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For fractured low permeability reservoirs, there are challenges to enhance oil recovery after water flooding with high water cut contents. Because of unsatisfied surfactant polymer flooding, we explored the integrated EOR techniques of conformance control treatment and surfactant flooding. This paper analyzes the results of pilot tests with four injectors and 16 producers and concludes the effectiveness of integrated EOR techniques. Based on lab results of conformance control core flooding tests and surfactant based chemical EOR reservoir core flooding experiments, we did pilot simulation studies to develop pilot design parameters. Then through history match and detailed compositional simulation, we made EOR integrated technology design and compared several injection scenarios by predicting the potential performance. Finally, an integrated EOR technique with two conformance control treatments and surfactant flooding was selected and executed for three injectors in the interested pilot block. For the fourth injector, only surfactant flooding was used to compare. Lab results of conformance control core flooding tests showed the efficiency of plugging and a good fluid diversion performance of conformance polymer agents. Surfactant based chemical EOR reservoir core flooding experiments resulted from 70% to 98% residual crude oil recovery. The experimental data obtained was implemented in a numerical simulator model to find the potential incremental recovery associated with conformance control treatments and chemical flooding. A refined sector model used to further evaluate the effect of them. Positive simulation results boost pilot tests. Five fluid injection slugs including the cleaning slug, pre-flooding slug, near wellbore plugging slug, in deep conformance control slug, and surfactant flooding slug were run for three injectors in the range of eight to ten months of treatment. In the interested pilot block, the monthly decreasing rate of oil production dropped from 3.58% before treatment to −1.04% during treatment. Comparing the oil production data from the fourth injector with those from other three injectors, we observed monthly oil production rate increases from 4.25% to 7%. These results highlighted the importance of conducting a conformance control treatment before surfactant flooding, especially in fractured low permeability reservoirs. The results of pilot tests in this work shed light on designing integrated EOR techniques. These positive results of controlled high water cut and improving oil production are promising enough to go towards a larger field project.

Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding.Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions.Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs.In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

For fields with hard and brittle shale sections that have microfractures (either preexisting in the formation or induced by drilling operations), we experienced troublesome drilling with a relatively low rate of penetration (ROP). A systematic experimental work has been implemented to discover whether nanoparticles added to drilling fluids penetrate shale formations and improve wellbore stability. Starting with quantitative analysis of the shale rocks, we found the mineralogy and clay composition of these rocks by using X-ray diffraction (XRD). The XRD analysis shows that the shale rocks consist of mixed-layer clays and are very heterogeneous. The shale samples were then characterized by X-ray computed tomography (XCT) and scanning electron microscopy (SEM) to gain an understanding of preexisting microfractures. The XCT results show that multiple cracks are irregularly distributed inside the shale with widths between 10 to 25 μm. Smaller cracks with widths ranging from 100 to 250 nm were also observed via imaging on the shale sample surface using SEM. To answer whether adding the nanoparticles improves wellbore stability, we first designed the nanoparticle infiltration test by flowing nanoparticle dispersions through the shale assembly at an inflow pressure of around 800 kPa. After the shale samples were subjected to infiltration tests with durations between 9 to 27 days, the injected depths of nanoparticle along cracks was determined to range from 190 to 420 μm, as seen by optical microscope images. Higher resolution SEM images show that the maximum infiltration depths of the nanoparticles range from 2 to 5 μm in different crack-free locations. Nanoindentation tests were then conducted under the continuous stiffness measurement (CSM) mode to probe the mechanical properties of the pre-treated and post-treated shale samples. At two indentation depths, the averaged Young's modulus E for the shale sample before and after nanoparticle infiltration significantly increased from 29.5 to 34.0 GPa (at a depth of 500 nm) and from 29.0 to 33.3 GPa (at a depth 3000 nm), respectively. The nanoparticle infiltration and nanoindentation test results demonstrate that nanoparticles can filter into and further strengthen the shale formation. We also formulated nanoparticles in our drilling fluid and performed the pressure transmission test (PTT) to see their sealing effect on the field cores. A highly favorable plugging result was obtained from the PTT using base mud with nanoparticles. Therefore, it is concluded that our systematic experimental work has delivered results, which support the practice of using nanoparticles to improve wellbore stability for shale formations.

Tight oil reservoirs need stimulation in order to produce the trapped oil. The most common form of stimulation used by the oil and gas industry is hydraulic fracturing. Fracturing operations tend to create fractures including primary fractures and microfractures. The objective of this study is to develop a fracturing fluid which can be converted into microproppant, beads, and channelized-proppant as desired in-situ during a fracturing operation to enhance the hydraulic conductivity of the microfractures and the primary fractures, and simplify the hydraulic fracturing operation, where the channelized-proppant is defined as the pillars surrounded by channels. Resin, curing agents, surfactants, and aqueous phase were mixed together to form O/W emulsion to serve as fracturing fluid. After curing process, resin and curing agent would react and form proppant in-situ. The parameters affect the proppant formation such as the curing temperatures, pressure, mixing strength, surfactant concentration, and size control additives were all studied and thus through controlling the parameters, microproppant, beads, and channelized-proppant can form in-situ as desired. The particle size distribution, sphericity, roundness, conductivity, acid solubility, and crush strength were tested. Through controlling the experimental parameters and adding size control additives, fracturing fluid can be converted into microproppant, beads, and channelized-proppant as desired at a temperature from 30° C to 90° C. Almost 100% of the resin and the curing agents were converted into proppant with a specific density of 1.09g/ml. For the beads, both the sphericity and roundness are over 0.9, less than 2% fines were generated after being loaded to 15 kpsi, the acid solubility is 2.37%, and the conductivity of the beads of 20/40 mesh tested with proppant loading of 1 lb/ft2 at 4000 psi at room temperature was 227 mD-ft. For the microproppant, both the sphericity and roundness are close to 1 with d50 about 80 µm. Furthermore, channelized-proppant was formed in an artificial fracture with walls made of glass sheets. Thus, with the fracturing fluid developed, the conductivity of the well can be maximally optimized through the in-situ formation of channelized proppant and microproppant to keep the primary fractures and microfractures open respectively.

The following will illustrate how laws and public concerns can serve as a framework for oil and gas exploration, drilling, and production. It will outline several case histories and how different laws and motivations intersect and shape the industry. This is a comprehensive analysis of laws governing a particular region's actions and examined on a federal, state and, in some cases, local level. Other factors, including public image and community feedback are evaluated, too. Three case histories are explored. These are presented via a timeline of events leading up to an implementation, reevaluation, and/or development of legislation and/or legal decision. Other legislation is assessed on how an Act (e.g. Clean Air, Clean Water) is initiated apart from the oil and gas realm and then eventually adopted to address certain public concerns. In most cases, regulations were already set in place and oil and gas entities had to interpret accordingly and work within determined protocols. In some cases, incidents occurred that, in turn, created new legislation and/or set expectations that had implications for how the industry would execute future projects. Incidents include a case of negligence and how the specific company responded as well as other operators located in the immediate vicinity. The regulations and/or best management practices that were created because of the incident will also be discussed. Other cases illustrate the cultural norms surrounding a particular set of legislation. An operator may be familiar with one area yet when branching out to other locations, conclude that the new area is not financially feasible for them due to the different technology and documentation required. Bigger and/or local operators have made these ventures profitable. A comprehensive report on regulations and how operators execute them will also be provided. Impacts and effects on the oil and gas entities as well as the social and natural communities are assessed, illustrating the important connection between the residential/individual communities and the business entities via the government bodies to hear both sides and appropriately represent the cases at hand.