Mid-Continent Water Management for Stimulation Operations

One downside of prolific oil and gas production is the often associated increase in produced water volumes. As hydrocarbon prices and production increase, so do water production and the need for efficient water disposal. This need plus increasing regulatory scrutiny and operators’ environmental stewardship goals have compelled the search for economic methods of safely maximizing - and maintaining - disposal well efficiency. This paper will relate case histories of several salt-water disposal wells in northwestern Louisiana, in which the conventional remediation solution, matrix acid treatments, did not effectively remove near-wellbore damage. Instead, precision bypass fracs were designed to maximize injectivity without fracturing rock beyond the narrow zonal limits set by state regulators. The strict regulations required a precise, scientific approach to stimulation design and operations, including the use of fracture modeling, on-site diagnostics and radioactive tracers. The paper will present regulatory issues, stimulation design process, operational highlights and post-stimulation results for some representative disposal wells. It will also describe improvements made at producing well locations to minimize future stimulation requirements. Finally, it will conclude with some recommended best practices for economical, safe, effective bypass frac design and operations in water disposal wells.

Inconsistent bacterial control and monitoring led to variability in Salt Water Disposal (SWD) well performance and injectivity creating excess costs in biocide applications and remedial work. A metagenomics study using Whole Genome Sequencing (WGS) was conducted to determine the source(s) of problematic microorganisms throughout the process life cycle: Freshwater> Drilling> Completion> Flowback> Produced water> SWD. A total of 30 metagenomes were collected from the 6 process stages and identification and quantification of the major microbial taxa from each of these stages were identified. "Taxonomy to Function" associations were identified for all the major taxa found in the SWD fluids. WGS was performed on positive Sulfate Reducing Bacteria (SRB) and Acid Producing Bacteria (APB) media bottles inoculated in the field for a Flowback sample. Four of the six major taxa found in SWD samples are considered groups of microorganisms known to cause microbiologically influenced corrosion (MIC): Clostridia, methanogens, SRB and Iron Reducing bacteria. Thermovirga and Thermotagae, were the two most abundant taxa found in SWD samples, both thermophilic halophilic fermenting bacteria. The Fe reducing bacteria Shewanella was only detected in Drilling and SWD fluids suggesting its source was Drilling fluids. Completion fluid metagenome profiles from two separate sites followed similar patterns. During middle of completions Proteobacteria phyla were dominant taxa represented mostly by Pseudomonas. Other abundant phyla were all characteristic of polymer degrading bacteria. None of these taxa were dominant populations identified in SWD waters. Fresh water only shared similar taxa with Drilling and Completion fluids. A few minor taxa from Drilling and Completion stages show up as significant taxa in SWD fluids. The majority of taxa found in SWD samples appear to originate from Flowback and Produced waters, although at lower abundances than found in SWD samples. It cannot be determined if the microorganisms found in Flowback and Produced waters were endemic to the formation or come from contaminated source waters, i.e. process equipment used to store and transport water sources. Petrotoga mobilis was the dominant population of bacteria that grew in both media bottles, 96% and 77% for SRB and APB, respectively, while Petrotoga was detected at 14% in the field sample. The most abundant bacteria detected in field sample were Clostridia (38%) while only 2.7% were detected in APB media. SRB media bottle had 0.18% SRB detected by WGS; APB media had 9% SRB population abundance. No SRB were detected in corresponding field sample or below detectable limits (BDL) for WGS methods (<0.01%). WGS was forensically used to successfully identify type and source of problematic microorganism in SWD facilities. Results from media bottle and field sample comparisons stress the importance of developing improved field monitoring techniques that more accurately detect the dominant microorganisms.

Seawater power injectors and saltwater disposal wells are used to maintain reservoir pressure in a carbonate reservoir in Saudi Arabia. Various forms of hydrochloric acid were used to stimulate damaged wells and restore the injectivity of these wells. The forms of the acid used were regular, emulsified, and in-situ gelled acids. Acid diversion was achieved by using a coiled tubing unit, nitrogen foam, in-situ gelation, emulsified acid or combinations of these methods. A comprehensive investigation was undertaken to assess the effectiveness of acid treatments performed in the field and improve the outcome of the acid jobs. Laboratory and field investigations were conducted simultaneously to address formation damage and associated problems. These investigations included coreflood tests to screen various acid formulae, and analysis of field samples to identify the damaging mechanism. More than 80 acid jobs were analyzed in this study. A new empirical coefficient was identified and used to evaluate these jobs. The coefficient was based on: 1) the ratio between the pre and post acid injectivity indices, 2) the rate of decline of normalized well injectivity index, and 3) the incremental cumulative injection from the Hall plot following the acid job and before the first change in the slope. In addition, chemical analysis of acid returns (spent acid) was used to assess the damaging mechanisms and determine the type and concentration of various acid additives. Improper use of emulsified acid and in-situ gelled acid was found to result in poor field results. The outcome of acid jobs was found to be a function of the volume ratio of regular to in-situ gelled acid. Good field results were obtained when the volume of in-situ gelled acid was 15-30% of that of the regular acid (15 wt% HCl). Furthermore, the study confirmed that acid injection using coiled tubing enhanced the efficiency of the acid treatment. This paper highlights the importance of conducting laboratory and field evaluation of acidizing treatments. The following new findings were obtained: A new job index was developed and used to assess acid treatments in the field. Severe formation damage can result from the improper use of in-situ gelled acids. Analysis of spent acid was effectively used to optimize the concentration and type of various acid additives.

The continuous steel coiled tubing manufactured by the ERW induction process features a patented weld allowing for coiled steel flat strips to be milled into continuous lengths of finished tubing and wound onto reels. A coating line was specially configured to apply a bonded three layered epoxy polyethylene coating to the continuous coiled steel tubing in lengths up to 14,400 feet by the straight through endo process. The coated steel tubing was used for high pressure utility lines positioned from a central offshore platform to satellite platforms and were bundled and laid simultaneously from a lay barge. The lines were successfully nstalled offshore in Mobile Bay, Alabama in July, 1991. INTRODUCTION Electronic Resistance Welded (ERW) tubing or pipe is manufactured in a continuous process at the pipe mill. For typical pipeline applications, however, this continuous pipe is cut into 40 foot lengths at the mill, coated, transported to the installation site and then welded back together in the field. Obvious efficiencies result if the pipe can be coated, transported and installed in continuous lengths. Procedures for manufacturing and handling continuous lengths of pipe are well established in the coiled tubing industry. Additionally, the offshore pipeline industry has developed procedures for installing continuous pipe lengths by the reel barge method. This paper describes the combination of these proven tubing/pipeline industry procedures with the continuous application of a high quality coating suitable for offshore pipelines. The continuous steel coiled tubing manufacture is described first, followed by the coating application, and a case history of its use in Mobile Bay, Alabama (Reference 1). TUBING MANUFACTURE Stee1 Coiled Tuber Development Modern coiled tubing technology was first applied in 1969, when l/2 in. OD tubing was used in conjunction with gaseous nitrogen to backwash salt water disposal wells. Since then, available tubing diameters have increased from 1/2 in. to 2 3/8 in. OD. Coiled tubing trucks and skid units capable of running various sizes and lengths are now located in almost every oil and gas producing area of the world. There are presently more than thirty different downhole and fluid flow types of applications for coiled tubing. These applications now include offshore utility lines. Stee1 Selection and Coil Slitting Master coils of steel sheet are received from the steel mill in ten standard thicknesses ranging from 0.067 in. to 0.188 in. Coil lengths for the thinnest and thickest gauges vary from 3,800 feet to 1,800 feet, respectively, and the average coiled weight is 43,000 lbs. Each master coil is identified by a coil number and steel heat number. Individual strips slit from the master coils can be traced to the master coil number throughout the manufacturing process and delivery to the customer. Quality assurance and control is a vital tubing manufacturing function and follows both the welding and mill process to conclusion.

The rapid development of unconventional oil and gas (O&G) extraction around the world produces a significant amount of wastewater that requires appropriate management and disposal. Produced water (PW) is primarily disposed of through saltwater disposal wells, and other reuse/disposal methods include using PW for hydraulic fracturing, enhanced oil recovery, well drilling, evaporation ponds or seepage pits within the O&G field, and transferring PW offsite for management or reuse. Currently, 1–2% of PW in the U.S. is used outside the O&G field after treatment. With the considerable interest in PW reuse to reduce environmental implications and alleviate regional water scarcity, it is imperative to analyze the current regulatory framework for PW management and reuse. In the U.S., PW is subject to a complex set of federal, state, and sometimes local regulations to address the wide range of PW management, construction, and operation practices. Under the supervision of the U.S. Environment Protection Agency (U.S. EPA), different states have their own regulatory agencies and requirements based on state-specific practices and laws. This study analyzed the regulatory framework in major O&G-producing regions surrounding the management of PW, including relevant laws and jurisdictional illustrations of water rules and responsibilities, water quality standards, and PW disposal and current/potential beneficial reuse up to early 2022. The selected eastern states (based on the 98th meridian designated by the U.S. EPA as a tool to separate discharge permitting) include the Appalachian Basin (Marcellus and Utica shale areas of Pennsylvania, Ohio, and West Virginia), Oklahoma, and Texas; and the western states include California, Colorado, New Mexico, and Wyoming. These regions represent different regulations; climates; water quantities; quality diversities; and geologic, geographic, and hydrologic conditions. This review is particularly focused on the water quality standards, reuse practices and scenarios, risks assessment, knowledge gaps, and research needs for the potential reuse of treated PW outside of O&G fields. Given the complexity surrounding PW regulations and rules, this study is intended as preliminary guidance for PW management, and for identifying the knowledge gaps and research needs to reduce the potential impacts of treated PW reuse on the environment and public health. The regulations and experiences learned from these case studies would significantly benefit other states and countries with O&G sources for the protection of their environment and public health.

Water is the liquid of life. It cycles endlessly from air, land, and sea, and makes life on planet Earth possible. The average adult human is made up of roughly 60% water and consumes around 50,000 liters of water in a lifetime. However, this miracle solution can pose its fair share of problems—dangerous currents at sea, flooding on land when too much falls from the sky too fast, and crushing pressures at depths that can hinder ocean exploration. Still, water is a commodity, and no one may know that better than the oil and gas business, where millions of gallons of water are used every day to stimulate complex shale wells into giving up their hydrocarbon resource. In some regions, oil and gas wells do not return nearly the water that is pumped into them. But in areas like the crucial Permian Basin in west Texas, a given well can return up to 12 barrels of produced water for every single barrel of oil. While the oil eventually heads to the sales pipeline, the produced water—a briny mix of injected water, oilfield fluids, and chemicals—has no well-defined, single destination. Some will go into saltwater disposal wells, but regulators have been clamping down on disposal well use and have been resistant to permit for new ones given the levels of seismic activity some believe is related to reinjection. Other volumes will go to recycling centers to be filtered and prepared for reuse in future fracturing jobs. And it just keeps coming. In 2024, the Permian Basin produced more than 20 million B/D of water, a figure projected to exceed 26 million by 2030, according to researchers at B3 Insights. A potential answer to the produced water glut could be on the horizon in the form of data centers. A number of these large scale, AI-driven server farms are currently under construction or coming online in west Texas. The facilities consist of multi-building complexes filled with IT infrastructure for use with cloud storage, data distribution, and artificial intelligence (AI). The AI boom has fueled several new, massive data center projects across the globe. Produced water typically contains total dissolved solids (TDS) concentrations of 30,000 to 300,000 mg/L, making it unfit for reuse as is. However, treatment technologies, including ceramic membrane filtration, electrocoagulation, and ion exchange, can bring the water to spec for industrial cooling applications. For the US, the Permian makes a lot of sense: The water resource is available there for cooling, and the natural gas resource is available for off-grid power. The land is available that these sprawling campuses require. Low population density means fewer neighbors are adversely affected during the construction phase and beyond. If you’ve ever done any home computing that is memory-intensive—something as simple as upscaling an old photo—you likely heard your computer’s fan kick on. The fan is designed to keep things cool as your system accesses more computing power to accomplish the task. AI needs exponentially more computing power to achieve its end product, thus the size of the current crop of data centers.

E&P Notes Round Two in Mexico: 10 More Offshore Fields Awarded Trent Jacobs, JPT Digital Editor The first tender of the second round of Mexico’s oil and gas licensing auctions issued 10 awarded areas to more than a dozen different oil and gas companies. In addition to Mexico-headquartered companies, other winning firms hail from Russia, Malaysia, US, and the Netherlands. Five locations received no bids, including some that were understood to be gas-rich and therefore a challenging investment due to the relatively low-cost gas imports coming from the US. Growing Number of Projects Go Forward, but the Global Backlog is Still Building Stephen Rassenfoss, JPT Emerging Technology Senior Editor There are recent signs of life in the exploration sector, with as many delayed projects getting funding during the first half of 2017 as in all of 2016. A report from consultancy Rystad Energy tempers that assertion by describing the jump in the number of delayed projects getting a final investment decision (FID) as “apparent positive momentum.” On the upside, it reported 17 delayed international projects have received an FID since it started tracking the many delayed projects in 2015 in the wake of the oil price plunge. The development cost of those projects is expected to be USD 78 billion. H2O Midstream-Encana Deal Highlights Water Management Role in US Shale Joel Parshall, JPT Features Editor H2O Midstream’s recent acquisition of produced-water infrastructure from Encana Oil & Gas (USA) in the Permian Basin highlights the growing importance of efficient water management in United States shale plays. The acquisition, announced on 14 June, was concurrent with the execution of an acreage-dedication-based midstream water services agreement, under which H2O Midstream will gather, dispose, and deliver for reuse produced water for a substantial portion of Encana’s acreage position in Howard County, Texas. By terms of the acquisition, H2O Midstream will now own and operate Encana’s existing produced-water gathering system that consists of more than 100 miles of interconnected pipeline and five saltwater disposal wells with a total permitted disposal capacity of 80,000 BWPD. First Oil From Kraken: Offshore Project To Increase UK Production by 15% Trent Jacobs, JPT Digital Editor UK-based EnQuest achieved the delivery of first production from the Kraken offshore oil field on Friday, 23 June. Average production from the heavy-oil project is expected to reach 20,000 B/D of oil by year’s end. Located almost 80 miles to the east of the Shetland Islands, the Kraken field holds an estimated 128 million bbl of reserves, according to EnQuest. The independent explorer has so far drilled and completed 13 wells, seven producers and six injectors. US Crude Oil and Petroleum Products Exports Doubled Over Past 6 Years Pam Boschee, Senior Editor Following the loosening in December 2015 of US restrictions on exporting domestically produced crude oil, the US exported an average of 520,000 B/D, reaching 1.1 million B/D in February— the highest monthly level on record. Crude oil and petroleum product gross exports more than doubled over the past 6 years, increasing from 2.4 million B/D in 2010 to 5.2 million B/D in 2016, according to the US Energy Information Administration.

ABSTRACT: Building a mechanical earth model (MEM) is a challenging task. It requires an extensive collection of data such as logs and core data to build a reliable model. MEM can support decision-making and assuaging the risks linked to wellbore stability, saltwater disposal, CO2 sequestration, fault slippage and induced seismicity. Obtaining the data required to build MEM relies on several costly and time-consuming operations such as core sampling, laboratory analysis, various well logs and well testing. This is while there are instances where data is not available. Therefore, a question arises in regards to the possibility of computing the latter critical components in a relatively less demanding manner using drilling related data. According to the literature, there is a direct relationship between data measured during drilling and actual rock behavior. These relationships, although complex, can be mapped using the combined power of machine learning and data analysis, resulting in accurate real -time estimates during drilling. In this paper, we employ a versatile set of machine learning and deep learning models to accomplish the latter. 1. INTRODUCTION The estimation of stress is a critical component in any geomechanics study. Stress estimation can be applied in several ways in the oil and gas industry. For instance, wellbore stability, where the stress concentrates around the wellbore. Fault stability and induced seismicity, the effect of depletion, the hydraulic fracturing growth and containment, and recently the fracture-driven interaction and poroelastic stress changes due to injection during storage (CO2 and water disposal wells) (Zoback, 2007) There are several approaches for stress estimation documented in the literature. Zoback (2007) suggests the use of frictional limit theory calibrated to diagnostic fracture injection test (DFIT), mini frac, leak of the test (LOT), or Extended Leak off test (XLOT). Sayers et al. (2010) explained the process of estimating stress for an isotropic and an anisotropic medium from logs and core data. The process needs density and sonic logs and, from that, estimates four components (Ostadhassan, 2013): • Overburden Stress • Elastic properties (Young's modulus, Poisson's ratio, Biot Coefficient) • Pore pressure • Horizontal stresses (minimum horizontal stress and maximum horizontal stress) Overburden stress is calculated by integrating the density log from surface to depth z. computing the latter is relatively simpler in regards to the remaining components. The logs calculation results in a dynamic property that needs to be calibrated to a static one using core laboratory experiments. A data that is expensive to get. The pore pressure can be estimated from drilling activity; however, in low permeability formations such as shales, estimating the pore pressure is complicated.

The objective of this paper is to display the Thermal induced fracture effect (TIF) observed in Villano water disposal wells by decreasing the injection water temperature by 20°F (Aug 2012) and 10°F (Dec 2013) through to the installation of air-coolers at surface. Furthermore the application of fracture surveillance workflow and the design, execution and results of a controlled temperature and pressure test in CPF disposal well (Apr 2013) are also presented. The methodology aims to share the results obtained in two different cases ocurred at different times in Villano Field within the Hollin Sandstone formation, allowing improvement of the injectivity in the disposal wells. This work includes comparison of the results and identification of key factors in order to maintain maximum injectivity (100% Producer –Re-Injection water system). Additionally, the implementation of a monitoring program was necessary for a daily surveillance of the injection temperature and well behavior. Finally, field tests performed in another location (CPF) in which the injection temperature was controlled by a heat exchanger. The results were used to evaluate the differences between the documented cases and the Villano TIF cases. Thermal fracture effects in Villano increased the injection rate by 34K bwpd which resulted in significant savings as new disposal well was not required. The thermal effect was reached with a low temperature reduction (20°F and 10°F), instead of the 50°F+ documented; the maximum reduction in the thermo elastic stress was around 26.5 psi/°F (Propped Fractured well) and 21.7 psi/°F (Non – propped fractured wells) which decreased the injection pressure by 530 psi 217 Psi respectively. Surveillance data suggests that the fractures will remain constant or will continue to grow by maintaining a low temperature. Documented studies advise that the effect is maintained when the temperature is increased however, tests performed in CPF disposal well confirmed that the effect is not permanent if the injection conditions are removed. In the particular cases of Villano and CPF fields, the injectivity is directly proportional to the temperature.

Subsurface disposal of salt water coproduced with oil and gas has become a critical issue in the United States because of linkages with induced seismicity, as seen in Oklahoma and northcentral Texas. Here, we assess the spatiotemporal and stratigraphic variations of salt-water disposal (SWD) volumes in the Permian Basin. The results of this analysis provide critical input into integrated assessments needed for handling of produced water and for emerging concerns, such as induced seismicity. Wellbore architecture, permits, and disposal volumes were compiled, interpreted for disposal intervals and geologic targets, and summarized at formation, subregion, a 100-mi2 (260-km2) area, and monthly volumes for the years 1978–2016. Geologic targets were interpreted by intersecting the disposal intervals with gridded stratigraphic horizons and by reviewing well logs where available. A total of 30 billion bbl (∼5 trillion L) were disposed into 73 geologic units within 6 subregions via 8201 active SWD wells for 39 yr. Most disposal occurred in the Midland Basin and Central Basin Platform (CBP) over the first 34 yr but shifted from the CBP to the Delaware Basin over the last 5 yr (2011–2016) with the expansion of unconventional oil and gas production. Approximately half of the salt water is disposed above the major unconventional reservoirs into Guadalupian-aged formations, raising concerns of overpressuring and interference with production. Operators are exploring deeper SWD targets; however, proximity to crystalline basement poses concerns for high drilling costs and the potential for induced seismicity by reactivation of deep-seated faults.

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

Usually, some amount of unwanted water is being produced along with oil production in most of the oil fields. These waters are dangerous to environment and must be managed safely. In most cases, they are injected into water disposal wells. Scale formation and well plugging during water injection to disposal wells is a critical problem in waste water management. Main reasons for inorganic scale formation in these wells are incompatibilities of injection water and reservoir water, and thermodynamics condition variation of injection water. These mechanisms lead to the mineral scales precipitation and consequently, they are deposited in porous media which leads to injection rate reduction in water disposal wells. The critical place of scale formation is the well bottom. It is the entrance of injected fluids and commonly results in the increase of injection pressure and reduction of water injection. In the current study, the effect of pressure and temperature would be assessed on precipitation of inorganic scale by lab testing and software simulation at different mixing ratio of injection water to formation water. Also, some core flooding tests are run to evaluate the effect of deposited mineral scales on water injection process in the core samples. All input data of software modeling and core samples belong to a water injection well in a sand stone reservoir in south west of Iran.

This paper evaluates water management practices among leading operators in the Permian Basin to assess their strategies, technologies, regulatory strategies, and treatment methods. The aim is to identify key efficiencies, challenges, and lessons learned that could provide valuable insights for operators in the Middle East seeking to optimize water management in unconventional resources. This study utilizes a benchmarking process by gathering data from several sources such as publicly accessible sources, including regulatory filings and operators reports. The focus is on major operators based on their activity levels within the Permian Basin to ensure a representative sample of the most influential players. Key metrics are evaluated such as the number and location of saltwater disposal wells, ratio of water injected versus recycled, and water treatment and disposal practices along with estimated costs. This paper also examines transportation methods such as trucking, piping, and automation adoption, assessing each operator’s cost efficiency. Results clearly demonstrate that disposal wells are still a main conduit for removing water from the hydrogeologic cycle in the Permian. However, as seismic activity around certain locations near faults increases, new approaches for managed produced water in arid grasslands are being discussed and tested. Industry has already dramatically improved its ability to recycle within industry, with over 80% of New Mexico completion volumes, and an estimated 40-60% of Texas completion volumes now coming from treated Produced Water (14). However, the volumes of Produced Water are so great that even at peak recycling rates, only ~20-25% of produced water is recycled as a Completion fluid, leaving a balance of 75-80% of produced water which still needs to be safely dispatched (1). Major operating companies are now aggressively employing strategies for separating oil, gas and water, followed by further "clean up" of the water fraction by removing residual solids and oil plus organics to generate a clean brine for recycling. As a next step in treatment, salt removal or desalination is being investigated using innovative technologies such as thermal processes followed by condensation, mechanical vapor recompression, and various membrane technologies to produce treated water for agriculture and other potable water applications, with pilot studies underway. Results will be discussed more fully. The findings of this study contribute to the knowledge base for Middle East operators and engineers, providing valuable insight and guidance into water management practices in unconventional reservoirs. By analyzing recycling rates, treatment technologies, and regulatory impacts, this study identifies best practices that enhance operational efficiency and sustainability and reduce operating risks.

Produced water (PW) is generated in a large amount worldwide and has complex compositions. PW treatment is required to meet environmental regulations as well as reuse and recycling of PW. Meanwhile, plenty of water is needed for slickwater fracturing applications during unconventional reservoir development. This study aims to find effective ways to treat PW and formulate it into slickwater for fracturing operations to save fresh water and improve water sustainability. A synthetic high salinity oily produced water with overall salinity of more than 100,000 ppm was used. Searching effective chemicals and optimizing their dosages for PW treatment were based on measurements of oil-water separation time, floc volume and transmission intensity using stability analyzer which allows a step-by-step vertical scanning of dispersions. After treatment, PW was used to prepare slickwater. Hydration time and viscosity of selected dry friction reducer (DFR) in the PW were measured by rheometer, and friction reduction performance of the slickwater was evaluated by a standard friction flow loop system. The developed chemicals are efficient and economical for the PW treatment with short oil-water separation time, high oil removal efficiency, and low chemical dosage. Floc formed quickly and separated from the water phase in several minutes after chemical addition and clear bottom phase was observed. The oil content was reduced to less than 20ppm and total suspended solid was reduced by 80% within 10 minutes with the addition of 30ppm chemical. DFRs for unconventional reservoir development are selected in this work because of simple logistic handling under harsh environmental conditions comparing to liquid and emulsified friction reducers. An optimized DFR formulation which was compatible with treated PW was developed. The DFR was able to totally dissolve in PW in 1 minute. The viscosity of DFR in treated PW at different temperatures was almost same as that of solution prepared using synthetic brine. The friction reduction can reach up to 75% in less than 2 minutes. This indicates that the PW after treatment is applicable for either re-injection or reuse as base water for slickwater fracturing. This work provides the insight of oily produced water treatment by chemical method for slickwater fracturing. This significantly alleviates oilfield produced water discharge and improves water sustainability by saving large volume of fresh water for unconventional reservoir development.

Conventional phospholipid (PL) recovery and purification techniques use large volumes of fresh water, organic solvent, and alcohols. Due to diminishing fresh water resources and concerns about the use of organic solvents, the development of more environmentally benign processing techniques is vital to the sustainability of PL production.This article considers three greener alternatives to conventional processing technologies.