Salinity Of Produced Water Research Articles

Variability in Quantity and Salinity of Produced Water from an Oil Production in South Kuwait

Variability in Quantity and Salinity of Produced Water from an Oil Production in South Kuwait

RETRACTED: The hybrid absorption cooling–desalination and reverse osmosis system to boost energy utilization efficiency

The reverse osmosis (RO) process is the most widely used water softening system, which is used due to its high-performance efficiency. However, this method causes damage to the ecosystem by producing concentrated salt water. This research investigated the integration of the newly proposed absorption cooling–desalination (ACD) hybrid system and the reverse osmosis method. In this method, the brine that comes out of the reverse osmosis is introduced to the evaporator of the ACD system for further distillation. This work is a possible solution for the treatment of reverse osmosis output brine, increasing the recovery rate, minimizing the overall cost of operation, and preserving the ecosystem. Also, by the implementation of this novel unit, excessive cold fresh water is created. The results show that the cooling capacity of the ACD system alone is about 0.346 kW with a coefficient of performance (COP) of 0.774, and it can produce 13.887 cubic meters of water per day at a working temperature of 85 degrees Celsius, which can be easily obtained from low-temperature sources. Compared to the reverse osmosis method alone, the combined method of reverse osmosis and ACD unit proposed in this article causes an overall increase in recovery rate (RR) by 72% and a reduction in electrical energy consumption by 49%. Besides, the overall produced water salinity declined by 59% due to the integration of RO and ACD units.

Forward osmosis performance in extracting water from produced water

Produced water (PW) is a prominent brine waste in the petroleum industry, which can be reused after desalination. In this work, the influence of PW salinity variation and its composition on PW desalination through the forward osmosis process, using cellulose triacetate membrane, was investigated. In the absence of oil, increasing feed salinity from 10 to 20 g/L causes water flux to decrease from 9.43 to 7.33 LM.H. By adding 750 mg/L oil to the feed solutions with different compositions, the resulted water fluxes were almost the same and were around 7.5 LMH. The membrane fouling investigation in long-period operation (5000 min) showed a decrease of 37% in water flux. It was observed that osmotic backwashing, conducted by using 0.5 and 2 M NaCl, and chemical cleaning, treated by sodium dodecyl sulfate solution, recovered the water flux to 75% and 85% of the initial fluxes, respectively.

Origin and geochemistry of formation waters from the lower Eagle Ford Group, Gulf Coast Basin, south central Texas

The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125–165 °C), development of reservoir over-pressuring (400–800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and 87Sr/86Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism generating salinities greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing δ18O and decreasing δ2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is an unknown mechanism allowing for water flow into low permeability reservoirs.

Optimization of multistage membrane distillation system for treating shale gas produced water

Thermal membrane distillation (MD) is an emerging technology to desalinate high-salinity wastewaters, including shale gas produced water to reduce the corresponding water footprint of fracturing operations. In this work, we introduce a rigorous optimization model with energy recovery for the synthesis of multistage direct contact membrane distillation (DCMD) system. The mathematical model (implemented in GAMS software) is formulated via generalized disjunctive programming (GDP) and mixed-integer nonlinear programming (MINLP). To maximize the total amount of water recovered, the outflow brine is fixed close to salt saturation conditions (300 g·kg−1 water) approaching zero liquid discharge (ZLD).A sensitivity analysis is performed to evaluate the system's behavior under different uncertainty sources such as the heat source availability and inlet salinity conditions. The results emphasize the applicability of this promising technology, especially with low steam cost or waste heat, and reveal variable costs and system configurations depending on inlet conditions. For a produced water salinity ranging from 150 g·kg−1 water to 250 g·kg−1 water based on Marcellus play, an optimal treating cost are between 11.5 and 4.4 US$ m−3 is obtained when using low-cost steam. This cost can decrease to 2.8 US$ m−3 when waste heat from shale gas operations is used.

Monitoring wastewater discharge from the oil and gas industry using passive sampling and Danio rerio bioassay as complimentary tools

Produced water (PW) represents the largest volume waste stream in oil and gas production operations from most offshore platforms. PW is difficult to monitor as releases are rapidly diluted and concentrations can reach trace levels. The use of passive samplers can over come this. Here polyethylene (PE) was calibrated for a diverse range of PW pollutants. Zebrafish were exposed to dilutions of PW and passive sampler extracts in order to investigate the relationship between freely dissolved chemical concentrations and acute toxic effects. The raw PW had an LC50 of 13% (percentage of PW in the standardized zebrafish medium). Observed non-viable deformations to embryos (at 5 hpf) included heart and yolk edema, head, spine and tail deformations. The dose-response relationship of lethal effects showed that if 0.0041 g of PE is exposed to this PW, then extracted, 50% of exposed D. rerio will suffer lethal effects. The sum of tested freely dissolved concentrations that led to 50% lethal effects (mortality and non-viable deformations) was 2.32 × 10−4 mg/L for PW and 7.92 × 10−2 mg/L for PE. This implies that exposure to raw PW was more toxic than exposure to PE extracts. This toxicity was attributed both to the presence of contaminants as well as PW salinity. Passive samplers are able to detect very low freely dissolved pollutant concentrations which is important for assessing the spatial dilution of PW releases. Bioassays provide complimentary information as they account for all toxic compounds including those that are not taken up by passive samplers.

Integrated Water-Injection Analysis Uses Salinity as Tracer in Giant Brownfield

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 185872, “Integrated Water-Injection Analysis for a Giant Brownfield,” by A. Ortega, S. Renna, G. Fanello, C. Callegaro, SPE, and I. Bergamo, SPE, Eni, and O. Yehia, SPE, Petrobel, prepared for the 2017 EAGE Annual Conference and Exhibition/SPE Europec, Paris, 12–15 June. The paper has not been peer reviewed. When dealing with giant brownfields, a systematic approach is mandatory to succeed in identifying the main production mechanisms amid the geological and dynamic complexity of the reservoir. In this paper, an integrated work flow is proposed for brownfields where oil production is driven mainly by water injection. Produced-water salinity plays a key role, acting as a natural tracer and, thus, helping avoid additional costs for new data acquisition. Introduction Production-data analysis (PDA) is a well-known method of investigating field performance. Nevertheless, its application in a giant brownfield can be difficult. Analysis can be very complex and time-consuming because of the large quantity of data and data heterogeneity and reliability, especially if the data are gathered through different monitoring systems and technologies. Considering this, a systematic integrated work flow has been developed that focuses on brownfields where water injection has played a key role in oil production. The work flow allows a comprehensive analysis of the water injection through the following steps: Identification of injector/producer connections Fluid-path conceptual models Evaluation of the current water-injection efficiency Water-injection optimization Phase 1, which includes the first two steps, is based mainly on advanced PDA. Integrated analysis of production, pressure, and salinity data allows for the detection of the evolution of injector/producer connections. The main fluid paths in the field then are identified and used to drive and integrate the geological knowledge of the field. The result is a more-robust 3D model, representative of the main highlighted production mechanisms. Phase 2, which includes the third and fourth steps, instead is driven by streamline analysis traced on the dynamic model, which allows for the evaluation of the efficiency of the current water- injection strategy. Water injection then is optimized on the basis of a redistribution of the injection rates, promoting the most-efficient connections to the detriment of the least efficient. The consequent modification of the water paths allows for contact with new, unswept areas, leading to an increase in oil recovery with limited investments. This paper shows the application of the work flow in the context of a wider brownfield-rejuvenation project. In particular, the paper is focused on the setup of easy-to-understand conceptual models and considers how they drive geological evaluations (e.g., faults, layering, contacts) in the realization of a new 3D model. A dynamic model able to reproduce the events since the preliminary history matching confirms the validity of the approach.

The dynamics of hydraulic fracture water confined in nano-pores in shale reservoirs

Hydraulic fracturing treatments and horizontal well technology are central to the success of unconventional oil and gas development. In spite of this success, replicated over several thousand wells over diverse shale plays, hydraulic fracturing for shale wells remains poorly understood. This includes the poor recovery of hydraulic fracture water, the inability to explain the progressive increases in produced water salinity and an incomplete understanding of the potential trapping mechanisms for hydraulic fracture water.In this work, we focus on describing the distribution of saline water in organic and inorganic pores as a function of pore size and pore morphology with the purpose of providing fundamental insights into above questions. A kerogen model is constructed by mimicking the maturation process in a molecular dynamics simulator and it incorporates structural features observed in SEM images including the surface roughness, tortuous paths, material disorder and imperfect pore openings of kerogen pores. This work also extends this kerogen model through the use of oxygenated functional groups to study fluid behavior in partially mature shales associated with non-zero oxygen to carbon ratios.Our results demonstrate that water entrapment mechanism and the distribution of water and ions in organic and inorganic pores are strongly related to the pore-surface mineralogy and pore width. The work in this paper also underscores the importance of kerogen thermal maturity and pore roughness on the accessibility of the kerogen material to water.

Research on Corrosion of Well-Bore Tube and Anticorrosive Measure of Tazhong-1 Gas Field

Natural gas of Tazhong-1 gas field contains 7.7% carbon dioxide and 2.31% hydrogen sulfide, and produced water salinity is up to 140000mg/L,the well-bore tube has seriously potential corrosion destructive with natural gas being exploited. Based on the corrosion type partition of down-hole tube for eighteen production wells of Tazhong-1 gas field, P110,P110S and P110SS corrosion behavior were investigated under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide/carbon dioxide, and corrosion inhibitors were chosen to meet need of anticorrosion of Tazhong-1 gas field. The results show that fifteen wells in eighteen production wells belong to hydrogen sulfide corrosion of both hydrogen sulfide and carbon dioxide influence. Other wells are singular carbon dioxide corrosion. The most severe corrosion of three types of down-hole tubes all occurs at 90°C in both corrosion media, and their corrosion resistance order is respectively P110&gt;P110S&gt;P110SS and P110S&gt;P110SS&gt;P110 under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide and carbon dioxide. The selected anti-temperature corrosion inhibitors (YU-1、YU-4) can control the corrosion rate of three types of down-hole tubular goods within 0.076mm/a in simulated formation water media with carbon dioxide (PCO2=0.08～4.64MPa) or hydrogen sulfide and carbon dioxide (PH2S/Pco2=1.3/4.64Mpa) while added amount of the inhibitor is 120～300mg/L or 200mg/L. All of these provide technical support for safe and fast development of Tazhong-1 gas field.

Using HEM surveys to evaluate disposal of by-product water from CBNG development in the Powder River Basin, Wyoming

Production of methane from thick, extensive coal beds in the Powder River Basin of Wyoming has created water management issues. Since development began in 1997, more than 650 billion liters of water have been produced from approximately 22,000 wells. Infiltration impoundments are used widely to dispose of by-product water from coal bed natural gas (CBNG) production, but their hydrogeologic effects are poorly understood. Helicopter electromagnetic surveys (HEM) were completed in July 2003 and July 2004 to characterize the hydrogeology of an alluvial aquifer along the Powder River. The aquifer is receiving CBNG produced water discharge from infiltration impoundments. HEM data were subjected to Occam’s inversion algorithms to determine the aquifer bulk conductivity, which was then correlated towater salinity using site-specific sampling results. The HEM data provided high-resolution images of salinity levels in the aquifer, a result not attainable using traditional sampling methods. Interpretation of these images reveals clearly the produced water influence on aquifer water quality. Potential shortfalls to this method occur where there is no significant contrast in aquifer salinity and infiltrating produced water salinity and where there might be significant changes in aquifer lithology. Despite these limitations, airborne geophysical methods can provide a broadscale (watershed-scale) tool to evaluate CBNG water disposal, especially in areas where field-based investigations are logistically prohibitive. This research has implications for design and location strategies of future CBNG water surface disposal facilities within the Powder River Basin.

Soil solution and exchange complex response to repeated wetting–drying with modestly saline–sodic water

Coal bed natural gas (CBNG) extraction in the Powder River (PR) Basin of Wyoming and Montana produces modestly saline-sodic wastewater, which may have electrical conductivity (EC) and sodium adsorption ratios (SAR) exceeding accepted thresholds for irrigation (EC = 3 dS m−1, SAR = 12 (mmolc l−1)1/2. As an approach to managing large volumes of CBNG-produced water, treatment processes have been developed to adjust produced water salinity and sodicity to published irrigation guidelines and legislated in-stream standards. The objective of this laboratory study was to assess acute and chronic soil solution EC and SAR responses to various wetting regimes simulating repeated flood irrigation with treated CBNG product water, followed by single rainfall events. Fifty-four soil samples from irrigated fields in southeast Montana were subjected to simulated PR water or CBNG water treated to EC and SAR values accepted as thresholds for designation of saline × sodic water, in a single wetting event, five wetting–drying events, or five wetting–drying events, followed by leaching with distilled water. Resultant saturated paste extract EC (ECe) and SAR of soils having 33% clay. Repeated wetting with PR water having EC of 1.56 dS m−1 and SAR of 4.54 led to SAR 3 dS m−1 and SAR near 12. Subsequent inundation and drainage with distilled water, simulating rainfall-quality leaching, reduced ECe and SAR more often in coarse-textured, high salt content soils than in finer-textured, lower salt content soils. Decreases in ECe upon leaching with distilled water were of greater magnitude than corresponding decreases in SAR, reinforcing supposition of sodium-induced dispersion of fine-textured soils as a consequence of rainfall following irrigation with water having salinity and sodicity levels equal to previously published thresholds.

Monitoring of Steam Stimulation in the McMurray Formation, Athabasca Deposit, Alberta

Because of injectivity considerations, injection schemes in the Athabasca deposit of Alberta often require creation of fractures. Bitumen recovery is linked to the heat and fluid distribution obtained in the reservoir. Hence, to optimize the performance of the process, one needs to monitor closely the mechanical and thermal disturbance caused by steam injection in the reservoir formation. The objectives of the monitoring program described in this paper were (1) to obtain input data for numerical simulation studies so that subsequent optimization of the process could be undertaken, (2) to verify assumptions/speculations on the process mechanisms, and (3) to obtain diagnostic information. Six wells were steam stimulated. The monitored data included tiltmeter records on all wells, injection-pressure/flow-rate data, produced-water salinity analyses, limited pressure-falloff analyses, data from a few pressure observation wells, first-order leveling, and self-potential (SP) and resistivity mapping. From these observations, the existence and nature of fractures around different wells were inferred. The study confirmed that a combination of various monitoring techniques enhances the reliability of interpretations. For obtaining process data in a cost-effective manner, monitoring programs that rely heavily on conventional data collection from injection and production wells are recommended.

Water Salinity of First Eocene Reservoir: Unique Behavior and Influence on Reservoir Engineering Calculations

Summary. The salinity of the produced water from the First Eocene reservoir of the Wafra field was studied through its history. The change in the salinity of the initially produced water (from about 500 to 20,000 ppm NaCl) was attributed to meteoric water that might have entered the reservoir through outcrops west of the field. The correct value of the interstitial water salinity (23,000 ppm) that should be used in estimating the original oil in place (OOIP) by the volumetric method was determined by three different approaches. In addition, a technique to overcome the complex behavior of aquifer salinity in calculating the volumetric OOIP for the First Eocene reservoir is outlined. A study of the change in the produced water salinity of the First Eocene reservoir with time proved that water is dumping from an upper water- bearing zone into the reservoir. Analysis of temperature and noise logs confirmed that this upper water dumping, which apparently has supported the reservoir pressure, occurred behind casing in many deeper wells penetrating the First Eocene reservoir. Introduction History. The Wafra field is located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia, as shown in Fig. 1. This field comprises several major and minor oil accumulations at different depths. The shallowest reservoir in the Wafra field is the First Eocene, which is found at a very shallow depth, and its name reflects the geologic age of the producing limestone zone. The productive area of the Wafra field comprises several productive area of the Wafra field comprises several reservoirs so that, at one location, one deep well can penetrate more than one reservoir. penetrate more than one reservoir. Drilling was begun in the Partitioned Neutral Zone in Dec. 1949 by a Getty Oil Co. and American Independent Oil Co. joint operation at the location of Exploratory Well is on the eastern flank of a large gravity anomaly. This exploratory well encountered a wet sand member at a depth very comparable to its depth in a big reservoir some 19 miles [30 km] north. Drilling activities were continued and seismic surveying was adopted in 1950 in an effort to determine precisely the subsurface structure shown by the gravity precisely the subsurface structure shown by the gravity anomaly. Following the unsuccessful results of Exploratory Wells 2 and 3, drilling operations were suspended awaiting additional geophysical work. The Wafra field was discovered in April 1953 when Exploratory Well 4 proved to penetrate commercial oil accumulation in the proved to penetrate commercial oil accumulation in the Burgan sand. Cores from this and a subsequent well confirmed the presence of oil accumulations in beds overlying the Burgan sand, especially in Eocene' limestones. The well designed to test the productivity of Eocene limestones, spudded on Dec. 31, 1953, proved conclusively that a significant oil accumulation existed in the Copyright 1987 Society of Petroleum Engineers First Eocene limestone at a very shallow depth. The last First Eocene well was completed in Jan. 1963. Currently, the First Eocene reservoir contains more than 200 completions, the majority of which are partially penetrating openhole completions. penetrating openhole completions. Geology. It is known from the stratigraphic column of the Wafra field that the First Eocene reservoir is overlain by the Rus and Dammam formations. The Rus formation is an anhydrite rock that represents a cap rock for the First Eocene reservoir. The Dammam formation is mainly a water-bearing formation with a salinity of about 16,000 ppm. The First Eocene reservoir rock has been described as a marly dolomitic limestone of various porosities. porosities. The First Eocene reservoir consists of two structures known as "main area" (bigger structure) and "west Wafra" (smaller structure). Although the First Eocene limestone in the west Wafra structure is appreciably higher than that in the main area, it is particularly important to note that little or no oil is present in the western flank of the west Wafra structure. present in the western flank of the west Wafra structure. In addition, logs taken from wells penetrating the First Focene limestone suggest a strongly tilting oil/water contact (OWC). The OWC at the eastern flank of the reservoir is about 200 ft [61 m] deeper than at the western flank of the reservoir. These observations imply that oil accumulation in the First Eocene limestone is under hydrodynamic condition. JPT P. 1119