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Domestic abuse is a serious problem for married women in India (IPV). It is vital that women take use of accessible healthcare services if we want to lower the maternal death rate. Indian women's physical encounter with rape is examined in eight Empowered Action Group (EAG) states. For women living in EAG states, the rate of physical IPV is expected to be greater than in non-EAG states. The 2005-2006 India National Family Health Survey includes 65,587 women (NFHS-3). According to a logistic model, living in an EAG state lowers your risk of experiencing physical IPV in the last year. This is not what we expected. The best way to deal with domestic abuse is still up for debate among medical professionals. This article describes a review of qualitative research that aims to address the following two questions: How do women who have experienced domestic violence rate the treatment they get from medical professionals? Second, what do women who have been abused by their spouses seek from their healthcare providers in response to their disclosures?

Summary The application of surfactants in enhanced oil recovery (EOR) has revealed over the years various challenges that impose limitations on the successful implementation of surfactant flooding. Surfactant adsorption is one of the most important aspects that strongly dictates the feasibility of surfactant-based EOR. The effect of the presence of crude oil on surfactant adsorption and the influence of surfactant partitioning on the adsorption quantification are presented in this paper. Static adsorption experiments were conducted in this study for a surfactant mixture [alkyl ether carboxylate (AEC):alkylpolyglucoside (APG)] on sandstone rock samples in the absence and presence of crude oil. Partitioning experiments were carried out to evaluate the surfactant partitioning between the aqueous surfactant solution and the crude oil to determine the partitioning influence on the adsorption results in the presence of crude oil. The mixture’s adsorption and partitioning behaviors were studied at a fixed salinity of 32 k ppm and temperatures of 80 and 106°C. High-performance liquid chromatography (HPLC) was used in measuring the surfactant concentration throughout adsorption and partitioning tests. Rock characterization was also performed in this study using X-ray diffraction (XRD) as well as X-ray photoelectron spectroscopy (XPS) before and after adsorption with and without crude oil being present. Static adsorption outcomes displayed the adsorption of APG, AEC, and the overall mixture with and without crude oil being present, because all are having a similar increasing trend when concentration increases. However, the adsorption values were much higher when crude oil was present as compared with the adsorption values when crude oil was absent; this is because of not considering the impact of surfactant partitioning. The adsorption values (i.e., at 0.2 wt%) for both temperatures were below 2.5 mg/g in the absence of crude oil and rose to around 3.5 mg/g in the presence of crude oil. A significant amount of what was adsorbed belongs to AEC because of its increased chain-chain interactions with APG, which was evidenced experimentally in our previous work; hence, AEC is the greatest contributor to the overall surfactant mixture’s adsorption. Also, temperature had an impact on the adsorption capacity of the AEC:APG mixture, showing that APG has a greater sensitivity to temperature in comparison to AEC. The adsorption behavior of APG was found to be the opposite of AEC, where the adsorption capacity at 106°C was lower for AEC than its adsorption capacity at 80°C and vice versa for APG. The surfactant partitioning results were used to validate the surfactant adsorption outcomes in the presence of crude oil. After eliminating the partitioning effect, the surfactant adsorption isotherms in both cases of the presence and the absence of crude oil were almost identical. The results highlighted the importance of measuring surfactant partitioning, and the impact that partitioning has on the total surfactant losses during the surfactant flooding process. XRD and XPS results indicated that the change of the rock structure after adsorption when crude oil was present was attributed to the rock dissolution phenomena. It was concluded that adsorption and partitioning take place in the water/oil/rock system simultaneously and taking that into account allows for the improved and proper designing of the surfactant flooding.

Carbon Capture and Sequestration (CCS) has potential to provide an amicable solution in reducing CO2 emissions to the atmosphere for perpetuity with zero-degree failure. Geological storage sites are conventionally considered to be safe for CO2 sequestration and are thoroughly simulated for any potential leakage due to loss of structural integrity. The offshore CO2 storage site, if leaks, could potentially affect the marine environment eventually escaping into atmosphere. A prior modelling of potential leakage from identified threats and its impact on marine environment will ensure the safety and substantially aid site- specific and adaptive Monitoring, Measurement & Verification (MMV) planning. Subsurface integrity study of the storage site integrated with coupled modelling contemplates longterm security of CO2 storage. For a leak to occur through the plugged &abandonment (P&A) wells, one or more barriers must fail. P&A wells integrity feasibility reveals the impact of CO2 interaction with non- CRA composite structure identifying possible leak paths. The probability of a leak from subsurface to the environment through each of the P&A well, depending on its attribution, was estimated. Barrier's failure probabilities in P&A wells are understood under various well leak estimation scenarios. Range of potential leakage rate, in the event of loss of well integrity, was evaluated. To demonstrate the impact of potential CO2 leakage in marine environment through the loss of subsurface or well integrity from identified locations, integrated CO2 dispersion simulation was carried out for multiple potential leakage scenarios and changes in marine water pH were analyzed. Based on barriers reliability function, the well leakage modelling results suggest that minimum rate of CO2 leakage through the well path that can possibly reach to the seabed is 6-10 tCO2e/year and for extreme case it would be 500 tCO2e/year. The CO2 dispersion modelling were performed for these leakage rates at three different well locations. Three scenarios were considered and simulated for escaped CO2 gas in the water column and its impact on marine environment. The observed change in marine water pH values in near and far-field region were negligible or undetectable. Any reduction in the pH values was predicted to be within the natural variation of the seawater acidity at the storage site with the varying climatic conditions. The CO2 gas bubbles were predicted to be fully dissolved in the water column, no CO2 gas bubbles would reach the surface and escape into the atmosphere for the modelled leakage scenarios in water depths of 140m. In this paper, the integration of well leakage rate modelling with CO2 dispersionsimulation results are discussed to ameliorate the MMV planning for legacy wells to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years post injection.

There are many gas fields associated with large amount of CO2 concentrations (>50 mol%) in offshore Malaysia. Development of the contaminated gas fields is only possible if a geologically safe storage site is identified for the storage of produced CO2. The critical component of CCS project field development plan is monitoring of the storage site for the long-term containment and conformance security. 4D time-lapse seismic is key in monitoring, measurement, and verification (MMV) plan. The time-lapse 4D seismic has been traditionally used to identify the potential threats associated with reservoirs with enhanced oil recovery plan. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richards’ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richards’ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. This study focuses on the different characteristics on 4D seismic attributes for carbonate and clastic reservoirs and discusses to effectively utilize for MMV.

Carbon Capture & Storage (CCS) has globally been recognized as the way forward to manage & reduce Green House Gas (GHG) emissions. However, for every geological CO2 storage project there are two inherent yet independent storage risks: loss of containment and loss of conformance. For early detection and mitigation of these risks, a robust Monitoring, Measurement and Verification (MMV) plan is of supreme importance. While several matured, newly developed and under trial monitoring technologies addressing various aspects of MMV are currently available but it's crucial to evaluate them in terms of applicability, durability, ease of operation & maintenance, and cost to the project. This study focuses on the screening and selection monitoring technologies to achieve a site-specific, adaptive, and cost-effective MMV plan and design. Identification of critical containment & conformance risks were achieved through integrating information from various elements viz. CO2 plume migration forward modeling, 3-way coupled modeling, well integrity analysis, overburden risk analysis, CO2 marine dispersion modeling, environmental impact assessment (EIA), regulatory requirements, etc. Based on identified risks, the specific MMV elements were selected along with designing of their scheduling and frequency. Subsequently, an inventory of all available technologies addressing explicit MMV needs was prepared. These technologies were put through rigorous analysis on their capability of detection, operability, tool/technology longevity, availability, and associated costs. High-ranking technologies were then knitted for the final MMV planning & design. As a part of the arduous screening, permanent ocean bottom (OB) monitoring technologies were analyzed and some of the alternate low-cost technologies surfaced that can cater to continuous and long- term data acquisition needs. Knitting of 3D Distributed Acoustic Sensor – Vertical Seismic Profile (DAS- VSP) hybrid with 3D seismic surveys would help optimizing the logistic requirements and reducing cost of monitoring survey acquisition over the project lifecycle. During the entire screening and selection process, Multi-Fiber Optic Sensor System (M-FOSS) technology emerged as the leading monitoring technology, which is cost-effective, easy to operate and has the flexibility to be deployed at well and/or on seabed. An exhaustive inventory of available/emerging MMV technologies and the cost versus benefit matrix was developed that can be used for MMV planning and design across CCS projects. The study focuses to streamline the long-term sustainability of the adapted MMV planning to enhance the project economics by ensuring the optimum value propositions of implemented technologies.

The deployment at the field-scale of a novel technique to improve oil recovery using nanoparticles injection is challenging. It requires a comprehensive evaluation of a series of laboratory experiments, to translate and validate the mechanisms into a numerical model to predict accurately and reduce uncertainty parameters. This paper describes the application of novel advanced reservoir modeling for nanoparticles from pore-scale to field-scale, using an offshore Malaysian oilfield as a pilot field case. A series of laboratory experiments (fluid-fluid and fluid-rock) and numerical studies: nanofluid formulation, pore-scale studies, validation, and upscaling process into the field-scale model were carried out. The development of nanofluids was formulated to meet key criteria such as compatibility and thermal stability at the intended field condition. Prior to coreflooding tests with native core, a series of experiments to observe mechanisms were carried out. The results of the laboratory experiments were then validated in the 1D coreflooding model. The procedure was continued with observed critical parameters being scaled-up into 3D field-scale model before running the prediction scenarios. The newly developed nanofluids for the intended field performed well in compatibility and thermal stability tests at reservoir temperature. Precipitation and sedimentation were not observed in this solution. The wettability alteration to more water-wet was observed with consistent results through interfacial tension measurements, contact angle measurements, and relative permeability measurements. Coreflooding was performed using native core, and the reduction of residual oil saturation was approximately 25% between pre- and post-nanoflooding. The adsorption of nanofluids was measured to be around 1.12 mg/g of rock. All these results were input into the model and the history match quality index achieved an acceptable match of ~95%. Several critical parameters for the upscaling process were investigated such as reaction rate of particle aggregation, adsorption, and retention factor. During the scale-up process, the velocity of the fluids and pressure drop were conserved because the recovery is sensitive to flooding rate and the viscosity of the fluids are pressure dependent. The field-scale model was run for the intended field location. The potential of using nanoparticles was evaluated and compared to the no further activity scenario giving an additional recovery factor of approximately 1% per year. The developed method of novel robust advanced reservoir modeling for nanoparticles creates a new reference as the first application in the world of novel advanced numerical modeling at field-scale.