One-Spot Oil De-Saturation Evaluation in the Sabriyah Lower Burgan Sandstone Formation Testing an Alkaline-Surfactant Formulation and Interpretative Translation to Alkaline-Surfactant-Polymer Oil Recovery Potential
Authors: Al-Murayri Mohammad T. , Al-Kharji Anfal A. , Al-Mayyan Haya E. , Pitts Malcolm , Wyatt Kon , Dean Elio 
Published: November 2018

Abstract
A Single Well Chemical Tracer Test (SWCTT) was performed in the Sabriyah Lower Burgan reservoir to provide an estimate of alkaline-surfactant-polymer (ASP) flood viability. Only an alkaline-surfactant (AS) solution was injected. As a result, oil de-saturation results for an ASP solution needed to be estimated to provide oil recovery potential to decide whether to proceed to a multi-well pilot. The SWCTT had a test radius of approximately 23 ft with a pore volume of 500 bbls. Three pore volumes of water were injected prior to determining the waterflood residual oil saturation. Injection was at a much lower rate and higher pressure than was observed with subsequent production of water. As a result, water injection was suspended and three acid jobs were performed. Water was then injected for eight pore volumes followed by SWCTT oil saturation determination. Oil saturation at waterflood residual was 35 % PV. An AS solution, totaling 1.2 pore volumes, was then injected which reduced the residual oil saturation to 27 % PV. Numerical simulation matched the SWCTT performance in SA-Well A; waterflood residual oil saturation of 36 % PV and AS residual oil saturation equal to 28 % PV were achieved. Injection of ASP solution instead of AS indicated an additional oil saturation reduction to 20 % PV. Waterflood residual oil saturations from constant rate laboratory linear corefloods with live and dead crude oil averaged 42 % PV and 40 % PV, respectively. Dead crude oil linear coreflood mimicking the injection sequence of the SWCTT resulted in AS solution reducing oil saturation from a waterflood residual of 35 % PV to 34 % PV. Injection of ASP solution further reduced the oil saturation to a final oil saturation of 17 % PV. Live crude oil linear corefloods with ASP injection after waterflood reduced oil saturation to 12 % PV. Constant pressure linear corefloods with dead crude oil waterflood residual oil saturation was 43 % PV and a subsequent ASP injection sequence reduced the oil saturation to 12 % PV. Coreflood and numerical simulation extrapolations suggest that if polymer was included with the AS solution in the SWCTT, oil saturation in SA-Well A Lower Burgan could have been reduced to 17 % PV or lower.
Well injection rates were much lower than production rates. Injection rate was 550 bbl/day at 4600 psi downhole pressure while the well brine production rate was up to 2400 bbl/day. Low injectivity was observed during initial seawater injection, which resulted in reducing the proposed SWCTT test pore volume and elimination of polymer from the chemical formulation. Expected bottomhole pressure was 3200 psi while actual bottomhole pressure was 3800 psi, the original reservoir pressure. A conceptual mechanistic model of the Sabriyah Lower Burgan with the high reservoir pressure concluded that the lower injectivity was not caused by microscale rock properties but by the presence of a steady state boundary (constant pressure boundary) in close proximity to the evaluated well.