An eco-friendly CO2 foam based fracturing fluid is developed which can be used at HPHT conditions for shale reservoirs with high goethite content. Results observed were compared to the conventional fracturing fluids which were previously published. For the formulation of the fracturing fluid, gum acacia and Lactic Acid is grafted together in the presence of Potassium per sulphate (KPS). Base solution of the fracturing fluid is prepared using 80% of CO2 liquid and 14% brine solution. Lecithin is used to emulsify CO2 liquid and brine solution. Grafted polymer is mixed with the base solution. An Propylene glycol, oxygen scavenger, biocide, cross linker and other additives has been added in smaller proportions nearly 0.15% in the base fluid. Sodium Lauryl Sulphate and Palmitic acid is added in the base solution as foaming agent. After mixing the formulation at high rate for 10-15 minutes, 4-5% proppant is added in the developed fracking fluid. The series of test has been conducted and the results are compared with the conventional fracking fluid. FTIR has been used for the characterization of grafted Copolymer and the effective synthesized co-polymerization is shown by the Infrared spectra of gum acacia (GA), Lactic acid (LA) and grafted copolymer (GA-g-LA). Rheological properties have been evaluated of the base gel and foam separately. In this paper, the viscosity of grafted copolymer polymer fracturing foam at high pressure high temperature (HPHT) as a function of surfactant concentration, salinity, and shear rate are presented. Pressurized foam rheometer was used to find out the viscosity of CO2 foam at different surfactant concentrations (0.25–1 wt%) and salinity (0.5–8 wt%) over a wide range of shear rate (10–500 s−1) at 1500-3000 psi and 200-400 °F. The viscosity is found between 70-125 cP at for different concentrations. The foam quality has been evaluated by adding 0.25% w, 0.5%w and 1%w of surfactants. Half-life and proppant carrying capacity of the best quality foam been determined at different temperature ranges. Half-life time was found to be 145 minutes at 250oF. The results of effect of salinity and effect of shear rate have been discussed in detail. The result showed that at foam quality of 80% & 70% proppant loading is 5.5%vol and 3%vol. Use of grafted copolymer results in higher viscosity and proppant carrying capacity which is beneficial for HPHT fracturing conditions. The use of grafted copolymer enhanced the properties of fracturing fluid. GA-g-LA is a novel approach and has not been used in well stimulation industry. Grafting increased the stability of fracturing fluid at HPHT wells. This could be brought in practice in the coming time and can be used in deep wells.

Low salinity water flooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase water floods. The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Combining two methods in one process to enhance oil recovery represents a needed cost savings in the oil industry. Microgels are used as conformance control agents to improve oil sweep efficiency and control excess water production. Low-salinity water flooding (LSWF) is used as a wettability alteration agent in carbonate reservoirs and improves displacement efficiency. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by combining the four technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to demonstrate how the combining method can improve oil recovery. The oil-wet carbonate cores provided a higher improved oil recovery than water-wet carbonate cores during LSWF compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix, thereby producing more oil from the matrix. Preformed particle gels (PPGs) is a diverting agent that is used to solve the conformance problem in low permeability rich oil zones. It is injected to reduce thief zone permeability and then divert displacing fluid into poorly swept zones. The focus of this study is to see how PPGs, low water salinity, polymer and silica particles perform in porous media by creating flow resistance to injected fluid thereby changing the wettability and enhancing the sweep and displacement efficiency . Silica particles modify the surface wettability and also modify the gel particles strength, LSWF modify the mechanical properties of PPG such as swelling ratio, polymer increase the sweep efficiency of chase water flood and PPG plug the high permeability zones to divert the water flow into low permeability zone to displace the remaining oil.

This paper presents the investigation of the surfactant solution flooding in cross capillary geometry using microfluidics devices in the framework of EOR (Enhanced Oil Recovery). As a matter of fact, the surfactant injected in reservoir to enhance the oil recovery causes blockage or flow deficiency due to incompatible flow in reservoir. Therefore, the objective of this study is to observe the flow efficiency of water/surfactant flow in these channels resulted improving in enhanced oil recovery. In this study, surfactant solution flooding experiments conducted at different injection rates. The first one relates to injection rate of 1 µl/min and second one corresponds to injection rate of 2µl/min. From this, it was revealed that at the flow of 1µl/min the surfactant solution reaches to junction point within 6 seconds and takes 13 seconds to achieve the full saturation in micro fluidic chip. Further, initial flow of surfactant is smooth and regular and then as it reaches at junction point its flow is declined by 7%. However at 2µl/min flow surfactant took 3 seconds to achieve saturation in microfluidic chip. Nevertheless, exactly half time was required for surfactant to reach junction point. Hence, higher injection rate are highly suitable for consolidated reservoir and surfactant require no alteration. The observations are key point for better understanding of the insinuated phenomena in EOR as to determine the applicable data to feed flow simulators.

Inside a continuous chemical reactor, in which phase transitions occur during the reaction, thermodynamic conditions as well as compositions of the process stream are subject to significant spatial and temporal changes. Given that measured information about thermodynamic state variables is only available for the inlet and outlet stream of the reactor, it is currently not possible to determine a spatial distribution of thermodynamic states within the reactor on the basis of measured information via software sensors. As, in particular, exothermic chemical reactions often show temperature peaks which are likely to destroy catalysts and components or adversely affect their service life, this limited information about internal reactor states poses a considerable risk with regard to product quality and process reliability. Therefore, this paper proposes a novel approach in the area of sensor technology which is based on rigorous thermodynamic models and enables a more detailed prediction of the reaction progress in view of avoiding undesired temperature peaks, based on measured process parameters of the input and output streams only.