For over 10 years research has been carried out on the impact of low salinity waterflooding on oil recovery. Data derived from corefloods, single well tests, and log-inject-log tests have shown that injecting low salinity water into an oil reservoir should result in a substantial increase in oil recovery in many cases. The results varied from 2 to 40% increases in waterflood efficiency depending upon the reservoir and composition of the brine.In 2005, a hydraulic unit was converted to inject low salinity brine into an Alaskan reservoir, by switching a single injection pad to low salinity water from high salinity produced water. An injector well and 2 close production wells were selected within a reasonably well constrained area. A surveillance programme was devised which included capturing produced water samples at regular intervals for ion analysis and the capturing of production data.Detailed analysis of the production data, and the chemical composition of the produced water, demonstrated an increase in oil production and provided direct field evidence of the effectiveness of LoSal™ at inter-well scales. Additionally, the response of the reservoir to low salinity water injection was confirmed by single well chemical tracer test.In parallel, laboratory studies have led to mechanistic understanding of LoSal™ in terms of multiple-component ionic exchange (MIE) between adsorbed crude oil components, cations in the insitu brine and clay mineral surfaces. The results clearly show that the enhanced oil production and associated water chemistry response was consistent with the MIE mechanism proposed.The oil production data have been modeled using an in-house developed modification to Landmark's VIP TM reservoir simulation package. An excellent match for the timing of the oil response was obtained which provides a good basis for predicting the result for large scale application of LoSal™ flooding.

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.

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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.

Water injection has been used to increase oil recovery since the late 19 th century. For over 100 years, the mechanisms behind this incremental oil recovery have been thought of as physical, i.e. the injection of water maintains reservoir pressure and sweeps the mobilised oil to the producing well. In the last decade this premise has been questioned and through the development of BP's LoSal TM EOR technology, it is now recognised that oil recovery through waterflooding also involves chemical processes and that modifying the brine chemistry of the injection water can significantly impact the observed recovery.Several hypotheses regarding the mechanism involved with low salinity waterflooding have been discussed in the literature. In 2006, BP published a proposed mechanism for this phenomenon based upon multicomponent ion exchange (MIE) triggered by expansion of the electric double layer at the mineral surfaces that bind the oil. This paper describes on going research studies focused on advancing the understanding of these mechanisms using sophisticated physical chemistry techniques such as Small Angle Scattering using neutrons from the ILL facility in Grenoble, France and the ISIS facility at the Rutherford Appleton laboratory, UK and X-rays at the DIAMOND Light source, Oxon. These techniques are capable of measuring the thickness of any water layer at the mineral surface down to the Angstrom level.Results to date provide some support for the BP published mechanism. They have shown the presence of a thin water layer and its variation with changes in the salinity of the water medium at model silica and clay-like surfaces, with attached (model) polar oil components, suspended in oils. Furthermore, the impact of cation-type on the water-layer thickness has also been demonstrated.