Geochemical Modeling to Evaluate the Performance of Polymer Flooding in a Highly Sour Sandstone Heavy Oil Reservoir
- Mohammed Taha Al-Murayri (Kuwait Oil Company) | Dawood Sulaiman Kamal (Kuwait Oil Company) | Jose Gregorio Garcia (Kuwait Oil Company) | Mojdeh Delshad (UEORS) | Christopher Britton (UEORS) | Robert Fortenberry (UEORS)
- Document ID
- Society of Petroleum Engineers
- SPE International Heavy Oil Conference and Exhibition, 10-12 December, Kuwait City, Kuwait
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 5.5.8 History Matching, 5.2 Reservoir Fluid Dynamics, 5.4 Improved and Enhanced Recovery, 5.3.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.10 Microbial Methods, 7 Management and Information, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.4.1 Waterflooding, 5.5 Reservoir Simulation, 5 Reservoir Desciption & Dynamics, 5.4 Improved and Enhanced Recovery, 7.2 Risk Management and Decision-Making
- Heavy Oil, Kuwait, Sandstone Reservoir, Geochemical Modeling, Polymer Flooding
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The Umm Niqa Lower Fars (Heavy Oil Field) oil reservoir has very favorable properties of high permeability, low temperature, and moderate oil viscosity for polymer flooding and work is progressing towards implementing a polymer pilot in this target reservoir. Nonetheless, Heavy Oil Field contains high salinity water, it is shallow with concerns about injectivity limitations, and high concentrations of H2S (up to 5 mol% in reservoir fluids) which may adversely impact the effectiveness of the injected polymer solutions. A comprehensive laboratory and numerical modeling was initiated to address some of these issues. One potential concern is the degradation of polymer in the co-presence of H2S and possible oxygen introduced with polymer solution injection. This study is aimed at evaluating the impact of H2S on polymer performance in the Heavy Oil Field reservoir via geochemical simulations based on laboratory data.
Previously performed polymer rheology and transport experiments were history matched and model parameters were developed for subsequent simulations. Transport behavior of both HPAM type and biopolymers was modeled incorporating two new features of viscous fingering and filtration models.
This was then followed by a geochemical simulation study to assess and potentially de-risk the presence of H2S near the wellbore assuming that all oxygen in the injection water (if any) is rapidly consumed by reservoir rock minerals and oil.
The parameters developed for the rheology of the polymers were very robust and represented the effects of salinity and polymer shear thinning over a wide range of polymer concentrations for each polymer. These parameters were then used to conduct simulation studies on waterflooding and polymer flooding in the presence of near wellbore H2S. Sensitivity simulations to relative permeability/wettability, oil viscosity, polymer concentration were also conducted to identify the impact on injectivity of polymer solution. The use of the newly added viscous fingering and filtration models was necessary in some cases to correctly model the transport behavior of unstable displacements. Geochemical evaluation showed that injecting H2S-free water over a period of ~3 months can significantly reduce H2S concentration in the near-wellbore region (~30 ft) due to stripping from the oil phase. This is advantageous for the injected polymer because even if small oxygen concentration is co-injected with the water, there would be no H2S present to cause polymer degradation.
This study presents a practical approach to de-risk the deployment of polymer flooding in a highly sour shallow sandstone heavy oil reservoir. The findings of this study will be evaluated in a one-spot EOR pilot soon.
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