Mangala is the largest discovered oil field in the Barmer Basin of, Rajasthan, India having a STOIIP of over 1 billion barrels in multiple stacked fluvial clastic reservoirs. It contains medium gravity (20–28oAPI), waxy, viscous crude (9–17 cp) in high permeability (1–25 Darcy) clean sandstone reservoirs. Initial development plans for the field are based on waterflooding, with at least the initial volumes of water heated to minimize any issues with wax dropout in the reservoir. Owing to the relatively high oil viscosity and adverse mobility displacement for waterflooding, the desirability of implementing an appropriate EOR process was identified shortly after the field discovery. Screening studies identified aqueous-based chemical flooding processes as the most favorable for Mangala. Detailed laboratory studies have now identified the potential of alkaline-surfactant-polymer (ASP) processes in significantly improving the sweep and displacement efficiency. The laboratory studies involved screening and optimization of the ASP slug formulation based on IFT measurements, adsorption measurements, polymer rheological and thermal stability studies; followed by a series of linear and radial corefloods. Experiments indicate the ASP process is the most effective chemical EOR process for Mangala, with improvement in recovery efficiency above the waterflood recovery of over 30% STOIIP. Chemical EOR simulations with using STARSTM have been used extensively to understand the process mechanisms via matching of the coreflood experiments. Simulation parameters tuned to the laboratory data were used to evaluate the process performance under field conditions. A closely spaced five-spot pilot with 100m well spacing has been designed to evaluate the process. The pilot consists of four injectors, the central producer, three saturation monitoring wells and two post-pilot core holes. An ASP pilot will be implemented in the field shortly after startup of the waterflood. Introduction Production startup of Mangala under waterflood is planned for 2009. Given its adverse waterflood mobility ratio, the importance of EOR for Mangala was realised soon after its discovery in 2004. The bulk of the Mangala reservoir contains a medium- to light-gravity oil of moderate viscosity, with a minor biodegraded zone of higher viscosity above the OWC. The oil also has a reasonably high petroleum acid content, which will react with an injected alkaline solution to form natural "soaps" that can help to increase oil recovery. Reservoir geology varies from massive and well-connected stacked channel sands to relatively discrete single-storey channels with somewhat poorer (but still good) lateral communication; all with high porosity and permeability. Further, the injection water available has low salinity and is reasonably soft. Mangala oil, rock and water attributes are all positive for the application of mobility-controlled chemical EOR methods. The base waterflood is expected to recover more than 35% of STOIIP, with an oil plateau of 4–5 years duration before the field goes on steep decline. Significant fluid handling and water injection will be required to achieve the projected recovery. Thus, huge potential exists for mobility control chemical flood processes, not only in terms of extending the plateau and increasing reserves but also in terms of significantly reducing total fluid production and water injection requirements. This is important for the project economics as it implies that the oil production facilities will work longer at designed capacity longer, and total fluid handling requirements may go down if an EOR process is implemented sufficiently early, before the field goes on waterflood decline. This will result in significant CAPEX and OPEX savings as well. Early implementation of the process will also ensure a more better efficiency of the process, as the in situ oil saturations will be high. Otherwise late in the field's life, the higher water saturations that will exist later in the field's life can partially shield the remaining oil from the action of the injected chemicals.
Mangala field is one of the largest onshore oil fields in India. The Fatehgarh reservoirs consist of multi-Darcy permeability sandstones with low connate water saturations and moderate reservoir temperatures (62°ϾC). The reservoirs contain waxy and moderately viscous crude (9 -22 cP) resulting in adverse mobility ratio between oil and water. The field was originally developed using an inverted 9-spot, hot waterflood. Given the viscous nature of the oil, even before development of the field was initiated, it was envisaged that sweep improvement methods would have good potential to enhance overall recovery from the field. After detailed laboratory studies and a successful pilot, a full-field polymer flood has been implemented. Experience from the pilot highlighted the need for maintaining polymer solution integrity and ensuring good propagation of the flood; acquisition and analysis of reservoir surveillance data are crucial in order to implement a successful polymer flood.Initially, lab viscosity measurements of actual samples from the full-field project's injection lines conducted in aerobic conditions showed significantly lower values than what would be expected based on measurements made on polymer solutions in synthetic brine. Readings from an online viscometer, however, showed somewhat higher viscosities. Use of a stabilizer chemical during sample collection helped protect the sample from aerobic degredation, and the viscosity measurements more closely matched the online viscometer. The data re-emphasized the need to prevent oxygen from entering the system, and modificationsto the polymer preparation plant, Central Polymer Facility (CPF), to minimize oxygen ingress showed marked improvement in viscosity readings. This paper will detail the procedures followed to minimize the impact of oxygen (air) while taking samples and measuring viscosity.A detailed well and reservoir surveillance program was implemented at the start of polymer injection. Surveillance activities includedspinner surveys, fall-off tests, bottom-hole pressure measurements, and saturation monitoring. The paper also presents an analytical approach for the estimation of in-situ viscosity with fall-off surveys. These results are compared with modeled viscosity from simulation. All polymer injector wells were pre-produced for extended periods prior to start of polymer injection; previous experience showed that this improved injection (reduced skin) and conformance. The saturation monitoring survey and fall-off tests suggest good sweep and even re-saturation of oil in some sands. Integration of high resolution seismic data between injector-producer pairs and surveillance data helped the operator to take appropriate action on some under-performing producers which later showed significant improvement in performance.Initial oil production response from producers which are near to polymer injectors is encouraging, with significant increases in oil rate and decreases in water-cut. Samples collected from some of the producers show polymer breakthrough in...
The paper discusses the full-field polymer flood implementation plan post successful pilot result in one of the largest onshore fields in India. Mangala field contains multi-Darcy sandstones that have high porosity and very low connate water saturation and low temperature (65 degC). The connate water salinity is low (~6500 total dissolved solids), The crude is waxy and viscous, which results in unfavorable mobility for water-flooding, Chemical flood was identified as a potential EOR method during a screening study. A normal 5 spot polymer flooding pilot has been conducted and results are encouraging in terms of additional oil recovery and reduction of water cut. Additionally much has been learnt about how to optimize the surface facility, polymer preparation, and polymer quality monitoring. Following the successful completion of the pilot, it is planned to implement a polymer flood for the fullfield. All the lab results and pilot learnings have been incorporated to minimize the uncertainty and risks. Different subsurface injection pattern concepts have been evaluated based on the reservoir characteristics. Various parameters like pattern and number of wells, polymer viscosity, tapered vs. fixed concentration, polymer slug sizes and other variables have been optimized and are discussed in the paper. Sensitivities to capture the impact of polymer adsorption, implementation schedule, conformance in injectors, visco-elastic effect of polymer, polymer shear thinning characteristics etc. on recovery have been studied. Learning from pilot has been used in selecting the surface facility, well design, pumping facility, selective completion for conformance control, surface pressure requirement, and designing to minimize the viscosity loss across the completion and sand face. Surface facilities concepts have been finalized to prepare concentrated polymer at a single location and pumping it to each well for injection. Polymer flooding has the potential to significantly improve the sweep efficiency in the field and to increase expected ultimate recovery (EUR). The project is one of the largest in the world in terms of scale, polymer usage, and related facility and logistics.
Detailed laboratory experiments were carried out to evaluate the potential for various chemical flood processes (polymer, alkali-polymer, and alkali-surfactant-polymer) in Mangala, a large oilfield in India containing waxy crude with viscosity of 7–20cp. Experiments included fluid-fluid and fluid-rock interaction studies, followed by a series of linear and radial corefloods. Simulation of the corefloods was carried out using STARS, the advanced compositional simulator available from CMG. The main coreflood simulation objective was to shed light on the various process mechanisms and to generate chemical flood parameters for field-scale simulation forecasts. Primary matching parameters included performance of the base waterflood, injection pressures to define shear-thinning polymer behavior, chemical flood performance to define interpolations between appropriate relative permeability curves based on capillary numbers, and produced chemical concentrations to define adsorption parameters. Sensitivity studies on the matching parameters examined the impacts of heterogeneity within the large-diameter radial cores, chemical adsorption, and capillary pressure and gravity effects. The coreflood simulations provided significant insights into the chemical flood process mechanisms and eliminated uncertainties such as the effect of gravity in radial coreflood experiments; although some issues including the role of capillary end-effects have not as yet been completely resolved. The modeling showed that in situ saturation monitoring (scanning) of the cores is critical for future planned corefloods. The study also showed some of the current limitations in modeling these complex processes. Chemical flood parameters fine-tuned during the coreflood simulations have been used in field-scale simulations to evaluate expected performance and to aid in design of a field-scale pilot project. Extensive field-scale simulations have been used to design an appropriate chemical flood implementation strategy. These works indicate potential field-scale incremental recoveries over waterflooding of ~7% STOIIP for a polymer flood and ~15% STOIIP for an alkaline-surfactant-polymer flood.
The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered-most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.
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