Enhanced oil recovery (EOR) techniques can significantly extend global oil reserves once oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average oil recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR.

Core flood and field tests have demonstrated that decreasing injection water salinity increases oil recovery from sandstone reservoirs. However, the microscopic mechanism behind the effect is still under debate. One hypothesis is that as salinity decreases, expansion of the electrical double layer decreases attraction between organic molecules and pore surfaces. We have developed a method that uses atomic force microscopy (AFM) in chemical force mapping (CFM) mode to explore the relationship between wettability and salinity. We functionalised AFM tips with alkanes and used them to represent tiny nonpolar oil droplets. In repeated measurements, we brought our “oil” close to the surface of sand grains taken from core plugs and we measured the adhesion between the tip and sample. Adhesion was constant in high salinity solutions but below a threshold of 5,000 to 8,000 ppm, adhesion decreased as salinity decreased, rendering the surface less oil wet. The effect was consistent, reproducible and reversible. The threshold for the onset of low salinity response fits remarkably well with observations from core plug experiments and field tests. The results demonstrate that the electric double layer force always contributes at least in part to the low salinity effect, decreasing oil wettability when salinity is low.

The effects of interfacial tension (IFT) upon gas-oil relative permeabilities are of considerable interest in the reservoir engineering of gas flooding processes. Several papers have presented experimental data on this matter, although there is some conflict among the findings of different authors. This paper describes the development and implementation of an unsteady-state pore-scale process simulator, which has been utilised to interpret a number of related laboratory gas-oil displacements performed at different values of interfacial tension. The experimental work was carried out at this laboratory and the range of IFTs considered covered almost three orders of magnitude - from 9.76mN/m down to 0.019mN/m. However, more importantly, all of the experimental data was available to the authors including the oil/gas viscosity ratio, M (= oil/ gas), as a function of IFT. This proved to be essential in the modelling and interpretation of the experimental results and it has rarely been reported by previous experimentalists. Both constant rate and constant pressure drop simulations were carried out, using pore-scale models that had been suitably anchored to the experimental samples. The resulting production data were analysed using a modified JBN technique and the calculated relative permeabilities were found to exhibit the same IFT sensitivities as the experimental datasets - viz. a marked increase in the gas curve and very little change in the oil curve with decreasing IFT. This behaviour is subsequently explained by considering both the viscous/capillary force balance and the viscosity ratio operating during each displacement. These vary considerably over the experimental range considered, with different displacements effectively lying in different flow regimes. In addition, results demonstrate that it is extremely difficult to predict a priori the directional trend exhibited by relative permeability curves with varying IFT, unless all of the experimental quantities are reported. The fact that both capillary number and viscosity ratio play a role in determining the phase distributions during a displacement means that such trends can only be properly understood in light of appropriately-scaled network simulations that incorporate the underlying pore-scale physics. Introduction Variations in gas-oil relative permeability as a function of interfacial tension (IFT) are of particular importance in the area of compositional simulation, where oil and gas compositions can vary significantly both spatially and temporally. This is especially significant in the context of volatile oil and gas condensate reservoirs, where phase compositions do not generally pass through the critical point and miscibility is consequently avoided. At present, many standard compositional simulators utilise a model first proposed by Coats, which employs simple linear interpolation to modify the relative permeability curves at different values of IFT. The interpolated relative permeabilities take the form: (1) P. 791^

Summary Core tests demonstrated that decreasing the salinity of injection water can increase oil recovery. Optimizing injection-water salinity, however, would offer a clear economic advantage for several reasons. Too-low salinity risks swelling of the clays that would lead to permanent reservoir damage, but evidence of effectiveness with moderate-salinity solutions would make it less difficult to dispose of produced water. The goal is to define boundary conditions so injection-water salinity is high enough to prevent reservoir damage and low enough to induce the low-salinity (LS) effect, while keeping costs and operational requirements at a minimum. Traditional core-plug testing for optimizing conditions has some limitations. Each test requires a fresh sample; core-testing requires sophisticated and expensive equipment; and reliable core-test data require several months because cores must be cleaned, restored, and aged before the tests can begin. It is also difficult to compare data from one core with results from another because no two cores are identical, making it difficult to distinguish between effects resulting from different conditions and effects resulting from different cores. Gathering statistics is limited by the time required for each test and the fact that core material is in short supply. Thus, our aim was to explore the possibility of a less-expensive, faster alternative by probing the fundamental chemical mechanisms behind the LS effect. We developed a method that uses atomic-force microscopy (AFM) to investigate the relationship between the wettability of pore surfaces and water salinity. We functionalize AFM tips with organic molecules and use them to represent tiny oil droplets of nonpolar molecules, and we use sand grains removed from core plugs to represent the pore walls in sandstone. We bring our “oil”-wet tip close to the sand-grain surface and measure the work of adhesion between the tip and the surface. Repeated probing of the surface with the tip produces data that one can convert to maps of adhesion, and we can estimate contact angle. Adhesion work is proportional to wettability and is directly correlated with the salinity of the fluid in contact with the tip and the particle surface. From our measurements, the threshold values for the onset of the LS response are 5,000 to 8,000 ppm, which benchmark remarkably well with observations from core-plug tests. From a mechanistic perspective, the correlation between salinity and adhesion provides evidence for the role of electrical-double-layer (EDL) expansion in the LS response; expansion of the double layer decreases oil wettability. Because AFM experiments can be performed relatively quickly on very little material, they give the possibility of testing salinity response on many samples throughout a reservoir and for gathering statistics. Our approach provides a range of data that one can use to screen conditions to maximize the value of the core-plug testing and to provide extra data that would be too time consuming or too expensive to gather with traditional methods alone. Thus, AFM force mapping is an excellent complement to traditional core-plug testing.

Numerical prediction of rock properties is a rapidly evolving area that has the potential to influence dramatically how core analysis is performed. In this paper, we investigate the numerical prediction of relative permeability from micro-computed tomographic images using pore network modeling. Specifically, we apply four different algorithms to a digital image of a reservoir sample that has been tested using traditional core analysis, and compare the results. The four algorithms are the following: quasi-static, unsteady-state, steady-state periodic, and steady-state non-periodic. They differ significantly in terms of the physics that they are designed to capture and their computational performance, but there is no published research quantifying how these differences affect the simulation of relative permeability. We show that the traditional quasi-static algorithm exhibits outstanding computational performance, but gives results that are the most different from the other three methods. The unsteady-and steady-state simulations give surprisingly similar results given the differences in how relative permeability is obtained. The two steady-state methods differ little under the conditions tested. This result is encouraging because the periodic simulation is significantly more computationally efficient. However, it raises questions about the ability to capture hysteretic behavior. Phase saturations are mapped from the network results onto the digital images of the pore space as a means to help interpret differences in the pore-scale behavior of the models. Finally, results are compared to relative permeabilities from laboratory corefloods.