Summary 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 apre-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.
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 where 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 bbls for each well. Volumes actually pumped ranged from ~6,500 – ~11,000 bbls. 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. A mechanistic semi-analytical model based on previously published laboratory work (Seright, et.al) obtained a good match with the field data. The rate-pressure data were fed into the model and effective fracture widths were back calculated. Comparison of results with the FMI log findings are explained. Gel monitor wells responses were scaled based on field data using Fetkovich type DCA. 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 shown in the following table:Table Sweep efficiency was increased as defined by produced oil/injected gas ratio. One year average post-gel oil rate from 19 offset producers is 720 stb/d as compared with pre-gel oil rate of 645 stb/d. Rate of increase from the treatments is thus 75 bbl/d or 12 %, which indicates a payout time of 12 months. Keeping this enlightened approach and seizing on the key concepts, 4 more CO2 injector wells are slotted for treatment in 2004 to follow up on the encouraging results. Introduction B. Raman field is the largest oilfield in Turkey, having an estimated 1.85 billion barrels of heavy oil reserves. Its reservoir rock is heterogeneous fractured, vugular limestone. The field was first placed on production in 1961 and had produced 1.5 % of its reserves by 1986, when TPAO began immiscible CO2 injection. Up to 2003, 5% of the reserves could be produced, which is still an unexpected 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 EOR method to increase CO2 sweep efficiency. The behaviour type of the field after the CO2injection application had started was analyzed by using oil rate, injection pressures, gas-oil ratio (GOR) and gas utilization factor history, and 3 different behaviour types were observed (Figure 1). The years 1986–1993 are defined as the fill-up period where the injected gas fills the fractures and vugs.
KOC undertook a major leap in its FDP expansion programme by a very comprehensive Miscible Gas EOR feasibility screening review of the North Kuwait (NK) Sabiriya and Raudhatain oil fields. This paper will highlight the major findings of the Phase 1 of this project executed in 2008. Phase 1 evaluated available resources and data required for implementation of an EOR Pilot followed by a full field implementation. Main emphasis was to evaluate EOR injectant supply options and identify a most-likely first source with the associated risks. The workscope encompassed 4 major task items: ▪Investigate and rank alternative injectants for technical/economic feasibility, recovery efficiency & local availability point of view:–CO2-the quality, quantity, usability from the industries, factories, power-plants.–Mixtures of CO2 & NGL from Jurassic Condensate–Feasibility of other methods such as water-alternating-gas (WAG) or nitrogen (N2) injection–Evaluate the Heavy Oil Project emissions as injectants.▪Review PVT EOR laboratory studies conducted by KOC to date. Screen data for consistency and representativeness for PVT/EOS modeling in Phase-2 sector/pattern reservoir simulation work. Characterize fluid property variation vertically and areally. Make recommendations.▪Review the completion and facilities for suitability in a CO2 & other injectant environment. Provide a first pass assessment of the associated gross economics to implement EOR scenarios that may require changes/uprgades to the surface facilities and/or completions.▪Review coreflood SCAL studies, solubility and miscibility tests including WAG. Compare waterflood and immiscible/miscible tertiary gasflood relative permeability experiments. Establish the need for carbonate rock leaching experiments for CO2 injection. Establish the need for asphaltene precipitation experiments for heavy API grades. The study identified pure CO2 and CO2/NGL mixtures as the most plausible miscible gas options worth pursuing a pilot study. For each Miscible Injectant type, the source options & supply volumes and the CAPEX and OPEX cost estimates were established. Semi- analytical recovery models were used to evaluate the EOR recovery efficiencies of the individual reservoirs, net injectant requirements and product streams. The detailed EOR cost model was built using the actual KOC well and facility cost Database and CAPEX and O&M costs for the industrial sourced CO2. A preliminary economics was performed using input from both models above. A pilot project to demonstrate the feasibility of CO2 WAG was also proposed.
A detailed study of the productivity and recovery potential for a turbidite reservoir has been completed using a practical application of stochastic modeling and reservoir simulation techniques. The objective of this study was to assess the impact of various reservoir characteristics on development considerations such as well spacing and expected production/recovery profiles. Distributions of typical sand body dimensions were estimated from a review of core, log, seismic, and analog data. These distributions were input to a stochastic modeling program to generate multiple realizations of reservoir descriptions for a range of net/gross ratios, facies distributions, and assumed sand body geometries. An interface program was developed to minimize the gridding problems associated with conversion of stochastic model output to reservoir simulation input data. Grid data generated from this program were input directly to practically sized reservoir simulation models. Results from the stochastic realizations and simulation models demonstrated the potential variability in connectivity and recovery profiles that may be expected for a turbidite reservoir. The reduced connectives in the stochastic model yield significantly different production profiles and lower recoveries than would be calculated with the assumption of continuous layer-cake type models. The approach developed for this study can be used to define and improve confidence limits for production and recovery profiles from typical turbidite reservoirs with only limited well information. Introduction Turbidite reservoirs are formed as a result of downslope movements of clasic sediments under the forces of gravity and fluid turbulence. These reservoirs are generally associated with deep sea submarine fans. Typical deposits consist of massive, structureless channel fill sands which pass laterally into and are overlain by progressively thinner, laminated intervals of sands and shales. The shifting, stacking, and erosion of these channel-levee systems results in a complex reservoir description with variable correlation of individual sands at the scale of typical well spacing. Interchannel areas, which are often dominated by muds (shales) and thin-bedded sands, can significantly reduce the connectivity of individual sand sequences. A schematic illustration of a typical facies distribution for this type of turbidite system is presented in Figure 1. An assessment of the impact of sand discontinuities or connectives in these reservoirs is required for realistic performance predictions and estimation of associated confidence limits. This is particularly important during the pre-development stage when major investment decisions, regarding well spacing and facility (platform) requirements, are being made on the basis of a limited number of exploration wells. Analytical calculations and conventional simulation approaches based on layer-cake type models will lead to optimistic results. Alternate model representations were proposed by Weber and van Geuns in which the architecture of middle and upper fan turbidites was described as either "jigsaw" or "labyrinth" distributions of sand bodies. P. 343^
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