Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

Abstract

Abstract Laboratory studies conducted over a period of many years have indicated that oil recovery could be improved by injecting lower salinity water (less than about 5,000 ppm). Although the recovery mechanisms are still uncertain, they appear to be similar to those found in alkaline flooding. Recent successful field trials have led to serious evaluation of field-scale implementation of low salinity EOR. Four sets of single well chemical tracer tests (SWCTT) performed in Alaska confirmed that the favorable laboratory results could be replicated in the field. The SWCTT results (two in the Ivishak sandstone, one each in the Kuparuk and Kekiktuk sandstones) showed that waterflood residual oil saturation (Sorw) was substantially reduced by low salinity water injection. The low salinity EOR (LoSal) benefits ranged from 6 to 12% OOIP, resulting in an increase in waterflood recovery of 8 to 19%. Based on these encouraging results, low salinity oil recovery is being actively evaluated for North Slope reservoirs. Background Research into wettability impacts on oil recovery has shown that many properties of the injected water affect the amount of oil recovered. One consistent trend has emerged; the lower the salinity, the higher the oil recovery. Numerous laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water.1–6 Many of these academic studies were conducted using core material and crude oil from a BP North Sea reservoir. The increase in oil recovery for low salinity water injection from this North Sea reservoir ranged from 10 to 40%. Recently, near-well field testing confirmed that waterflood displacement efficiency can, under specific circumstances, be increased by reducing the salinity of the injected water. A Log-Inject-Log test (LIL) was conducted in the Middle East to evaluate LoSal benefits (see Fig. 1).7 The results were in line with laboratory tests from other fields, and showed a 25 to 50% reduction in Sorw when waterflooding with low salinity brine. Single well chemical tracer tests performed in Alaska (described later in this paper) resulted in reductions in remaining oil saturation of 6 to 12% OOIP, which increased waterflood recovery by 8 to 19%. Low Salinity Oil Recovery Corefloods Low salinity oil recovery is an enhanced oil recovery method consisting of the intentional injection of water containing low concentrations of total dissolved solids into the reservoir. Numerous laboratory coreflood studies have been conducted to compare waterflood performance of simulated formation water and low salinity water. A typical experimental dataset using Berea sandstone and crude oil and formation brine from a BP-operated North Sea field (BPNS2) is shown in Fig. 2. This comparison showed major production benefit between floods with the original BPNS2 formation water (15,000 ppm, with composition shown in Table 1) and reduced salinity waterflood cases. Flooding with low salinity water (in this experimental dataset, a flood at 1,500 ppm TDS and a flood at 150 ppm TDS) improved crude oil recovery from 56% OOIP for the 15,000 ppm case(100% BPNS2 brine) up to 64% OOIP for the 1,500 ppm case (10% BPNS2 brine). The ultra-low salinity flood at 150 ppm TDS (1% BPNS2 brine) showed oil recovery increasing all the way up to 73% OOIP. This represents a 30% increase in oil production compared to the high salinity flood with 15,000 ppm formation water. It should be noted that in each of these floods, the connate brine had the same composition as the invading brine.