This paper reviews the effect of brine composition on LoSalTM EOR waterflood recovery. An improved understanding of the LoSalTM mechanism is presented. Corefloods and single-well tracer tests were performed to evaluate the mechanism and quantify recovery benefits. It was determined that recovery is a function of water chemistry and formation mineralogy. Project economics are significantly enhanced by injecting a slug of low salinity water versus continuous injection. It was determined that a 40% slug by pore volume is fully effective. The work presented in this paper was done to quantify tertiary LoSalTM EOR benefits at the Endicott field located on the North Slope of Alaska. An interwell test is currently underway to unambiguously measure LoSalTM EOR response at field scale. Background The effect of brine composition on waterflooding was first documented by Jadhunandan in 19901 and by Jadhunandan and Morrow in 19912. The first published single well chemical tracer test (SWCTT) results were presented by Webb et al in 20043, and by McGuire et al in 20054. In the past few years numerous core measurements and field tests have been performed at the Endicott Field (Figure 1). A better understanding of the LoSalTM mechanism and encouraging results from field tests at Endicott are evidence that LoSalTM is an emerging EOR technology Endicott was brought on line in 1987. It is a mature offshore oil field located on the North Slope of Alaska. Endicott has been produced with crestal gas re-injection and peripheral water injection. Approximately 10 percent of the produced gas has been used for fuel. Produced reservoir water has been re-injected. Voidage replacement has been accomplished with sea water injection. The salinity and hardness of the reservoir water and the sea water are approximately equal. Current production is 13 Mbpd of oil and 2 Mbpd of NGL. Average water cut is 90% and average GOR is 20,000 scf/stb. To date, 128 wells, including 24 sidetracks have been drilled. Currently 56 producers and 26 injectors are active.

This paper describes the first comprehensive inter-well field trial of low-salinity EOR. The objective of the trial was to demonstrate that reduced-salinity waterflooding works as well at inter-well distances as it does in corefloods and single well tests. The trial was designed to evaluate two risks: 1) whether mixing or other mechanisms prevent achievement of reduced-salinity improved recovery in the reservoir and 2) whether the adverse mobility ratio between the injected water and the oil bank causes viscous fingering – resulting in mobilized oil being left behind. The demonstration was implemented in a single reservoir zone at the Endicott field (North Slope Alaska). The trial involves an injector and a producer 1040 feet apart. The producer was monitored for changes in watercut and ionic composition. In December 2007, produced saline water was injected to pre-flood the pattern until watercut was over 95%. Reduced-salinity water injection commenced June 2008. The associated EOR response was detected in the producer after three months. Data from a wellhead watercut meter and fluid samples from a test separator both revealed a clear drop in watercut, from 95% to 92%. The timing of the drop in watercut coincided with the breakthrough of reduced-salinity water at the producer. Incremental reduced-salinity EOR oil recovery timing and volume matched behaviors observed in corefloods and single well tests. By May 2009, 1.3 pore volumes of reduced-salinity water had been injected. The incremental oil recovery is equal to 10% of the total pore volume in the swept area. Initial oil saturation at Endicott is 95%. In the pilot area, tertiary reduced-salinity waterflooding is expected to drop residual oil saturation from 41% to 28%, a 13 unit drop in residual oil. The inter-well field trial demonstrates that the identified risks did not impact performance.

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Miscible injectant (MI) has been injected at Prudhoe Bay and its satellite fields for over 30 years. Since 1982, more than three trillion cubic feet of MI has been injected and over 300 million barrels of oil has been produced through this enhanced oil recovery (EOR) technique. Since MI is a finite resource, the allocation of MI across all the fields in the Greater Prudhoe Bay (GPB) area, as well as the distribution of MI to various injection patterns in each field, must be managed methodically to optimize oil recovery.This paper provides an overview of all EOR projects at GPB and presents the process and methodology for MI allocation to these projects and to individual injection patterns. A new approach is used to determine the amount of MI allocated to each project based on predicted marginal MI utilization per barrel of EOR oil. The marginal MI utilization of each project is predicted using a COBRA model. COBRA is a full-field scale-up tool for predicting MI performance based on type pattern simulation model results. This paper will discuss the allocation approach used to compare the marginal MI utilization among various projects to determine the optimum MI allocation. The volume of MI allocated to each project is then distributed to the various injection patterns following a pattern ranking process. A new ranking index is proposed to combine a pattern's maturity and efficiency, so that a single indicator can be used to rank injection patterns in order to optimize the utilization of the limited MI resource.