To evaluate fluid recovery and resulting regain of methane permeability with a range of water-and hydrocarbon-based fluids, some involving the use of CO 2 or nitrogen, specialized core-testing procedures have been developed (Figs. 1 and 2).In general, core samples representing average-or better-quality reservoir matrix are used for the testing because these are the portions of the reservoir that will experience the greatest degree of invasion and leakoff during the highly overbalanced fracturing process and are also the zones from which the majority of potential production will be sourced.There are several key points that differentiate this from common core testing with water-based fluids:• Because phase behaviour is an integral part of the cleanup mechanism, downhole pressures and temperatures must be accurately simulated. This can require pressures of 70 MPa or greater and temperatures higher than 100º`C.• A key objective is a representative comparison of hydrocarbonand water-based systems. This being the case, use of methane (or a simulated reservoir gas containing all of the light-and heavy-gas phase hydrocarbon components) rather than nitrogen is used as the reference for regained permeability to achieve meaningful results. The solubility of methane in hydrocarbons is much greater than the solubility of nitrogen, resulting in a much lower interfacial tension (IFT) at a given pressure level. This allows methane to more effectively displace hydrocarbons. Specialized equipment is required to safely pump methane at high pressures and accurately measure flow rates. AbstractThe Montney gas reservoir has become a critically important component of current western Canadian gas supply and offers exciting future potential. However, this reservoir often presents variable and unique stimulation challenges. Unlike reservoirs that display little water sensitivity, such as the U.S. Barnett Shale and possibly the Muskwa in the Northeastern British Columbia Horn River Basin, recovery of water-based fluids in the Montney can be a key consideration in achieving economic production rates.The use of water-based fracturing fluids in low-permeability reservoirs can result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid to the formation. This problem is increased by the water-wet nature of most tight-gas reservoirs (where no initial liquid-hydrocarbon saturation is or ever has been present) because of the strong spreading coefficient of water in such a situation.The retention of increased water saturation (Sw) in the pore system after the injection of water-based completion fluids can restrict the flow of produced gaseous hydrocarbons, such as methane. Capillary pressures of 10 MPasy-20 MPa, or much higher, can be present in low-permeability formations at low-water saturation levels. Inability to generate sufficient capillary-drawdown force using the natural reservoir-drawdown pressure can result in extended fluid-recovery times or permanent loss of eff...

The Neogene of North Kuwait comprises of unconsolidated sandstone reservoir having viscous crude. The field is to be developed by way of injecting steam into the reservoir. The XRD and SEM studies revealed that variety of the detrital clay minerals like Illite, Smectite, Chlorite, and Palygorskite commonly occurring within the formation. An experimental study was carried out to understand the implications of steam injection on the clay bearing formations and to determine temperature-dependent water-oil relative permeability to provide an indication of the recoverable reserves under steam injection. Sensitivity to different pH and salinity were also analyzed.Detailed laboratory study was conducted on nine plugs to determine the effect of hot water and steam injection on the permeability, relative permeability, residual oil saturation and mineralogical changes in the reservoir. The baseline steamflood was carried out to determine the residual oil saturation and evaluate the permeability changes due to clay swelling/dispersion in contact with brine and steam. The other six sensitivity steamfloods were carried out to determine the potential permeability damage resulting from clay swelling/dispersion when contacted with different pH fluid, salt concentrations (TDS) and clay stabilizers. Pre and post XRD and SEM analysis were done to see the effects of each steamflood on the core sample.This paper presents the discussion on results of core flood experiments conducted on nine preserved core samples at reservoir conditions. The results show that clays when contacted with steam induce significant permeability reduction. High salinity and pH control may not be sufficient to eliminate the loss of permeability. However, some clay stabilizers are found to be useful to improve the permeability and recovery.

Canada ranks third in the world in terms of oil reserves which are primarily heavy oil and oil sands. In situ production of heavy oil and bitumen by thermal methods based on steam injection is a commercial technology. However, as the availability of better quality deposits is declining, the industry is moving towards development of lower quality oil sands. Lower quality oil sands are typically finer, have lower initial oil saturation and a more complex mineralogy. Thermal formation damage associated with steam injection is discussed in the paper in regards to oil sands located in the Lower Cretaceous formations in Western Canada. The focus of the paper is the McMurray, Clearwater and Grand Rapids oil deposits. Petrographic data (thin section analysis, X-ray diffraction and scanning electron miscroscopy) and physical rock properties are used to compare three oil sand formations. Results of laboratory experiments to obtain relative permeability data and evaluate thermal formation damage are discussed. Examples of the high temperature-high pressure water-oil relative permeability and steamflood data for three formations are presented. The paper shows that thermal formation damage is reservoir specific. A multidisciplinary approach is needed to obtain a good understanding of oil sand deposits, in particular lowerquality reservoirs. Laboratory testing to evaluate formation damage effects and obtain relative permeability data is essential for reservoir simulation and feasibility studies for a specific project.