High-permeability vacuum membrane distillation utilizing mechanically compressed carbon nanotube membranes

High-permeable vacuum membrane distillation by applying vertically aligned carbon nanotube for the first time.

Enhancement of Aqueous Solubility and Dissolution Profile of Atorvastatin Calcium: In vitro Evaluation of Solid Dispersion

Purpose: The objective of the present study was to formulate solid dispersions (SD) of Atorvastatin calcium to improve the aqueous solubility and dissolution rate to facilitate faster onset of action. Atorvastatin calcium is a lipid lowering agent belonging to BCS-II having low solubility and high permeability.

Proteome allocation and the evolution of metabolic cross-feeding

Metabolic cross-feeding (MCF) is a widespread type of ecological interaction where organisms share nutrients. In a common instance of MCF, an organism incompletely metabolizes sugars and releases metabolites that are used by another as a carbon source to produce energy. Why would the former waste edible food, and why does this preferentially occur at specific locations in the sugar metabolic pathway (acetate and glycerol are preferentially exchanged) have challenged evolutionary theory for decades. After showing that cells should in principle prioritise upstream reactions, we investigate how a special feature of these metabolites - their high diffusivity across the cell membrane - may trigger the emergence of cross feeding in a population. We explicitly model metabolic reactions, their enzyme-driven catalysis, and the cellular constraints on the proteome that may incur a cost to expressing all enzymes along the metabolic pathway. We find that up to high permeability coefficients of an intermediate metabolite, the expected evolutionary outcome is not a diversification that resembles cross-feeding but a single genotype that instead overexpresses the enzymes downstream the metabolite to limit its diffusion. Only at very high permeabilities and under restricted sets of parameters should the population diversify and MCF evolve.

Formulation and Characterization of Nimodipine Nanoparticles for the Enhancement of solubility and dissolution rate

Nimodipine (NMD) is a dihydropyridine calcium channel blocker useful for the prevention and treatment of delayed ischemic effects. It belongs to class ? drugs, which is characterized by low solubility and high permeability. This research aimed to prepare Nimodipine nanoparticles (NMD NPs) for the enhancement of solubility and dissolution rate. The formulation of nanoparticles was done by the solvent anti-solvent technique using either magnetic stirrer or bath sonicator for maintaining the motion of the antisolvent phase. Five different stabilizers were used to prepare NMD NPs( TPGS, Soluplus®, HPMC E5, PVP K90, and poloxamer 407). The selected formula F2, in which Soluplus has been utilized as a stabilizer, has a particle size (77 nm) and polydispersity index (PDI) (0.016). The formulas with the smallest particle size were freeze dried with the addition of 1 % w/w mannitol as cryoprotectant. The saturation solubility of NMD in the prepared nanoparticles was increased twenty four-folds, and the complete dissolution was achieved at 90 minutes compared with pure NMD, which reaches only 6%. The formation of hydrogen bonding between NMD and the polymer or the cryoprotectant, as confirmed by the FTIR study. In conclusion, the preparation of NMD as polymeric nanoparticles is a useful technique for enhancing the solubility and dissolution rate.

Design of in-Depth Conformance Gel Treatment to De-Risk ASP Flooding in a Major Carbonate Reservoir

Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor sweep efficiency, both areal and microscopic. An Alkaline-Surfactant-Polymer (ASP) pilot is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Design of the gel conformance treatment was multi-faceted. Rapid breakthrough of tracers at the pilot producer from each of the individual injectors, less than 3 days, implied a direct connection from the injectors to the producer and poses significant risk to the success of the pilot. A dynamic model of the SAMA pilot was used to estimate in the potential injection of either a high viscous polymer solution (~200 cp) or a gel conformance treatment to improve contact efficiency, diverting injected fluid into oil saturated reservoir matrix. High viscosity polymer injection scenarios were simulated in the extracted subsector model and showed little to no effect on diverting fluids from the high permeability streak into the matrix. Gel conformance treatment, however, provides benefit to the SAMA pilot with important limitations. Gel treatment diverts injected fluid from the high permeability zone into lower permeability, higher oil saturated reservoir. After a gel treatment, the ASP increases the oil cut from 3% to 75% while increasing the cumulative oil recovery by more than 50 MSTB oil over ASP following a high viscosity polymer slug alone. Laboratory design of the gel conformance system for the SAMA ASP pilot involved blending of two polymer types (AN 125SH, an ATBS type polymer, and P320 VLM and P330, synthetic copolymers) and two crosslinkers (chromium acetate and X1050, an organic crosslinker). Bulk testing with the polymer-crosslinker combinations indicated that SAMA reservoir brine resulted in not gel system that would work in the SAMA reservoir, resulting in the recommendation of using 2% KCl in treated water for gel formulation. AN 125 SH with S1050 produce good gels but with short gelation times and AS 125 SH with chromium acetate developed low gels consistency in both waters. P330 and P320 VLM gave good gels with slow gelation times with X1050 crosslinker in 2% KCl. Corefloods with the P330-X 1050 showed good injectivity and ultimately a reduction of permeability of about 200-fold. A P330-X 1050 was recommended for numerical simulation studies. Numerical simulator was calibrated by matching bulk gel viscosity increases and coreflood permeability changes. Numerical simulation indicated two of the four injection wells (SA-0557 and SA-0559) injection profile will change compared to water. Overall injection rate was reduced by the conformance treatment and was the corresponding oil rate. Total oil production from the center pilot production well (SA-0560) decreased with gel treatment but ultimately increased to greater rates

Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project

Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

Demonstrating Flexibility and Cost-Efficiency of Integrated Ensemble-Based Modeling – One Approach on Three Reservoirs

The aim of this study is to demonstrate the value of an integrated ensemble-based modeling approach for multiple reservoirs of varying complexity. Three different carbonate reservoirs are selected with varying challenges to showcase the flexibility of the approach to subsurface teams. Modeling uncertainties are included in both static and dynamic domains and valuable insights are attained in a short reservoir modeling cycle time. Integrated workflows are established with guidance from multi-disciplinary teams to incorporate recommended static and dynamic modeling processes in parallel to overcome the modeling challenges of the individual reservoirs. Challenges such as zonal communication, presence of baffles, high permeability streaks, communication from neighboring fields, water saturation modeling uncertainties, relative permeability with hysteresis, fluid contact depth shift etc. are considered when accounting for uncertainties. All the uncertainties in sedimentology, structure and dynamic reservoir parameters are set through common dialogue and collaboration between subsurface teams to ensure that modeling best practices are adhered to. Adaptive pluri-Gaussian simulation is used for facies modeling and uncertainties are propagated in the dynamic response of the geologically plausible ensembles. These equiprobable models are then history-matched simultaneously using an ensemble-based conditioning tool to match the available observed field production data within a specified tolerance; with each reservoir ranging in number of wells, number of grid cells and production history. This approach results in a significantly reduced modeling cycle time compared to the traditional approach, regardless of the inherent complexity of the reservoir, while giving better history-matched models that are honoring the geology and correlations in input data. These models are created with only enough detail level as per the modeling objectives, leaving more time to extract insights from the ensemble of models. Uncertainties in data, from various domains, are not isolated there, but rather propagated throughout, as these might have an important role in another domain, or in the total response uncertainty. Similarly, the approach encourages a collaborative effort in reservoir modeling and fosters trust between geo-scientists and engineers, ascertaining that models remain consistent across all subsurface domains. It allows for the flexibility to incorporate modeling practices fit for individual reservoirs. Moreover, analysis of the history-matched ensemble shows added insights to the reservoirs such as the location and possible extent of features like high permeability streaks and baffles that are not explicitly modeled in the process initially. Forecast strategies further run on these ensembles of equiprobable models, capture realistic uncertainties in dynamic responses which can help make informed reservoir management decisions. The integrated ensemble-based modeling approach is successfully applied on three different reservoir cases, with different levels of complexity. The fast-tracked process from model building to decision making enabled rapid insights for all domains involved.

Cutting Re-injection CRI Uncertainty and Risk Assessment

It is the responsibility of oil and gas operators to recycle or dispose of drilling cuttings in a safe and environmentally friendly manner. Environmental regulations are very strict in establishing that green operations and cutting re-injection be as clean and friendly to environment as possible despite the associated challenges and cost. It is the preferred technique by the majority of international companies. Cutting re-Injection operations include grinding down the drilling cutting to small particle sizes and mixing them with a water-based fluid (mud, water, gel) to form a slurry. The slurry is then pumped under high pressure into a disposal formation where fractures can be initiated and propagated. Existing wells can be used as appropriate by targeting watered-out formations far from hydrocarbon- bearing zones; sometimes operators drill new wells purely for cutting reinjection purposes. The main sources of uncertainty include reservoir heterogeneity, permeability, pore throat size and fluid leakoff rates into the formation. The optimum scenario is to pump the cutting re-injection slurry into a very high permeability formation where screening out, plugging or well packing is unlikely, assuming solids are suspended and are completely lost into the formation. This scenario can only be feasible if the formation pore throat size is much larger than the solid size. This paper presents how to conduct risk assessments for all possible scenarios considering all sources of uncertainties. The paper also shows that under some circumstances it is better to pump the cutting slurry into a very tight formation, such as shale (closed system), than a permeable formation with a high degree of uncertainty where screenout potential risk is most likely.