Summary Thermal-recovery methods are commonly used for production of viscous crude oil. Injected hot fluids react with reservoir rock, and some of these reactions might result in a change to the reservoir mineralogy. Depending on the physicochemical conditions and initial mineralogy, some such alterations can lead to formation damage and flow-assurance issues. This paper investigates these mineral reactions, the conditions in which they occur, and the effects of these processes on porosity and permeability of sandstone rocks with various initial mineralogy. Quartz, calcite, dolomite, kaolinite, and montmorillonite were used for preparation of 12 rock samples of various mineralogical contents. These mixtures were packed and used for steam-injection experiments. Porosity and permeability of the initial and steamed sandpacks were determined using computed-tomography (CT) scans and coreflood experiments, respectively. Composition of the collected condensate samples was analyzed using inductively coupled plasma optical emission spectroscopy (ICP-OES). Rock mixtures were aged in high-pressure/high-temperature (HP/HT) cells. Rock morphology and pore-space configuration were studied using scanning-electron-microscope energy dispersive X-ray spectroscopy (SEM-EDS). Mineralogy of the samples was analyzed using X-ray-diffraction (XRD) analysis. Mixtures of quartz with calcite were found to be the least prone to formation damage associated with steam injection. Silica dissolution/precipitation reaction resulted in 5% initial permeability reduction and 1 to 2% initial porosity reduction. Mixtures of quartz, kaolinite, and carbonate minerals (calcite or dolomite) after steam injection lost 11 to 22% of initial permeability and 2 to 7% of initial porosity. Kaolinite fines were shown to be mobilized during steam treatment. Aging of these rock mixtures for 10 days at 400°F and 1,000 psi led to formation of swelling smectite clay (Ca montmorillonite). Growth of montmorillonite was demonstrated to be possible only at low carbon dioxide (CO2) partial pressures. Mixtures with dolomite are shown to produce more montmorillonite than mixtures with calcite. Steam injection in montmorillonite-rich sandstone caused up to 84% loss in the initial permeability and up to 8% loss in initial porosity. The principal formation-damage mechanism proved to be clay swelling, which led to filling of pores with montmorillonite. The microporous network that filled the pores significantly restricted the flow. Aging of montmorillonite-rich mixtures did not reveal mineral alterations but did allow visualization of the morphological reorganization of montmorillonite and its pore-bridging effect. This paper describes interactions between superheated steam and rock samples. This study further characterizes formation-damage mechanisms caused by hydrothermal alterations and their effects on petrophysical properties of reservoir rocks. Data about conditions of mineral reactions can be used to shift the physicochemical or operational conditions to prevent growth of swelling clays such as montmorillonite.
Polyacrylamide-based friction reducers (FRs) are widely used in hydraulic fracturing to reduce friction created within fluid as it flows through tubulars or other restrictions. These polymers generally add viscosity to the fluid to reduce the turbulence induced as fluid flows. Type and amount of total dissolved solids (TDS) in source water have significant impact on performance of FRs. This study investigates these effects and evaluates various types of FRs applied to the Marcellus Shale region. It was found that increase in salinity often causes significant performance degradation (Mantell et al., 2011). This is especially critical for application of FRs in Marcellus shale that is known for challenging brine contents. This effect is more pronounced for some divalent cations than for monovalent ones. Addition of surfactant systems can improve FR performance by extending the salt tolerance. Overall, it can be concluded that FR optimization for given water content and proppant can be done by adjusting FR type and/or concentration. For special applications, when higher proppant loading is desired, applying Viscosifying Friction Reducers (VFRs) and High Viscosity Friction Reducers (HVFRs) are proven to be preferable. It was demonstrated that slickwater viscosity tend to increase exponentially with VFR concentration increase. At the same time VFRs should be breakable to ensure high regained proppant conductivity and minimization of formation damage. Such result would further justify the transition from traditional gelled fluids to FR-based viscous slickwater. This comprehensive review explores the application of various types of FRs for Marcellus shale region. It defines the critical TDS levels, and types of cations that require changes in FR type or dosage. This data can benefit operators in (1) optimizing performance of the FR-based completion fluid; (2) avoiding formation damage associated with usage of unjustified additives; and (3) comparing/qualifying FRs based on their optimal range of application and economical dosage.
Acidizing of sour, heavy oil, weakly consolidated sandstone formations under steam injection is a real challenge. Fines migration, sand production, inorganic scale, corrosion products, and damage due to asphaltene precipitation are some of the common concerns with these sandstone formations. They cause decline in the productivity of the wells, and there is always need to stimulate these wells to restore their productivity. Furthermore, the complexities of sandstone formations require a mixture of acids and several additives, especially at temperatures up to 360°F. Three treatments were tried in a horizontal well in this field: HCl acid, A (GLDA), and B chelating agents. In this paper, we evaluate the results of field applications using geochemical modelling, production data, and analysis of well flow back fluids after field treatments.The field treatment included pumping a foaming agent to have proper rheological characteristics and a better controlled pumping process, followed by the main stage of the treatments. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration of the chelating agent A was measured utilizing a titration method using ferric chloride solution. Geochemical modelling was conducted using specialized software, and was used to predict the concentrations of key ions in the flow back samples.The first two treatments including HCl acid and chelating agent B produced results below expectation. The third treatment using GLDA was successful and the well productivity increased significantly. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flow back samples indicated that iron was the main cation, which shows that the chelate dissolved corrosion products. Geochemical modelling was able to predict the trend noted in the concentrations of key ions and chelant in the produced fluids.
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