatments were successfully placed into the Rangely reservoir. The first 36?400 bbl treatment, implemented November 1996, increased the pattern oil rate from 260 barrels of oil per day (BOPD) in March 1997 to ±330 BOPD in August 1998; a conservative estimate of incremental oil recovery is ±40?000 bbl by the end of August 1998. The second 43?450 bbl treatment, implemented August-September 1997, increased the pattern oil rate from ±430 BOPD in March 1998 to ±470 BOPD in August 1998; post-treatment, the pattern oil rate data is described by a linear regression with slope, +56 BOPD but it is too early to make a firm estimate of incremental oil recovery. The third 44?700 bbl treatment, implemented October-November 1997, increased the pattern oil rate from ±330 BOPD in May 1998 to ±375 BOPD in July-August 1998; a linear regression of the post-treatment data gives a positive slope but again it is too early to estimate incremental oil recovery. Some general features in the pattern production response given by the three foam-gel treatments were observed. First, each of the treatments induces a stabilization in the pattern oil rate which, for treatments I and II, is accompanied by a decrease in the pattern gas rate. Second, the first positive oil rate response given by each of the treatments is observed 6-8 months after treatment execution and is dominated by the response at producer wells lying to the west/southwest and/or east/southeast of the treated injector well. For a given treatment volume, the cost of a foam-gel treatment at Rangely is 40%-50% below the average cost of polymer gel treatments. As the foam is injected at a higher rate, the total pump time required for a 40?000 bbl foam-gel treatment is similar to a 20?000 bbl polymer gel treatment. Early during pumping treatments II and III, we attempted to increase the CO2 content of the foam from 80 to 85 vol?%; this resulted in a wellhead pressure which was too close to the CO2 pressure limit necessitating a decrease in foam injection rate. Thus, in optimizing foam-gel treatment cost, there is a balance between maximizing the content of the inexpensive CO2 phase and minimizing total pump time. For Treatments II and III, the cost of the liquid phase formulation was reduced by decreasing the concentrations of surfactant and buffer. The implementation and evaluation of three large-volume foam-gel treatments at Rangely indicates that the foam-gel approach provides a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs.
A recent survey1 indicated that the proportion of U.S. EOR production recovered by gas injection has increased from 18% to 41% during the period 1986-1996. A major contribution to this trend has been the strong increase in the number of miscible carbon dioxide (CO2) projects which now account for > 70% of the total number of ongoing gas injection projects in the U.S. The Rangely CO2 flood began in 1986; currently, there are 372 active producer wells and 300 active injector wells, 259 of which are injecting CO2 using the water-alternating-gas (WAG) process.
In the application of gas injection to heterogeneous reservoirs, oil recovery efficiency can be limited by poor conformance as an increasing proportion of the injected gas flows through higher permeability thief zones and/or fractures. The importance of conformance improvement has long been recognized at Rangely. The main problem being addressed is poor CO2 conformance due to preferential flow through the natural fracture network leading to premature gas breakthrough at the associated producers. This process increases operating costs and reduces oil recovery. The objective of the Rangely Conformance Improvement Team (CIT) is to improve conformance in order to reduce operating costs and increase the oil recovery to >1 billion bbl (>50% OOIP) compared to the current 815 million bbl (43% OOIP).
A number of mechanical methods and chemical treatments have been employed to improve conformance at Rangely. While dual injection strings and selective injection equipment (SIE) have been used for improved injection profile control, chemical treatments using polymer gels2 and CO2 foam3 have been used to improve volumetric sweep efficiency and oil recovery. During the period 1994-1997, 49 injector wells were treated by placing a MARCIT™ gel4 into the fracture network.5 While these treatments have improved local sweep efficiency and oil recovery, economics limit the maximum treatment volume per injector well to 15?000-20?000 bbl. Certain regions of the Rangely reservoir require considerably larger treatment volumes to reduce the permeability of a larger volume of the fracture network and improve conformance in a larger volume of the well pattern.
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