A wide range of outcrop sandstones and carbonates have been tested for waterflood response to one twentieth dilution of synthetic seawater, using a single crude oil that gave high response to low salinity flooding for a reservoir rock. The tested outcrop rocks included 17 sandstones and 6 carbonates. Gas permeabilities ranged from 1.49 to 7,187 mD and porosities from 10 to 39%. The average reduction in residual oil for tertiary response was only 1.5% OOIP with the highest being 5.8% OOIP; some rocks showed no response. After testing, three of the outcrop rocks that responded to injection of low salinity brine were restored by cleaning and re-aging with crude oil using procedures comparable to those commonly used in restoration of reservoir cores. When re-tested, the response to low salinity flooding was eliminated for two of the cores and significantly reduced for the third core. Companion plugs for 6 of the sandstones and 3 carbonates were tested for increased oil recovery using low salinity connate and injected brine; this data provided comparison with the measurements for high salinity connate and injection brine. Six of the plugs showed increase in recovery for the low salinity waterfloods, and three showed decrease. Results are also summarized for the effects of reduction in salinity for 11 sandstone cores taken from five reservoirs and 8 carbonate cores all taken from the same reservoir. Comparison between results for outcrop and reservoir cores, including literature data, indicates that overall response to low salinity flooding is significantly higher for the reservoir cores.

The spreading of multi-component oils on water has been investigated by direct observations and predicted from measurements of the interfacial tensions and surface tensions of decane, toluene, heptane, and their mixtures. Pure decane does not naturally spread at ambient conditions, as indicated by its negative spreading coefficient. However, when decane is mixed with toluene and heptane, the mixture spreads on water over a wide range of compositions. The spreading coefficients are highly nonlinear with respect to concentration and feature a maximum. The spreading is ascribed to preferential accumulation of toluene at the oil/water interface and heptane at the oil/vapor interface. Molecular dynamics simulations corroborate the hypothesis of preferential accumulation. The accumulation of lighter alkanes at the oil/vapor interface reduces the surface tension, and the accumulation of aromatics at the oil/water interface decreases the interfacial tension. As a consequence, the oil mixture spreads over water.

High-pressure solutions of polystyrene-block-polybutadiene and polystyrene-block-polyisoprene in compressible propane or propylene exhibit a robust micellar region that grows in pressure-temperature coordinates with increasing copolymer concentration, molecular weight, and styrene/diene block ratio. This happens because, while the micellization pressure strongly increases with increasing copolymer concentration, molecular weight, and styrene/diene block ratio, the micellar cloud pressure (the pressure at which the micelles aggregate and precipitate from solution) is largely insensitive to these variables. In other words, neither the block size nor the block ratio nor the copolymer concentration seems to affect much the copolymer separation from solution in the micellar region.

Micellar solutions of polystyrene-block-polybutadiene and polystyrene-block-polyisoprene in propane are found to exhibit significantly lower cloud pressures than the corresponding hypothetical nonmicellar solutions. Such a cloud-pressure reduction indicates the extent to which micelle formation enhances the apparent diblock solubility in near-critical and hence compressible propane. Concentration-dependent pressure-temperature points beyond which no micelles can be formed, referred to as the micellization end points, are found to depend on the block type, size, and ratio. The cloud-pressure reduction and the micellization end point measured for styrene-diene diblocks in propane should be characteristic of all amphiphilic diblock copolymer solutions that form micelles in compressible solvents.

Micelles of hydrophilic−hydrophobic block polymers, such as poly(ethylene glycol)−block-poly(ϵ-caprolactone) (PEG−b-PCL), used as drug-delivery carriers, are generally fabricated via solvent displacement or dialysis, which is time-consuming, requires freeze drying, and can leave toxic traces of the residual organic solvents. An alternative is presented in this paper: form micellar PEG−b-PCL nanoparticles in a supercritical fluid solvent and then disperse them in water toward a water-dispensable formulation. This method is illustrated with pressure−temperature phase diagrams for PEG−b-PCL in supercritical trifluoromethane, which is selective enough for the PCL and PEG blocks to induce micellization. When subjected to decompression to remove trifluoromethane, dry and organic solvent-free nanoparticles are readily obtained. Their micellar structure is immediately reestablished in water, as confirmed by laser light scattering. Neither has been demonstrated previously.

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Increased secondary and tertiary oil recovery by low salinity water flooding has attracted widespread interest as a low cost improved oil recovery method. Field applications that give increased recovery by over about 2% OOIP are considered economically viable. Although the number of reported laboratory and field investigations is now approaching 200, no consistent conclusions have been reached as to the circumstances under which recovery is improved. Laboratory core floods provide a practical approach to investigation of necessary conditions for improved recovery. In seeking responsive rocks for investigation of recovery mechanisms, 19 sandstones were screened for low salinity effect (LSE) through decrease in residual oil after injection of dilute brine (LSE @Sor). The highest recovery given by a definitive bump in recovery, as opposed to small increase in oil cut, was 5% OOIP. Three rock types, Castle Gate, Berea Stripe, and Briar Hill, were selected for further study because of relatively high response. After the originally tested core plugs were cleaned and restored, two of the plugs gave robust residuals to high salinity flooding and no LSE @Sor; the third gave very high recovery by high salinity flooding but much reduced response to LS brine. Reproducibility of recovery behavior was tested for pairs of sister plugs. For all three core types, average LSE @Sor, if any, was much lower than the recoveries that led to their selection. The best performing sandstone, Briar Hill, was then tested further with sets of cores being taken from two additional quarried blocks, each weighing about 10 tons. None of the cores cut from these blocks gave significant tertiary response. The average recovery for outcrop rocks is much lower than the average for reservoir rocks. An unexpected conclusion from the study is that, because of the generally low response, outcrop rocks provide numerous examples of very little or no LSE @Sor.

The Greater Burgan Field, first discovered in 1938, is the second largest oilfield in the world. Production from the Greater Burgan began in 1946 from the Wara reservoir via primary recovery. Recently, field-wide waterflood as a secondary recovery mechanism has been implemented. The current insight on the potential of hybrid low salinity water and polymer flooding in the Greater Burgan is presented. The goal of the Greater Burgan Study team in this enhanced oil recovery (EOR) evaluation program was to compare the benefits of using low salinity waterflood (LSW) and low salinity polymer (LSP) injection as tertiary oil recovery methods in the Wara sandstone reservoir of the Greater Burgan field. The efficacy of low salinity and low salinity polymer injection has been investigated in the laboratory and by conducting a series of single-well chemical tracer (SWCT) tests in one Wara producer. In the field trial carried out on Well A, three separate determinations of residual oil saturation (Sor) were made. The first SWCT test measured waterflood Sor after injecting a slug of high salinity water (HSW) that is compositionally comparable to the produced water utilized field-wide for waterflooding operations. The second and third SWCT tests measured the remaining oil saturation after LSW and LSP, respectively. Laboratory corefloods were also performed to evaluate LSW and LSP recoveries and their impacts on injectivity. The injection water salinity, injection design, oil viscosity, and polymer viscosity used in the laboratory experiments were identical to those used in the field SWCT tests. These SWCT test trial results establish a baseline waterflood Sor (i.e., after high salinity water injection) and show that further reductions in Sor may be achieved with low salinity waterflooding and low salinity polymer injection. The laboratory results showed no plugging or injectivity issues during LSW or LSP corefloods. Overall, LSW and LSP were shown to be technically workable tertiary processes in the Greater Burgan.