Hydraulic Fracturing is considered to be one of the most important stimulation methods. Hydraulic Fracturing is carried out by inducing fractures in the formation to create conductive pathways for the flow of hydrocarbon. The pathways are kept open either by using proppant or by etching the fracture surface using acids. A typical fracturing fluid usually consists of a gelling agent (polymers), cross-linkers, buffers, clay stabilizers, gel stabilizers, biocide, surfactants, and breakers mixed with fresh water. The numerous additives are used to prevent damage resulting from such operations, or better yet, enhancing it beyond just the aim of a fracturing operation. This study introduces a new smart fracturing fluid system that can be either used for proppant fracturing (high pH) or acid fracturing (low pH) operations in sandstone formations. The fluid system consists of glutamic acid diacetic acid (GLDA) that can replace several additives, such as cross-linker, breaker, biocide, and clay stabilizer. GLDA is also a surface-active fluid that will reduce the interfacial tension eliminating the water-blockage effect. GLDA is compatible and stable with sea water, which is advantageous over the typical fracturing fluid. It is also stable in high temperature reservoirs (up to 300 °F) and it is also environmentally friendly and readily biodegradable. The new fracturing fluid formulation can withstand up to 300 °F of formation temperature and is stable for about 6 h under high shearing rates (511 s−1). The new fracturing fluid formulation breaks on its own and the delay time or the breaking time can be controlled with the concentrations of the constituents of the fluid (GLDA or polymer). Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effectiveness of the developed fluid. The flooding experiments were in reasonable conformance with the rheological properties of the developed fluid regarding the thickening and breaking time, as well as yielding high return permeability.

Massive hydraulic fracturing is the only method to have economic production from unconventional resources (i.e. tight sandstone and shale gas reservoirs, etc.). Tight permeability reservoirs represent around 60% of global unconventional resources, they have large quantities of hydrocarbon, and with their impaired permeabilities, hydraulic fracturing is the most promising technique dealing with those types of reservoirs. A typical fracturing fluid usually consists of a cross-linked gel system, buffer, clay and gel stabilizers, biocide, and a breaker among many other constituents, all to prevent damage resulting from such operations, or better yet, enhancing the formation beyond the aim of a fracturing operation. This paper introduces a new zero leak-off, smart fracturing fluid system for tight formations and conventional resources as well. The fluid system consists of GLDA chelating agent that has the abilities of a cross-linker, breaker, biocide, clay stabilizer, replacing those constituents in one simple fluid, GLDA is also a low IFT fluid which will reduce the IFT eliminating the water blockage problems due to the capillarity effect in tight reservoirs. It is also stable in high temperature reservoirs (up to 300°F), environmentally friendly and readily biodegradable. The effect of temperature, pH, shear rate, polymer concentration and GLDA concentration on the rheological properties of the new fluid system has been studied, as well as the thickening-breaking time and efficiency, thermal stability of the developed fluid system. The new fracturing fluid formulation can withstand up to 200°F of formation temperature and stable for about 6 hours under high shearing rates (511s−1), with polymer concentration ranging from 20 to 70 pptg with the optimum being 45 pptg at pH 12, the viscosity building and breaking time can be controlled by the concentrations of the constituents. Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effect of the developed fluid on the core permeability and to investigate the zero leak-off property. The flooding experiments were in conformance with the rheological properties of the developed fluid regarding the thickening and breaking time as well as yielding high return permeability (85-89%).

Naturally Fractured Reservoirs are important contributors to the world's oil and gas reserves representing around one-fifth of the world's reservoirs. They usually are of lower recovery and higher residual hydrocarbon saturation than the rest of reservoirs due to its mixed wettability, low matrix permeability, low fracture porosity, and the complicated fracture network. When alkaline-surfactant-polymer flooding is conducted, it enhances the recovery by altering the wettability, lowering the interfacial tension of the rock, reducing the mobility ratio, and forming a secondary in-situ surfactant, consequently reducing the residual hydrocarbon saturation. However, majority of ASP operations usually underestimate the complicated structure and description of reservoirs. As a result, this lacking causes a serious flood modeling issue on NFRs since they rely on the matrix system mainly being the storage of hydrocarbon, and the fracture system carrying out the production. This paper presents a comprehensive study on modeling ASP flooding on NFRs. It mainly addresses the effects of wettability, IFT, capillary forces, fracture parameters along with fracture and matrix permeabilities on ASP using a dual porosity and dual permeability model. It also addresses the performance, recovery factor and the optimum slug size for an optimum EOR operation, as well as to give guidelines and theoretical justification for better flooding practices based on a modeling approach only. Sensitivity analyses on the constructed model of slug size, initiation time, sequence of injection, and concentration are done. Results show the optimized slug sizes of the injectants (i.e. 200 stb/day: 1 year of pre-injected water, 2 years of AS slug and 2 years of ASP slug), optimum initiation time and sequence of injection (1 year of water pre-injection followed by the ASP slug then followed by water flooding), in addition to the optimum concentrations of chemical injectants (alkaline and polymer concentrations of 50 lb/stb each, and surfactant concentration of 30 lb/stb). Also sensitivity analyses on the mentioned parameters are conducted and the results show how they affect NFRs. The study introduces a non-conventional injection method named Cyclic Alkaline-Surfactant-Polymer flooding. The performance and effectiveness of C-ASP are presented in addition to a comparison between C-ASP and conventionally used methods.