Designing and Injecting a Chemical Formulation for a Successful Off-Shore Chemical EOR Pilot in a High-Temperature, High-Salinity, Low-Permeability Carbonate Field
- David Levitt (Total) | Alexandra Klimenko (Total) | Stephane Jouenne (Total) | Nicolas Passade-Boupat (Total) | Philippe Cordelier (Total) | Danielle Morel (Total) | Maurice Bourrel (Total)
- Document ID
- Society of Petroleum Engineers
- SPE Improved Oil Recovery Conference, 11-13 April, Tulsa, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2016. Society of Petroleum Engineers
- 2 Well completion, 5.3.2 Multiphase Flow, 1.6 Drilling Operations, 2.4 Hydraulic Fracturing, 5 Reservoir Desciption & Dynamics, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.7 Carbonate Reservoir, 4.3.4 Scale, 1.6.10 Coring, Fishing, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations, 5.7.2 Recovery Factors, 5.3.4 Reduction of Residual Oil Saturation, 5.7 Reserves Evaluation, 5.8 Unconventional and Complex Reservoirs, 5.2 Reservoir Fluid Dynamics
- Polymer, Surfactant, Carbonate, Temperature, Salinity
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- 415 since 2007
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This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology.
A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity.
The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush.
Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%, Al-Amrie et al., 2015), suggesting that the reason for the lower recovery in reservoir cores was in fact due to the short core length with respect to the mixing zone, as suggested in a previous publication (Levitt et al., 2012).
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Adkins, S., Liyanage, P. J., Pinnawala Arachchilage, G. W. P., Mudiyanselage, T., Weerasooriya, U. and Pope, G. A. (2010). "A New Process for Manufacturing and Stabilizing High-Performance EOR Surfactants at Low Cost for High-Temperature, High-Salinity Oil Reservoirs." Paper SPE 129923 presented at the SPE Improved Oil Recovery Symposium, 24-28 April 2010, Tulsa.
Al-Amrie, O., Peltier, S., Pearce, A., Al-Yafei, A., Morel, D., Bourrel, M., … & Klimenko, A. (2015, November). The First Successful Chemical EOR Pilot in the UAE: One Spot Pilot in High Temperature, High Salinity Carbonate Reservoir. In Abu Dhabi International Petroleum Exhibition and Conference. Society of Petroleum Engineers.