Improved Sweep in Bati Raman Heavy-Oil CO2 Flood: Bullhead Flowing Gel Treatments Plug Natural Fractures
- Osman K. Karaoguz (Consultant) | Nazan Necibe Senol Topguder (Turkish Petroleum Corp.) | Robert H. Lane (The Petroleum Institute) | Ulker Kalfa (Turkish Petroleum Corp.) | Demet Celebioglu (Turkish Petroleum Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2007
- Document Type
- Journal Paper
- 164 - 175
- 2007. Society of Petroleum Engineers
- 5.1.5 Geologic Modeling, 5.4.5 Conformance Improvement, 3.3 Well & Reservoir Surveillance and Monitoring, 4.1.3 Dehydration, 2.2.2 Perforating, 5.8.7 Carbonate Reservoir, 5.5.8 History Matching, 3 Production and Well Operations, 4.3.4 Scale, 4.6 Natural Gas, 4.3.1 Hydrates, 5.6.9 Production Forecasting, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.5 Reservoir Simulation, 7.1.9 Project Economic Analysis, 7.1.10 Field Economic Analysis, 5.6.2 Core Analysis, 5.4 Enhanced Recovery, 5.2.1 Phase Behavior and PVT Measurements, 5.4.2 Gas Injection Methods, 5.5.2 Core Analysis, 5.1 Reservoir Characterisation, 1.8 Formation Damage, 5.7.2 Recovery Factors, 5.1.1 Exploration, Development, Structural Geology, 4.1.2 Separation and Treating, 5.6.4 Drillstem/Well Testing, 5.3.2 Multiphase Flow, 5.7 Reserves Evaluation
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This paper covers the successful pilot field application of polymer gels for reservoir conformance improvement in the ongoing CO2 injection project at Bati Raman heavy-oil field in southeastern Turkey. Bati Raman is a naturally fractured carbonate reservoir in which the heterogeneities and the unfavorable mobility ratios between CO2 and the heavy oil cause inefficient sweep of the reservoir. These conditions prompted the pilot application of a conformance-improvement fracture-plugging (flowing) gel system in three wells in July 2002. Based on injection tests performed in the field, approximate treatment volumes were estimated to be on the order of 10,000 bbl for each well. Volumes actually pumped ranged from approximately 6,500 to 11,000 bbl. All three of the wells showed a gradual increase in injection pressure during treatment, indicating a decrease in injectivity index as treatment progressed. During one treatment, an offset producer experienced changes in fluid level consistent with rapid pressure transmission via the connecting fracture early in the treatment, with later loss of such communication. This behavior provides direct evidence of fracture plugging during treatment (Lane 2002).
A mechanistic semianalytical model based on previously published laboratory work (Lane and Seright 2000) obtained a good match with the field data. The rate/pressure data were fed into the model, and effective fracture widths were backcalculated. Comparisons of results with the Formation MicroImager (FMI) log findings are explained. Gel-monitor well responses were scaled based on field data using a Fetkovich type decline-curve analysis. These studies enabled the incorporation of the effect of reservoir heterogeneities on the gel propagation radius so that future gel-treatment design parameters could be optimized.
Pre and post-treatment CO2 injection pressures and the rates are as shown in Table 1. Sweep efficiency was increased as defined by produced oil/injected gas ratio. The 1-year average post-gel oil rate from 19 offset producers is 720 STB/D, as compared with a pre-gel oil rate of 645 STB/D. The rate of increase from the treatments is thus 75 B/D, or 12%, which indicates a payout time of 12 months. Keeping this enlightened approach and seizing on the key concepts, four more CO2 injector wells were treated in 2004 to follow up on the encouraging results.
Bati Raman field is the largest oil field in Turkey, having an estimated 1.85 billion bbl of heavy-oil reserves. It is located in southeast Turkey (Fig. 1) and contains low-pressure, low-gravity (10 to 13°API) oil at an average depth of 4,300 ft. Its reservoir rock, the Garzan formation, is heterogeneous, fractured, vugular limestone. Average matrix porosity is 18%, with mainly vugs and fissures, and secondary porosity is 1 to 2%. The typical matrix permeability by core analysis is 10 to 100 md; however, well tests show effective permeabilities in the range of 200 to 500 md, confirming the contribution of secondary porosity. The field was first placed on production in 1961 and had produced 1.5% of its reserves by 1986, when Turkish Petroleum Corp. (TPAO) began immiscible CO2 injection. Through 2003, 5% of the reserves had been produced, which is still an unexpectedly low value. Production rate has declined drastically since 2000. TPAO is seeking the most applicable methods to impede or reverse the decline. Polymer gel treatments were an obvious enhanced-oil-recovery (EOR) method to increase CO2 sweep efficiency.
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