• Skeans, Elii
• Dean, Elio S.
• Al-Murayri, Mohammed T.
• Al-Qattan, Abrar
• Hassan, Abrahim Abdelgadir
• Al-Ghanim, Wafaa
• Andrianov, Alexey
• Jadhav, Prakash
• Kakade, Shweta
• Banerjee, Anirban
• Liu, Echo
• Pitts, Malcolm J.

Abstract

<jats:title>Abstract</jats:title><jats:p>This paper sheds light on the design and field results of a strategic Long-Term Polymer Injectivity Test (LTPIT) to de-risk phased commercial polymer-flooding in the largest sandstone field worldwide in pursuit of production acceleration, reserves growth and cost optimization. Effluent water with up to 170,000ppm TDS was used in conjunction with a pre-selected sulfonated polymer to evaluate injectivity at multiple rates and polymer concentrations under sub-fracturing conditions. Reservoir parting pressure was judiciously estimated to be around 2,500 psi. Polymer and water injected below parting pressure flowed into and through the Wara reservoir matrix as evidenced by the increase in downhole pressure with increasing injection rate in line with Darcy’s law. Polymer solutions expressed in-situ viscosities of up to 2.75 cP when injected below fracture parting pressure while displaying pseudoplastic flow characteristics. Water on the other hand displayed Newtonian behavior. Polymer adsorption onto the Wara formation developed a residual resistance factor of 1.17 for an effective water permeability reduction of approximately 20%. Polymer injection evidently improved reservoir conformance and resulted in more uniform zonal intake. Injected fluid distribution between 4,693 to 4,706 ft decreased from 85% to 71% and injection out of this depth range increased from 3% to 15.5%. Step rate testing with varying polymer concentrations evinced that increasing polymer concentration will decrease injection rate and, therefore, the duration of any mobility control polymer flood in the Wara reservoir will be affected by polymer concentration. A dynamic model was developed using CMG STARS and calibrated to wellbore petrophysics, polymer concentrations, downhole pressures, injection rates and pertinent surveillance/monitoring data. Numerical simulation sensitivity analysis indicates that 1800 ppm of the pre-selected sulfonated polymer (ZLPAM 40520), dissolved in effluent water, is the optimal concentration with 0.8 PV of injection being the optimal injected volume in terms of oil recovery and project economics. The benefits associated with polymer injection in terms of production acceleration, incremental recovery and cost optimization can be significantly increased by fast-tracking polymer injection using optimal well configuration. Performance forecasts using field data demonstrated that polymer injection has the potential to considerably reduce water-handling requirements, thus resulting in major cost savings. Furthermore, assuming an oil price of $80/bbl, drilling additional wells to establish 40-acre spacing for polymer injection can result in 9.4% incremental recovery at a Unit Technical Cost (UTC) of 19.3 $/bbl inclusive of the cost associated with polymer, additional wells, surface facilities, operations and maintenance. The results of this strategic field trial establish the techno-economic feasibility of phased commercial polymer-flooding in the Wara reservoir of the Greater Burgan field in Kuwait.</jats:p>

Topics

• impedance spectroscopy
• surface
• polymer
• mobility
• simulation
• permeability