The effect of pore-structure upon two-phase relative permeability and capillary pressure of strongly-wetting systems at low capillary number is simulated. A pore-level model consisting of a network of pore-bodies interconnected by pore-throats is used to calculate scanning loops of hysteresis between primary drainage, imbibition and secondary drainage. The pore-body to pore-throat aspect ratio strongly influences the pattern of hysteresis. Changes in the patterns of hysteresis often attributed to consolidation can be understood in terms of changes in aspect ratio. Correlation between the sizes of neighboring pore-throats affects the shape of the relative permeability curves, while the width and shape of the pore-size distribution have only a minor influence.
Summary This paper describes two- and three-phase relative permeability concepts important for Prudhoe Bay. It includes a three-phase relative permeability correlation that incorporates hysteresis in gas, oil, and water relative permeability as well as the dependence of relative permeability on composition and gas/oil interfacial tension (IFT). The functional forms chosen to correlate the relative permeability data were based on interpretation of the pore-level mechanisms that determine fluid flow. The three-phase correlation reduces to traditional models in various limits and is more consistent with available data and trends in the literature than previous correlations. Although this correlation was developed for Prudhoe Bay, it can be and has been applied to other mixed-wet reservoirs with changes in the input parameters. The correlation is particularly useful in situations where both compositional effects and hysteresis are important. Introduction The ultimate use of relative permeability models is to help design, optimize, and analyze oil-displacement processes. Clearly, relative permeability is just one part of the recovery picture; reservoir characterization, gravitational effects, phase behavior, and mass transfer processes among other factors all interact to determine the amount of oil that can be recovered economically. Nevertheless, relative permeability plays a central role. The primary impact of relative permeability on process design is through fluid mobilities and fractional flows. Total fluid mobilities determine the resistance to flow of the fluids and hence affect (1) injectivity and the overall timing of the process and (2) the severity of viscous fingering or channeling and the "robustness" of a process to heterogeneities in general. The fractional flows impact producing-water/-oil ratio, producing-gas/oil ratio, breakthrough timing, and ultimate and incremental recoveries. The magnitude and location of waterflood residual oil, the target for the enhanced oil recovery (EOR) process, is impacted by low-capillary-number relative permeability. Waterflood oil recovery is also affected by the presence of gas through its impact on water/oil relative permeability ratio as in immiscible water-alternating-gas (WAG)-processes or in waterflooding where oil was forced into regions previously invaded by an expanded gas cap. Residual oil to gas in gravity drainage is determined primarily by oil/gas relative permeability, which in turn is impacted by the level of initial water saturation. Although phase-behavior mechanisms (attainment of miscibility, stripping of oil by gas, or swelling of oil by gas) are important mechanisms in developed miscible flooding, capillary number effects could also play a role because the IFT between the oil and gas becomes low as miscibility is approached.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractLow salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is controlled to improve oil recovery over conventional higher salinity waterflooding. Corefloods and single well chemical tracer tests have shown that low salinity waterflooding can improve basic waterflood performance by 5 to 38%. This paper describes a model of low salinity flooding that can be used to evaluate projects, shows the implications of that model, demonstrates its use to represent corefloods and single well tests as well as field scale simulations, and gives insight into the reservoir engineering of low salinity floods.The model represents low salinity flooding using salinity dependent oil/water relative permeability functions resulting from wettability change. This is similar to other EOR modelling and conventional fractional flow theory can be adapted to describe the process in one dimension for secondary and tertiary low salinity waterflooding. This simple analysis shows that while some degree of connate water banking occurs it need not hinder the process. Because mixing of injected water with in situ water delays the attainment of low salinity, potentially preventing attainment of low salinity all together if very small slugs of low salinity water are used, care must be taken in representing mixing appropriately in interpreting data and in constructing models. The use of numerical dispersion to represent physical dispersion in 1D, radial and pattern simulations of this process is demonstrated, i.e. coarse simulations are shown to give the same result as fine grid simulations with appropriately large physical dispersion. In many applications, the fine grid simulation necessary to represent appropriate levels of dispersion is not practical and pseudoization is necessary. We demonstrate that this can be done by changing the salinity dependence and shapes of relative permeability curves.
The diffusion of water and ions in the interlayer region of smectite clay minerals represents a direct probe of the type and strength of clay−fluid interactions. Interlayer diffusion also represents an important link between molecular simulation and macroscopic experiments. Here we use molecular dynamics simulation to investigate trends in cation and water diffusion in montmorillonite interlayers, looking specifically at the effects of layer charge, interlayer cation and cation charge (sodium or calcium), water content, and temperature. For Na-montmorillonite, the largest increase in ion and water diffusion coefficients occurs between the one-layer and two-layer hydrates, corresponding to the transition from inner-sphere to outer-sphere surface complexes. Calculated activation energies for ion and water diffusion in Namontmorillonite are similar to each other and to the water hydrogen bond energy, suggesting the breaking of water−water and water−clay hydrogen bonds as a likely mechanism for interlayer diffusion. A comparison of interlayer diffusion with that of bulk electrolyte solutions reveals a clear trend of decreasing diffusion coefficient with increasing electrolyte concentration, and in most cases the interlayer diffusion results are nearly coincident with the corresponding bulk solutions. Trends in electrical conductivities computed from the ion diffusion coefficients are also compared.
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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