A considerable portion of world reserves are located in mature and viscous oil reservoirs having thickness less than 15 m. Polymer flooding is a mature technology and is the most important EOR method based on full field case histories. Accurate assessment of injectibility of viscous polymer solutions into these reservoirs without induced fractures is a major challenge. Therefore, the objective of this study is to experimentally investigate and model polymer injectivity in porous media using unfiltered partially hydrolyzed polyacrylamide (HPAM) solutions for wide range of polymer concentrations (125-5000 ppm) and salinities (5-20 g/L) in high permeability sandstones. Data from rheological measurements and single phase linear core flood studies carried out as a part of this study were utilized for understanding the key microscopic (pore level) mechanisms and for quantifying the injectivity.Based on the experimental analyses, it was found that viscous nature of polymer solutions and their retention in porous media were the main mechanisms for loss in injectivity. Data obtained from the experiments were used to validate and fine tune the model. Subsequently, with the help of the Langmuir adsorption isotherm, filtration theory, permeability reduction model, Non-Newtonian viscosity and Darcy laws numerical modeling was performed for predicting the injectivity losses during polymer injection. A good quality match was obtained with experimental data. Finally, sensitivity of polymer concentration and salinity on injectivity was studied. Further, the results from this study, will serve as an auxiliary input for field scale simulations, will help operators in the selection, design and execution of the field projects and will stand as guidelines for extending the polymer flooding technology for heavy oil reservoirs.

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Among various Enhanced Oil Recovery (EOR) methods, gas injection has been proven to be one of the effective ways of enhancing oil recovery from mature fields. The field under study has approached the economic limit of production under conventional recovery methods (primary and secondary recovery). Since start of production in sixties, the field has produced 48.5 % of the initial oil in place and the water cut has increased to 89 % in April 2011. Responding to the industry needs, initially a comprehensive study was performed to evaluate the potential of immiscible CO 2 injection for the recovery of residual oil after water flooding in this mature field. This paper presents the preliminary results of immiscible CO 2 injection on the basis of laboratory studies and detailed compositional simulations carried out on a sector model of the field. Based on the results obtained from laboratory studies it was found that CO 2 injection yields significant incremental recovery. Simulation results show significant increase in field oil production, essentially from 200 to 1100 m 3 /day and considerable decrease in water cut were observed. In addition, detailed PVT simulations were carried out to obtain

We carried out an integrated reservoir characterization to model a heavy oil reservoir called Balol located in the heavy oil belt of Mehsana in the western state of Gujarat in India. The Oil and Natural Gas Corporation of India was the field operator. The operator adopted in situ combustion process in northern part of Balol because of high-mobility contrast between oil and water. However, the performance review carried out by the operator found that oil recovery from this field was not as per prediction. Hence, serious attempts were made to interpret 3D seismic data to map the reservoir efficiently. We integrated the information derived from 3D time-lapse seismic data with the well logs provided by the operator to explain the movement of thermal front tracked using time-lapse seismic data. To model the reservoir, flow unit and electrofacies characterization was also carried out, and four to five FUs with conduits and baffles to flow were identified. Electrofacies analysis identified three major reservoir facies. These analyses also revealed that Balol reservoir was layered and heterogeneous with depth. Further, in addition to 3D seismic data, well logs and empirical equations were used to generate porosity, water saturation, and permeability models for the entire reservoir. Thus, a reservoir model with heterogeneous distribution of petrophysical properties was generated. We observed a high permeability trend in the northwest direction at injection wells, which could be governing the movement of thermal fronts in the reservoir.

Summary Injectivity decline is an issue during produced-water reinjection (PWRI) for water disposal in aquifers, waterflooding, chemical enhanced oil recovery, and geothermal-energy exploitation. A novel model for injectivity decline under flow conditions reminiscent of PWRI was developed taking into account deep-bed filtration and buildup of external filter cake. A distinct feature of the model is that it describes particle-retention kinetics responsible for internal filtration by an exponential decaying function of the retained-particle concentration. The corresponding nonlinear governing partial-differential equations were solved numerically and coupled with a known analytical model for external filtration with the concept of transition time. Coreflood experiments consisting of the injection of brine containing suspended hematite particles (volume fractions in the range of 2 to 6 ppm) were also performed. Computed-tomography (CT) scans of the core were taken to obtain deposition profiles along the core at different times. In addition, effect of various parameters (particle concentration and number of grids) on injectivity was investigated. From CT-scan and optical-microscope analyses, it was found that surface deposition in the porous medium and face plugging at the injection face of the core were responsible for decline in injectivity. The transition time from pure internal to external filtration was accurately determined from the CT-scan and pressure data. The newly proposed model and experiments were found to be in excellent agreement, indicating that the adopted retention function is a good heuristic description of particle retention.