Optimal Design of Thermal Membrane Distillation Systems for the Treatment of Shale Gas Flowback Water

Shale gas production is associated with the significant consumption of fresh water and discharge of wastewater. The flowback wastewater is tied to the hydraulic fracturing technology used for completing and stimulating the horizontal wells in the very tight formations characterizing the shale formation. Treatment and reuse of these large volumes of wastewater can lead to substantial savings in fresh water usage and reduction of the negative environmental impact thereby enhancing sustainability of the shale gas industry. Such treatment requires selective and cost-effective technology.Thermal membrane distillation (TMD) is an emerging technology that offers several advatanges such as high selectivity in separating water from inorganic solutes and modular nature that can accommodate a wide range of flows. It can also utilize low-level heats that are typically available from shale-gas production and processing.The objective of this work is to develop an optimization approach for the design of TMD systems to treat flowback water. A multi-period formulation is developed to account for the time-based variation in the flowrate and concentration of the flowback water. Modeling equations are used to relate design and operating variables to performance and cost. The optimization formulation also accounts for the period-based changes in the required design and operating variables and reconciles them over the selected periods. Other constraints include quality of the permeate and water-recovery ratio. The optimization formulation and design approach are applied to a case study for the treatment of flowback water for the Marcellus Shale Play. For 75% water recovery, the cost of the permeate is about $2.6/m3. As higher recoveries are sought, the cost per m3 of permeate increases due to capital productivity factors in dealing with the decreasing amount of flowback water over time. The results are reported using a Pareto chart that trades off recovery objectives with cost of treated water

Strategies to reengage patients lost to follow up in HIV care in high income countries, a scoping review

Background: Despite remarkable achievements in antiretroviral therapy (ART), losses to follow-up (LTFU) might prevent the long-term success of HIV treatment and might delay the achievement of the 90-90-90 objectives. This scoping review is aimed at the description and analysis of the strategies used in high-income countries to reengage LTFU in HIV care, their implementation and impact. Methods: A scoping review was done following Arksey & O'Malley's methodological framework and recommendations from Joanna Briggs Institute. Peer reviewed articles were searched for in Pubmed, Scopus and Web of Science; and grey literature was searched for in Google and other sources of information. Documents were charted according to the information presented on LTFU, the reengagement procedures used in HIV units in high-income countries, published during the last 15 years. In addition, bibliographies of chosen articles were reviewed for additional articles. Results: Twenty-eight documents were finally included, over 80% of them published in the United States later than 2015. Database searches, phone calls and/or mail contacts were the most common strategies used to locate and track LTFU, while motivational interviews and strengths-based techniques were used most often during reengagement visits. Outcomes like tracing activities efficacy, rates of reengagement and viral load reduction were reported as outcome measures. Conclusions: This review shows a recent and growing trend in developing and implementing patient reengagement strategies in HIV care. However, most of these strategies have been implemented in the United States and little information is available for other high-income countries. The procedures used to trace and contact LTFU are similar across reviewed studies, but their impact and sustainability are widely different depending on the country studied

A novel downhole sensor to determine fluid viscosity

This paper presents the performance evaluation of a novel sensor designed to measure the in situ viscosity of a fluid flowing at downhole conditions. The device provides a mechanism to allow the passage of solid particles (i.e. sand) and has a self-cleaning ability should any build-up of these particles restrict the flowing area. The sensor was assembled in a closed flow loop to prevent measurement error due to partial vaporization of the samples at higher temperatures, and it was tested and calibrated with mixtures of glycerin and water. Differential pressures, flow rates and temperatures were acquired and used to determine the viscosity of two crude oils (and mixtures of those) with viscosities ranging from 0.001 to 0.03 Pa.s (1 to 30 cp ) and temperatures from 37.8 to 71.1 °C (100 to 160 °F). Flow rates were controlled to maintain linearity in the differential pressure response to ensure a laminar flow regime. Viscosity measurements were validated with independent measurements using a Brookfield viscometer and the agreement was within 2%. Using data from this sensor, new viscosity mixing rules were developed to allow determination of mixture compositions from viscosity measurements or mixture viscosities for given compositions. This paper also presents a generalized mathematical model to describe the performance of the sensor with Newtonian and non-Newtonian fluids. The model characterizes the response of the sensor as a function of the parameters from a power-law model rheological description and the geometry of the device. The experimental data suggest the validity of this model for predicting the sensor response under realistic operating conditions. The model can be used to calculate optimum dimensions to fabricate a device for customized applications. Potential applications include the estimation of diluent to be added to a more viscous fluid to achieve a target viscosity reduction, fluid identification from wireline formation testers, smart well fluid monitoring, enhanced mud logging, and fracture fluid characterization

Hydrate Formation: Considering the effects of Pressure, Temperature, Composition and Water

The main components in producing natural gas hydrate (whether for gas storage or for transportation), are water and natural gas, at low temperatures and high pressures. Each variable has a significant effect on the formation of gas hydrate. It is therefore critical to analyze the effect of each variable on hydrate formation to ascertain the best conditions required for a successful gas hydrate formation process. This research evaluates the effect of these critical elements: temperature, pressure, gas composition, and water upon gas hydrate formation. This paper summarizes the findings of a sensitivity analysis using varying natural gas compositions. Results show that the composition of the natural gas can affect the temperature and pressure required for formation of the hydrate. Even more significant is the effect of impurities in the natural gas on the pressure temperature (PT) curves of the hydrate. Carbon dioxide, hydrogen sulfide and nitrogen are the main impurities in natural gas affecting the hydrate formation. At a particular temperature, nitrogen increases the required hydrate formation pressure while both carbon dioxide and hydrogen sulfide lower the required hydrate formation pressure. The quantity of water required for hydrate formation is an important variable in the process. The water to gas ratio vary depending on the composition of the natural gas and the pressure. Generally the mole ratio of water to natural gas is about 6:1; however, to achieve maximum hydrate formation an incremental increase in water or pressure may be required. This is an interesting trade off between additional water and additional pressure in obtaining maximum volume of hydrate and is shown in this analysis

Improved oil production using economical biopolymer-surfactant blends for profile modification and mobility control. Final report, November 1998

In the past, starch hydrocolloids have not been effective alternates to partially hydrolyzed polyacrylamides, copolymers, and xanthan gum polymers as water shutoff agents in fractures and in matrix flow configurations. Poor injectivity and questionable stability have usually prevented their use in profile control applications. However, in recent years, the demands of the oil and gas drilling industry have led to the development of new drilling, drill-in, and completion fluids with improved functionality. New types of modified starches have contributed to these new drill in fluid (DIF) products. It was felt that the properties of the new products would lend themselves to applications in improved recovery. The objective of this project has been to evaluate the use of agricultural starch biopolymers for gelled and polymer applications in oil recovery processes. The authors believe that there is great potential for finding new functional starch products because of their chemical and structural flexibility, low cost, and wide availability. The goals of this project have been, therefore, to systematically investigate how the physical properties and chemical composition of relatively inexpensive agricultural starch products will influence their use as effective selective permeability control agents or as gels for water shut-off

Analysis of the storage capacity for CO2 sequestration of a depleted gas condensate reservoir and a saline aquifer

Among the three types of geological CO2 sequestration (mature oil and gas fields, unminable coalbeds and deep saline formations), depleted gas condensate reservoirs are particularly interesting. First, because of the high-compressibility of gas, these reservoirs have larger storage capacity than oil reservoirs or aquifers. Second, the condensate that has dropped out from the gas phase during natural depletion will re-vaporize because of re-pressurization of the reservoir and by miscibility with the injected CO2. This condensate can be recovered from producing wells and leaves more pore volume for available storage of CO2. The objective of this study is to investigate the CO2 storage capacity in different formation types, for different levels of CO2 purity and different injection schedules. To this aim, we analyzed the injection of a CO2-based stream into a depleted gas condensate reservoir and into a saline aquifer using a compositional reservoir simulation model. The dynamics of the reservoir impose a minimum period of injection that is required in order for the storage scheme to benefit from 100% of the reservoir storage capacity. Hence, over and above a certain CO2 injection rate, it becomes meaningless to invest in bigger compressors to increase this rate to reduce the time of injection. When the CO2 stream contains impurities, such as N2 or methane, the storage capacity of the reservoir decreases proportionally to the impure stream's compressibility factor and its concentration of impurities. This finding suggests that an economic optimum between the costs of separation, compression and injection can be determined. Finally, the mass of CO2 sequestrated per pore volume in the equivalent aquifer model is approximately 13 times lower that of the depleted gas condensate reservoir model. This confirms that, because of their low overall compressibility, aquifers offer a far lower ratio of CO2 stored per pore volume than depleted gas condensate reservoirs. However, aquifers tend to have a far larger extent, which often compensates somewhat for this lower ratio and therefore provides storage for significant volumes of CO2

Hydrocarbon/CO{sub 2}/water multiphase equilibrium separations. Final report, July 1, 1993--September 30, 1995

Hydrocarbon (HC)/water and HC/CO{sub 2}/water systems are frequently found in petroleum recovery processes, petroleum refining, and gasification of coals, lignites and tar sands. Objective is to provide techniques for analyzing these mixtures at pressures up to 10,000 psia and temperatures up to 500 F; two laboratory apparatus were developed for this purpose. Three-phase separation data are obtained for mixtures of pure n-alkanes (C{sub 3} to C{sub 20}), CO{sub 2}, and water; and for mixtures of pseudocomponents of crude oils and water. Crude oils are characterized using a modified Whitson`s method. Rigorous equation-of-state computer simulators were developed and validated with experimental data; they are essential for reservoir engineering and enhanced oil recovery

Thermodynamic Modeling of Pure Components Including the Effects of Capillarity

Capillarity is seen in many physical processes where fluids are confined in a porous medium. Fluid properties and flow are both theoretically and experimentally shown to change because of capillary effects. Owing to difficulty and expense in experimentally determining these properties in porous media with small pores, a mechanistic approach is taken to incorporate capillary effects in thermodynamic modeling. The Young–Laplace equation provides an ideal method, making the system a function of pore size and wettability, thus taking into account the porous material properties and fluid-to-material interactions. The method proposed here shows good agreement with both experimental data and molecular simulation. The advantage is its ease of application in thermodynamic modeling and relatively small computation requirement compared to molecular simulation. Because of capillarity, the phase envelope of pure substances is suppressed, indicating a change in phase density and liquid fraction. This method is a powerful tool in describing fluid behavior in porous media