A New Polymer Flooding Technology for Improving Low Permeability Carbonate Reservoir Recovery--From Lab Study to Pilot Test--Case Study from Oman

Abstract

Abstract The field under study is located in the northern part of Oman where most of the fields have a tight carbonate oil reservoirs. Initially the field was produced under natural depletion for almost 15 years until 2005 when a line drive water flood development with horizontal wells took place and was deployed in the whole field. After more than 10 years of water injection, the water cut reached an average of 75% in the major producing blocks. The reservoir has a light oil with viscosity of 0.8 mPa.s, a downhole temperature of 87°C and average permeability of 10 mD. The calcium and magnesium concentration in formation water is high, about 4000 mg/L. Reservoir heterogeneity in tight carbonate reservoirs causes uneven water flood sweep efficiency and hence resulted in a lot of bypassed oil. The initial EOR methods screening in the field under study didn't recommend to use the conventional polymer flooding due to low reservoir permeability and hence injectivity challenge. However, a new unique nano-ploymer was recently developed in the market to be a potential EOR method for such tight formation reservoirs. Extensive laboratory experiments using the core and fluid samples from the studied reservoir followed by numerical simulation modeling work proved the technical feasibility for this new polymer. This was then followed by field testing pilot in one of the matured water flood sector and the performance is currently under monitoring. The new polymer is a particle-type and comes with various nanometer-micrometer sizes. This polymer has a low apparent viscosity of 1-4 mPa and when it is mixed with the injection water, the particles disperse in the water and the resultant mixture has a low viscosity making it easily to be injected. In addition, this nano-polymer has a high tolerance for both temperature and salinity. While the particles move into formation, they temporarily plug the preferential existing water paths and divert the injection water into the relatively small pores/throats and displace the remaining bypassed oil. The polymer particle has high deformation capacity, so it can deform and pass through the throat under certain pressure to plug even deeper parts of the formation. The process is repeated continuously so that it can inhibit water production and enhance oil production. For the lab experiments, 12 core plugs from the associated reservoir were collected, based on which, a series of experiments were conducted including: core thin section analysis, injectivity test for the nano-polymer and core flooding experiments on single plug and parallel double plugs. Subsequently, the lab results were utilized for numerical simulation and that was followed by economic evaluation. Based on the lab test results, a conceptual simulation model for the studiedfield's sector was used to estimate the incremental oil gain at different pore volume (PV) injection. The incremental oil gain was determined at different SMG PV injection starting from 0.05PV to 0.5 PV. The results showed that the best economic scenario is to go for PV injection of 0.3 which can be achieved in ~4 years'time. However, in order to expedite the field trail stage and reduce its cost, the lowest PV injection was selected which involves injection in two water injectors for one year only at 0.05 PV. The field pilot thus far has successfully completed the injection phase of the total planned volume (0.05 PV) of nano-ploymer. The injection was continuous for one year with no injectivity issue and the production performance is currently under monitoring.