Design of In-Depth Conformance Treatment in the Mangala Polymer Flood Project

Abstract The Mangala Field is located in the Barmer Basin in north-west of India (Fig. 1). The field has oil in-place volumes of 1.3 billion barrels, with an estimated recovery factor of 43% with polymer flood. Production began in 2009 and water injection in 2010. Polymer flooding started in 2015 in all layers at field scale. A successful ASP pilot was conducted in 201012 and it envisaged to roll it out gradually to full field in due course of time. The main reservoir units in the Mangala Field are the fluvial sandstones of the Fatehgarh Formation. The targeted reservoir horizon (FM1), is quite heterogeneous. The permeability range varies from 200 mD to several Darcies (4-5 Darcies) and sandbody connectivity is complex in the reservoir that is interpreted as a fluvial to lacustrine environment. This heterogeneity affects polymer sweep efficiency and calls for an in-Depth Conformance solution. Two candidate patterns were selected for further evaluation of conformance technologies. The selection criteria were based on early breakthrough, non-uniform injection profiles, cross-section analysis to check connectivities and low recovery factor with higher remaining oil. Several chemical conformance options were considered. Injection of gels are constrained by the gelation time, which does not typically exceed a few days. Injection of Microgels is preferred since the single component product acts by simple adsorption and can thus propagate deep in the reservoir. Moreover, the Microgel size which is above 2 μm, prevents the invasion of low-permeability intervals by a size-exclusion process. The product has thus a natural tendency to invade high permeability sandbodies (already swept). Different Microgel species have been submitted to lab tests. SMG Microgels keep their original size, while EMG Microgels expand with time and temperature. A major challenge to overcome is the existence of a polymer layer adsorbed on pore walls, which creates a barrier to Microgel adsorption. Finally, an EMG species whose chemistry induces high adsorption level has been qualified. The adsorption level is as high as 200 μg/g and the product induces a permeability reduction to water of around 8.5. Reservoir simulations were conducted afterwards to optimize the injection design (volume and duration) and draw performance forecasts. The reservoir simulation software used for the study can perform a dual polymer simulation, so two different species of polymers can be simulated. The sector model was made of two inverted contiguous 5-spot patterns with central injectors. The best scenario consisted in injecting the EMG at a concentration of 0.3% for 15-30 days. The deployment is simple since the product (delivered as liquid emulsion) can be injected with a volumetric pump of the water injection line directly. Additional oil production is expected to be as high as 95,500 bbls in 4.5 years. Microgel technology, has been successfully applied in waterflood projects in heterogeneous sandstone reservoirs and is shown to be applicable in ongoing polymer flood as remedial injection to solve conformance problems as well as produce significant incremental oil currently by-passed.