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In the past decade, the low dosage hydrate inhibitors (LDHIs) - which include kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) - have seen increasing use for gas hydrate prevention in hydrocarbon production operations, offering significant CAPEX/OPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). Typically dosed at < 2.5% in produced water, KHIs were historically considered primarily as hydrate nucleation inhibitors, although in recent years focus has shifted towards their powerful crystal growth inhibition properties. Beginning at low aqueous concentrations, KHI polymers induce a number of highly repeatable, well-defined, hydrate crystal growth inhibition (CGI) regions as a function of subcooling, varying from complete inhibition, through long induction times and reduced growth rates, to final failure/uninhibited growth. This behaviour can be used to robustly assess KHIs for field use, as we have previously demonstrated through development of the KHI CGI evaluation method, which is now used as standard by a number of laboratories. During CGI testing, it is not uncommon to observe anomalous (should be stable thermodynamically) hydrate dissociation in the presence of KHIs, although very little is understood regarding this phenomenon. In this work, we present the initial findings of experimental studies aimed at investigating this anomalous dissociation for different commercial base polymers. Results demonstrate that, in addition to inhibiting hydrate growth/nucleation, low dosages (e.g. 0.5% and 0.25%) of KHI polymers can induce partial or complete hydrate dissociation, with this process largely generic to different KHIs. However, some KHI polymers cause catastrophic hydrate growth after nucleation begins and these polymers show no ability to dissociate hydrates, so this hydrate dissociation ability is not universal to all KHI Polymers. The cause of this dissociation is unclear, although it is postulated to result from interactions between the KHI and inherent hydrate morphological and/or structural changes. In addition to improving confidence in KHI field use, findings potentially have novel applications with respect to hydrate plug remediation and gas production from naturally occurring hydrates in oceanic/permafrost sediments. • Gas hydrate dissociation using kinetic hydrate inhibitors. • PVCap, Luvicap-EG, and Luvicap Bio induce hydrate dissociation inside hydrate phase boundary. • The recrystallization is suggested as being the root of the anomalous dissociation. [ABSTRACT FROM AUTHOR]

Rapidly removing oil from emulsified produced water has become one of the most common problems that needs to be urgently resolved as gas-field exploitation enters its later stages, and an effective technique has not yet been established thus far. This paper introduces experimental research and further industrial application of a novel combined fibrous coalescer in the treatment of produced water in an offshore gas-field. Metal and oleophilic polymer fibers were combined at a certain proportion and woven into a fibrous bed with specific structural and geometric properties, which was used as the core separation component of the coalescer. The industrial operation results showed that the oil pollutant concentration of the produced water treated with the novel coalescer was reduced from 1200 to 25 mg/L, well below the 45 mg/L national discharge standard, under a residence time of 180 s and pressure drop of 30 psi. This is the first successful and significant industrial application of the technique in an offshore gas-field, providing a promising alternative for resolving the difficulty of produced water treatment in similar gas-fields, promoting further applications of the technique, and contributing to cleaner production and marine conservation. Image 1 • Reduce oil pollutant emission from produced water in offshore gas production. • A novel coalescence technique was developed and applied successfully. • Offer a solution for treating seriously emulsified produced water. [ABSTRACT FROM AUTHOR]

Abstract Smart water injection is recognized as an effective EOR process to alter the wettability and interfacial tension to obtain higher micro/macro sweep efficiencies. This water contains reactive ions such as Mg 2 + , Ca 2 + and SO 4 2 - which can act as potential-determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective water-flood process, especially in tight carbonate reservoirs, is the chemical incompatibility between the formation brine and the injecting water. In the present study, laboratory fluid compatibility tests were carried out and software simulation was done to investigate the most important challenges of the water-flooding process in one of the West Iranian oil fields with the possibility of developing formation damage. The chemical incompatibility between injected smart water and formation water leads to inorganic scale deposition. For this purpose, sea water as the basis of smart water was prepared to examine the impact of determining ions such as Mg 2 + , Ca 2 + , and SO 4 2 - and, to examine the effect of the salinity of the injected brine on the total amount of CaSO 4 scale precipitation. According to the obtained results, as the concentration of SO 4 2 - in the injecting sea water increases from 1 / 4 to 1 times its concentration in ordinary sea water, the CaSO 4 precipitation increases smoothly, and then it is accelerated as the concentration increases beyond that. Therefore, even though the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, calcium sulfate deposition was noticed, resulting in permanent formation damage. The test results also showed that CaSO 4 deposition increases as the concentration of Ca 2 + in the sea water increases. On the other hand, the presence of Mg 2 + ion in sea water increases the solubility of CaSO 4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that there is an optimum salinity in which the minimum amount of mineral scale is deposited, and 5 times dilution of sea water is determined as the optimum salinity. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage. In the end, this paper discusses the laboratory fluid compatibility results and scale prediction analysis for different smart water injection utilizations. Highlights • Modifying the salinity and ionic composition of the injected water can have impact on calcium sulfate scale precipitation. • Salinity and composition of injected sea water are two important parameters that affect the solubility product of CaSO 4 . • The results showed that the sulfate ions should be in the range of 1⁄4 to 1 times in SW for lower risk of formation damage. • Despite to Ca 2 + and SO 4 2 - ions, the presence of Mg 2 + ions in the injection SW increases the solubility product of CaSO 4 . • The simulation results showed that the solubility product of CaSO 4 cannot be well-predicted without laboratory tests. [ABSTRACT FROM AUTHOR]

Abstract Formation water, found in oil deposits, is highly corrosive. By utilizing flow phenomena and surface tension forces in smaller channels (e.g., Eötvös number less than one), these fluids can be separated, thus altering corrosion and the pressure required for transport. This research investigates the effects of wall wettability on oil-water flow regimes and pressure drops. Oil-water flows were studied in 3.5-mm hydrophilic borosilicate glass and 4.0-mm hydrophobic fluorinated ethylene propylene (FEP) channels using Parol 100 mineral oil (i.e., density of 840 kg/m3 and viscosity of 0.0208 Pa s) and tap water (i.e., 997 kg/m3 and a viscosity of 0.001 Pa s). For these oil-water combinations, glass was water wetting (i.e., contact angle of 67° for a water droplet submerged in oil on glass) and FEP was water repelling (i.e., contact angle of 93° for a water droplet submerged in oil on FEP) under static conditions. Flow regimes and pressure drops were recorded for a range of oil superficial velocities [i.e., 0.31–3.7 m/s (glass) and 0.23–2.7 m/s (FEP)] and water superficial velocities [i.e., 0.080m/s–5.5 m/s (glass) and 0.060–5.5 m/s (FEP)]. Stratified, intermittent, annular, and dispersed flow regimes were observed in both tubes. Additional inverted and dual flow regimes were observed in the hydrophobic FEP; oil wetted the wall in inverted flows, and flow regimes occurred inside of another flow regime in dual flows (e.g., inverted-annular intermittent). The modified Weber number indicated whether the walls were wetted by oil, mixed oil and water, or water. Pressure drops were found to be correlated to the flow regime with increased pressure drops observed when oil fully or partially wetted the wall. Graphical abstract Image 1 Highlights • Investigated oil-water flows in hydrophilic and hydrophobic 4-mm channels. • Stratified, intermittent, annular, and dispersed flow regimes in both channels. • Inverted (i.e., oil wetting) flow regimes observed in the hydrophobic channel. • Pressure drops depended on flow regimes, tube material, and wetting fluid. [ABSTRACT FROM AUTHOR]

Interaction between injection water (IW) and formation water (FW) salinities during microbial flooding critically influences the dynamics of in-situ Microbial Enhanced Oil Recovery (MEOR) processes. However, the lack in understanding of the influence of salinity interactions on MEOR processes had led to unreliable prediction of MEOR performance, and non-development of efficient strategies to improve the MEOR performance. Hence, analysing the influence of salinity interactions on MEOR processes would make the prediction of MEOR processes more realistic, and thereby, it could assist in development of suitable strategies to enhance the oil recovery. Thus, in the present study, a novel mathematical model has been developed by coupling the Multiple Ion (Na, Ca, Mg, Cl, SO 4 ) Exchange (MIE) transport model with the MEOR model, and it has been solved numerically by finite volume technique. The MIE transport model simulates the resultant spatial and temporal salinity distribution within the reservoir due to the mixing of IW and FW salinities during microbial flooding. The MEOR model simulates the coupled multiphase fluid (water-oil) flow and multispecies (microbes-nutrients) reactive transport processes within the reservoir, and finally predicts the oil recovery due to microbial flooding. Subsequently, the influence of IW and FW at different salinities on MEOR processes has been investigated. The present numerical results were validated with the experimental and analytical results. The results clearly suggest that the in-situ FW salinity was completely altered to the externally injected IW salinity, and this IW salinity dictates the entire MEOR processes as against the conventionally assumed FW salinity. Further, it is revealed that lowering the IW salinity from 0.5M to 0.1M had recovered 4.5%–14% of Original Oil in Place (OOIP) higher than that of conventionally used IW (sea water) for microbial flooding. Moreover, the MEOR performance could be enhanced significantly in reservoirs with any initial FW salinity by adopting IW salinity closer to the salinity condition at which the microbial growth and biosurfactant production is maximum. Finally, the present work assists in the selection of suitable reservoir, microbes, and IW salinity for attaining maximum oil recovery by microbial flooding. Thus, the present work helps to enhance the performance of MEOR technique. [ABSTRACT FROM AUTHOR]

Class I and Class II waste re-injection are the most important methods for disposing of fluid in North Dakota: in 2007, more than 96% of produced water were disposed of using underground injection, and by 2012 all produced water was being managed by underground injection. While Class II injection covers waste produced from most Exploration & Production (E&P) activities, Class I injection wells are used for disposing of a special class of industrial wastes, including waste generated by petroleum refining, metal production, chemical production, pharmaceutical production, commercial disposal, and food production. Non-hazardous industrial waste and Naturally Occurring Radioactive Materials (NORM) not associated with E&P can also be injected using Class I wells. In all cases, the primary concern for permitting and safe operations is to (1) predict the movement of the injected waste to ensure that it stays within pre-defined formations, and (2) ensure that pore-pressure increases caused by injection do not impact neighboring offset wells. Results from a geochemical study of the feasibility of disposal into the Dakota Sands (Inyan Kara formation) in North Dakota is being presented. Analyses were made using a compositional reservoir simulation (REVEAL) to predict the pore-pressure distribution, direction and movement of the injected fluid, as well as chemical reactions between formation brine/waste/formation rocks and the effect of these chemical reactions on formation injectivity and cap rock integrity. Forecasts indicate that for over 50 years of injection, the injected wastes will be completely trapped within the Dakota Sands (no fluid flow is expected to penetrate through the cap rock) and injection pressures are expected to remain well below the estimated fracture pressure. While the Inyan Kara formation is therefore a reasonable storage trap for industrial wastes, carbonate and sulfate scales may cause near wellbore formation damage and rising wellhead pressures which operators will need to address. [ABSTRACT FROM AUTHOR]

Prediction of pH-dependent carbonate and sulphide scale in oil and gas operations is of major importance to allow effective mitigation strategies to be put in place. Nevertheless, there is not a standard industry procedure which clearly describes how to obtain scale prediction profiles starting from commonly available field data. This work presents a clear and systematic step-by-step procedure to obtain carbonate and sulphide scale prediction profiles from the reservoir to the first stage of separation using commonly available field data, thus closing the gap between surface and subsurface three phase calculations. As presented here, any suitable aqueous phase mineral chemistry model can be used with any Pressure/Volume/Temperature (PVT, phase prediction) software to carry out these calculations and the models used here are referenced. [ABSTRACT FROM AUTHOR]

Recent development in oil field tracer technologies has been focused on implementations that increase oil recovery through optimized algorithms for production, aided by the addition of high fidelity interwell tracer data that improve reservoir history match. Prerequisites for successful tracer campaigns in oil reservoirs at a large scale not only include low-cost tracer materials with a rich palette of uniquely identifiable tracers, but also high sensitivity, easy-to-use trace-level detection and analysis methodologies. A fully automated in-line separation and detection protocol can simultaneously address challenges in throughput (speed and efficiencies) and accuracy (minimization of error-prone steps) of multi-tracer detection. Our previously reported tracer materials consist of barcoded variants of the dipicolinic acid (DPA) molecules that sensitize the emission of lanthanide ions. We have capitalized on the time-gated optical luminescence detectability of this sensitizer-lanthanide ion complex to reject background oil fluorescence, achieving high detection sensitivity in particularly complex oil field produced brine matrix. However, automation of the detection and analysis process has been hindered by opposing requirements in the integration of chromatography instrumentation (separation resolution) with in-line mixing (dispersion due to increase in residence time), and high sensitivity spectrofluorimetry (long integration time). We overcome this major barrier to implementing an in-line detection design under flow conditions by utilizing a microfluidic mixing chip which offers a high degree of mixing in a very short fluidic path length for the in-flow chelation of lanthanide ion to the chromatographically resolved tracer variants, and a flow-cell fluorescence detector at the output of the high-performance liquid chromatography (HPLC). In this study, we demonstrated the rapid in-line detection of a mixture of three different DPA-based barcoded tracers at ultra-trace level. An automated solid phase extraction (SPE) pre-concentration stage is added to the input of the HPLC, further lowering the detection limit down to a level of 100 pM (pico molar) of tracer molecules. As developed, the complete automated system offers unprecedented sensitivity of detection and accelerated oil field tracer analysis that approaches "near real-time" speed. • A fully automated in-line separation and detection protocol for multi-tracer detection. • Time-gated optical detection of the sensitizer-lanthanide ion complex. • Eliminating background oil fluorescence achieves high detection sensitivity. • Conducted under flow conditions by utilizing a microfluidic mixing chip for the efficient tracer lanthanide chelation. • Unprecedented sensitivity of detection and accelerated oil field tracer analysis. [ABSTRACT FROM AUTHOR]

Leading unconventional plays in the US such as Eagle Ford, Bakken and Niobrara have average gas oil ratio (GOR) ranging from 500 SCF/STB to 4000 SCF/STB. The behavior of produced GOR is difficult to characterize for unconventional reservoirs. Initial reservoir pressure ( P i ), well operating pressure and fluid properties directly related to Pressure Volume Temperature (PVT) such as bubble point pressure ( P b ), initial GOR ( R si ), GOR at P b ( R sb ), GOR at flowing bottom hole pressure ( R sw ) are the key factors affecting produced GOR from low permeability (10–5000 nD) reservoirs. Gas production may be controlled and kept in the desired production window by maintaining the flowing bottom hole pressure ( P wf or BHP). A single characteristic factor affecting the produced GOR is found to be ( 1 − R sw R sb ) ( 1 − P wf P b ) ( 1 − P wf P i ) . The first part ( 1 − R sw R sb ) considers the fluid PVT effect with operating condition, second part ( 1 − P wf P b ) accounts for the proximity of operating pressure with bubble point pressure and third part ( 1 − P wf P i ) is the drawdown effect. Production behavior in terms of produced GOR can be predicted using this single factor. Produced GOR increases with time when this factor exceeds a certain value, while, little or no deviations from the initial GOR are observed for lower values of the factor. It should be noted that the predictive factor does not depend on reservoir matrix permeability. Initially, a factor ( P b − P wf ) ( P i − P wf ) comprising only pressure terms was developed which failed to capture the behavior of produced GOR. Initial reservoir pressure and flowing bottom hole pressure ( P wf ) are varied to study a wide range of reservoirs and production conditions. The oil rates, recovery factor and produced GOR are the key production parameters for this study. Suitability of this factor is validated by comparing simulation data with field data. The optimum well operating pressure can also be determined using this factor to maximize recovery. Deviation of GOR from its initial value is higher for low permeability reservoirs. Higher gas and oil are recovered from reservoirs with higher initial gas oil ratios ( R si ). [ABSTRACT FROM AUTHOR]

Wastewater from shale oil and gas wells contains high levels of organic and inorganic compounds, and the beneficial reuse of produced water requires some level of treatment to remove emulsified oil and grease, suspended solids, and multivalent ions. It is important to identify the quantity and makeup of solids in produced water, so that an optimized reuse or treatment approach can be achieved. This study provides a qualitative and quantitative characterization of solids in frac flowback and produced water from five horizontal wells at two separate sites in the Wattenberg field of Northern Colorado. Difference in solids from wells fractured with fresh water and recycled water is compared in this study, and their distribution and characterization are identified by particle size distribution measurement and X-ray photoelectron spectroscopy (XPS). Results show that particle sizes were smaller and more uniform in produced water samples collected during the first week of production from the wells fractured with recycled water, suggesting that the recycled water was more compatible with the shale formation and wells fractured with recycled water tend to clean out faster. [ABSTRACT FROM AUTHOR]

This paper presents an easily-implemented assay method designed to detect mineral scale inhibitors, especially at low concentrations, in oil and gas produced water. The scale inhibitor concentration is determined using standard addition method, based on a semi-empirical linear relationship between scale inhibitor concentration and the logarithm of scale induction time. If a water sample contains only one scale inhibitor, this method will measure this inhibitor concentration directly. If multiple scale inhibitors are present, this method will detect their total scale inhibition efficiency. The method has successfully detected seven representative scale inhibitors at 0.3, 0.5, 1.0 mg/L in two laboratory prepared produced water samples. It has also been applied to scale inhibitor detection in real produced waters from oil field. This method features extremely low detection limit (0.05 mg/L inhibitor), applicability on a wide variety of scale inhibitors, and being easy to implement. By giving accurate determination of scale inhibitor efficiency, this method could enable better scaling control. [ABSTRACT FROM AUTHOR]

A side effect of hydraulic fracturing (HF) is the inoculation of the subsurface with surficial microorganisms, many of which could affect production and the chemistry of produced water (PW). There is little knowledge of what organisms are selected for once brought to the subsurface. The current practice to control microbial growth is to include a biocide in the HF fluids. However, biocides add a significant cost to these fluids and has potential consequences to health, safety, and the environment. In this study, we evaluate the microbial community composition of PW and freshwater in the Eagle Ford Shale (EF) to determine what organisms survive in production wells during the HF process. We also assess the effectiveness and necessity of the tri-n-butyl tetradecyl phosphonium chloride (TTPC) biocide for controlling microbial growth in these wells. At greater than 4 km depth, temperatures in EF are >160 °C conditions that do not support viable microbial communities, but at shallower depths, microbial communities may be viable. Freshwater and PW samples were collected and cultured in representative subsurface conditions at 128 °C and 60 °C, in the presence or absence of biocide and measured for their composition and viability using molecular methods and microscopy. Results indicate the presence of a diverse microbial community and these communities contain populations of microorganisms that may have the potential to affect production such as through hydrocarbon degradation and bioclogging. Furthermore, laboratory experiments simulating EF downhole conditions show that cells lose viability due to high temperatures, regardless of biocide. At lower temperatures, >50% of viable cells remain in cultures even with biocide present. Results imply that at depth, introduced cells are sterilized due to temperature while at shallower depths, TTPC may not be completely effective in biomass control, prompting the need to further explore options for microbial control. [ABSTRACT FROM AUTHOR]

In this paper, a novel flocculant with the characteristics of both quaternary ammonium salt cation and dithiocarbamate anion was synthesized. Firstly, a cationic polymer having secondary amine side groups was synthesized by using cationic monomer and diallyl amine (DAA) as monomers via aqueous solution polymerization, and then the secondary amine was modified by carbon disulfide (CS 2) to prepare the zwitterion flocculant. By using the oil removal as index, the effects of cationic monomer type, monomer concentration, mass ratio of cationic monomer to DAA, initiator concentration, polymerization temperature and time on the copolymerization results were investigated. The recommended rational condition was as follows: cationic monomer was methacryloxyethyltrimethyl ammonium chloride (DMC), monomer concentration was 50 wt%, mass ratio of DMC:DAA = 4:1, initiator was ammonium persulfate (APS) and its concentration was 0.4 wt%, and polymerization temperature was 60 °C for 8 h. The zwitterion flocculant obtained at the recommended condition had a removal of 99.5% at the dosage of 300 mg/L for produced water obtained from an offshore oilfield. In addition, the flocculation mechanism of the zwitterion flocculant was studied. According to the results of zeta potential measurement and floc morphology, it can be found that the quaternary ammonium salt unit in the zwitterion flocculant can bridge and flocculate oil droplets by destroying the stability of oil droplets in produced water through electrostatic neutralization, while the dithiocarbamate unit can interact with Fe2+ in produced water to form a network structure to catch flocculated oil droplets, and the synergistic effect of quaternary ammonium salt unit and dithiocarbamate unit is helpful for achieving the good flocculation result. The results provide a new selection for produced water treatment. • A novel zwitterion flocculant was synthesized by quaternary ammonium salt cation and dithiocarbamate anion. • Under the same conditions, the oil removal of zwitterion flocculant was much higher than that of cationic flocculant. • Synergistic effect of bridging flocculation and net capturing flocculation for produced water treatment. [ABSTRACT FROM AUTHOR]

Polymer flooding improves the mobility ratio by mainly increasing the injected water viscosity. Typically, these projects minimize the volume of polymer due to economic aspects since the polymer cost significantly affects operation expenditures. However, the injection of a single slug sometimes produces an abrupt viscosity transition at the slug tail, and the chase water forms fingers that can bypass the slug, destroying its integrity. Injecting gradually more dilute slugs mitigates viscous fingering and reduces polymer mass. The scarce field applications, scarce testing at laboratory scale, and the absence of simulations discussion drove the interest in the subject. This study implements and evaluates a numerical simulation by integrating laboratory scale data – bulk rheology, single- and two-phase core floodings – and then history matching graded viscosity core flooding. The results were compared using performance indicators and validated with three laboratory experiments from the literature. The experiments consist of one continuous injection core flood and two core floods using grading viscosity with similar polymer injected mass, one with two slugs and another with three polymer slugs. Experimental and simulated history data for oil recovery and cumulative water matched with less than 5% of normalized error. Events such as water and polymer breakthroughs were well represented. The performance indicators revealed the three slugs test showed the best polymer utility factor for oil/water and best injectivity. On the other hand, the two slugs test reached higher final incremental oil recovery. This work contributes to data integration and extended discussions necessary to enable tailoring and motivating applications of polymer viscosity grading, to save polymer mass and reduce the produced water. • The workflow integrates laboratory data to improve polymer flood modeling. • The workflow was validated using experimental core floods from the literature. • The study clarifies the polymer flooding optimization by using viscous grading. • The waterflood modeling is a key step to model the polymer flood. [ABSTRACT FROM AUTHOR]

Oilfield produced water (OPW) contains not only a complex mixture of organic and inorganic compounds, but also a significant amount of suspend solids and oil and grease (O&G), that need to be almost completely removed prior to reinjection (reuse) in oilfield reservoirs. For the separation of both contaminants from OPW, membrane technology has been described as a potential solution. Therefore, for this study, a multichannel ultrafiltration ceramic membrane (ZrO 2 ) was used in experiments. The effect of operational conditions on membrane filtration efficiency and the membrane cleaning strategy were investigated using real OPW. The permeate obtained with the membranes was free of suspended solids and presented an O&G content under 5 mg L −1 . Based on the results obtained, it is possible to highlight the ceramic membrane separation process as a promising technology for treating OPW in offshore units, being capable to generate a permeate stream suitable for reinjection in restrictive oilfield reservoirs. [ABSTRACT FROM AUTHOR]

Efficient removal of residual oil from produced water (PW) is a challenging but crucial task to meet the increasingly stringent environmental regulations. The current study presents lab-made magnetite particles coated with different amounts of oleic acid (OA) as an efficient and environment-friendly solution for the removal of low concentrations of oil from PW. Performance of the particles in oil removal experiments was studied as a function of the coating factor, adsorption time, oil to the particle concentration ratio and concentrations of emulsifier and salt. Furthermore, reusability of the particles after regeneration through solvent washing and centrifugation was studied. It was observed that the oil removal efficiency of the particles improves by increasing the OA coating factor up to 32 and decreases thereafter. Increasing oil to the particle concentration ratio boosted oil removed per unit time as well as the final oil removal efficiency. Salinity alone did not disturb the oil removal efficiency of the particles whereas oil adsorption efficiency was negatively affected due to the presence of emulsifier alone or in combination with the salinity. Adsorption of oil on the particles followed a Freundlich isotherm model and the kinetic was described by the pseudo-second-order model. Solvent washing completely restored the performance of the particles and was found to be more effective than centrifugation. It was concluded that the proposed particles offer a promising and highly efficient solution for the removal of residual oil from PW. • Magnetic particles were synthesized by coating oleic acid on magnetite. • The coated particles lowered the oil concentration in produced water as low as 1 ppm. • The oil removal efficiency could be customized by changing the oil to particle concentration ratio. • The particles were regeneratable through solvent washing. [ABSTRACT FROM AUTHOR]

A metadata analysis was conducted to analyze the impact of several operating conditions on the biological removal of chemical oxygen demand (COD) from produced water (PW). Operating conditions including temperature, salinity, oxygen availability, treatment technology, microorganism type, and treatment scale were investigated. No limiting maximum COD elimination capacity was reported in the literature, signaling the need to experiment with higher COD concentrations at reduced retention times to identify if such a limit exists. The maximum recorded COD elimination capacity of PW was achieved under low salinity and aerobic conditions in a membrane bioreactor using oil-degradation bacteria on a laboratory scale. Suspended growth exhibited maximum COD removal efficiency, and membrane bioreactors were the most studied technique and achieved the highest performance. Superior COD removal efficiency was realized under hypersaline conditions; however, the COD removal efficiency under freshwater conditions was higher than that under hypersaline conditions. [Display omitted] • Maximum COD EC was achieved under low salinity and aerobic conditions. • No limiting maximum COD elimination capacity was reported in literature. • Membrane bioreactor treatment was the most common treatment method (COD EC > 1175 mg/L/h). • High COD removal efficiency was realized under hypersaline conditions. [ABSTRACT FROM AUTHOR]

Well operation optimization is vital in maximizing the net present value (NPV) of the field development plan (FDP). As well operation is a time-series scenario, this problem contains numerous parameters to be optimized and countless solutions. This results in huge optimization time to evaluate each scenario using the reservoir simulator, especially with robust optimization. In this study, particle swarm optimization is coupled with the deep learning-based proxy model to solve such problems in the 2D synthetic and 3D Egg cases. First, the long short-term memory (LSTM) proxy model is developed to estimate the reservoir response to the well operation scenario instead of reservoir simulation. When the drilling and bottomhole pressure (BHP) schedules are entered into the input layer for the proxy model, the average cumulative field oil and water productions and field water injection from the multiple reservoir models are obtained in the output layer. In case of well pattern, the optimized scenario of the location and type of wells in Kim et al. (2021a) was fixed in this study. After the LSTM proxy model fits with the training data pair of time-series BHP schedule and corresponding the responses obtained by ECLIPSE (ECL), it can predict the time-series field response for given BHP scenario. When the calculated NPV from the LSTM is compared with the true NPV from ECL, the coefficient of determination for the validation and test datasets is higher than 0.97, solving the overfitting problem of the simple neural network (NN) proxy model. It is critical to select a proper deep learning algorithm according to the characteristics of the input and output data. While the convolutional NN (CNN) is proper to make a proxy model for well pattern scenario, which consists of the static images with the same dimension in Kim et al. (2021a), the LSTM is suitable for well operation scenario, which changes over time. Second, the drilling and BHP schedules are optimized under the constraint of the maximum available rig. Also, to reduce these high-dimensional optimization variables, we define the BHP schedule as a cosine function instead of the stepwise approach. It reduces the number of training data required for the proxy model. Third, optimization strategies are reviewed for both the well pattern and well operation. The sequential proxy, CNN-LSTM, shows similar NPVs with the results of the sequential ECL-ECL. However, CNN-LSTM requires only 12% of optimization time compared to ECL-ECL for the 3D case. Therefore, CNN-LSTM is proposed as the reasonable solution for reliable decision-making for the FDP in a short time. [Display omitted] • Long short-term memory (LSTM) is applied to predict reservoir performances based on bottomhole pressure (BHP) schedule. • LSTM proxy shows an R2 value higher than 0.97 and mitigates the overfitting problem in multi-layer perceptron proxy model. • Particle swarm optimization with LSTM proxy (PSO-LSTM) optimizes drilling and BHP schedules under the maximum rig constraint. • PSO-LSTM requires only 23% of optimization time compared to PSO-ECLIPSE (ECL) and achieves a similar NPV for the 3D model. • Convolutional neural network-LSTM proxy reduces optimization time dramatically, 88%, compared to conventional ECL-ECL case. [ABSTRACT FROM AUTHOR]

This paper aimed to review the research on emulsion formation, stability, chemical demulsification, and hydrophilic–lipophilic balance in chemical studies and other aspects related to emulsion thermodynamics. The global increase in energy demand pressures oil and gas producers to develop and explore a new source of energy. Crude oil is one of the indispensable sources produced from unconventional and conventional resources. It is accompanied by high water content during production activities, and this water is complex and has a high content of contaminants. This water is also produced in the form of foam or emulsion. Water-in-oil emulsion is considered as a common type in petroleum industry. Oil emulsion is very harmful due to the associated difficulties during the refining and transportation of crude oil and the limitation in the produced water discharge. The emulsion in petroleum industry is stable due to the natural surface-active compounds in crude oil. Thus, oilfield researchers need to study different utilization methods to demulsify emulsion. Chemical method is considered as an essential method in treating petroleum emulsion by using demulsifiers, such as non-ionic surfactant. • Water production in the petroleum industry and its source and toxicity. • Water-in-oil emulsion formation and characterization. • Deposition and solubility of asphaltene-stabilized emulsions. • Chemical demulsification based on nonionic surfactant. [ABSTRACT FROM AUTHOR]

Using fixed boundary conditions has always been the way wells are modelled in reservoir simulators for prediction runs. This commonly results in oil wells being shut-in due to increasing production of water or gas or triggering a workover option shutting-in a section of the wells perforated interval. These actions are late reactive actions instead of being proactive actions that can help prolong a wells life. In actual field operations, well flow rates and bottomhole pressures are often adjusted to better suit reservoir management strategies and control water and gas production. This paper introduces a novel yet simple implementation of adaptive well conditions that updates well boundary conditions based on wellbore or near-wellbore performance. This methodology can be executed using a commercial simulator alongside a small instructing application, or internally integrated as done here with an inhouse reservoir simulator built to present this work as proof of concept. Three case studies are presented in this paper with increasing complexity. We show that an improvement in the amount of recovered oil, an increase in the lifetime of assets, and a reduction of produced water and gas are all possible with adaptive well controls. In one of the three cases, adaptive well controls resulted in an oil recovery increase as high as 20%. We also discuss the differences between well-data and reservoir-data dependencies of the adaptive well-condition algorithms in terms of dynamic response and physical application. Implementing adaptive well controls can help in reconsidering business plans by reducing water and gas production and avoiding early abandonment of wells. It was also considered that one of the main advantages of adaptive well conditions is the potentially significant reduction in number of variables for future optimization studies due to the elimination of control steps. [Display omitted] • Well rates are automatically updated to deter water and gas production. • Adaptive well conditions increased oil recovery by 20% in a 3-phase reservoir model. • More control steps do not increase number of variables in optimization studies. • Adaptive well conditions using reservoir data helps unify waterfront advancement. [ABSTRACT FROM AUTHOR]

Scale deposition is one of the serious oilfield chemical issues which may lead to a range of downhole and production problems, including the reduction of well productivity index. Scale Inhibitor (SI) squeeze treatments are one of the most common techniques which are applied to prevent downhole scaling in production wells. A treatment typically consists of four stages, (i) a preflush, to condition the rock surface; (ii) a main treatment, where a batch of high concentration inhibitor is bullheaded into the formation; (iii) an overflush, to displace the scale inhibitor slug deeper into the near-well formation, and (iv) a shut-in stage to allow further inhibitor retention before putting the well back on production. During this backflow period, scale inhibitor is released from the rock surface into the produced water, and the scale deposition is prevented if the inhibitor concentration is above some specified Minimum Inhibitor Concentration (MIC). Due to logistic constraints in offshore wells, it is often required that the scale protection afforded by a squeeze treatment should last for some fixed design lifetime until the next treatment becomes available. For example, in the North Sea sector, well operations are often based on an annual treatment design. This paper presents a methodology to optimize the squeeze treatment design for a fixed target lifetime and this is applied for two offshore well squeeze treatments. This approach allows us to account for the operational constraints in the squeeze optimization process to treat a fixed volume of produced water, while minimizing the inhibitor neat volume and the total pumping time. A sensitivity study was performed on the inhibitor concentration, where the results showed that deploying a smaller inhibitor slug but with higher concentration is more effective than a larger slug with lower concentration, assuming a fixed volume of inhibitor and injected water. Therefore, it is recommended that the inhibitor is deployed at the maximum possible concentration, while avoiding the potential for any formation damage. Considering the same inhibitor slug (volume and concentration), this study suggests that the squeeze lifetime continuously increases with the overflush volume. This implies that the lifetime function is differentiable with respect to the overflush, and thus a gradient-based optimization algorithm, specifically the Gradient Descent (GD) may be applied to find the exact overflush volume resulting in the target lifetime. Employing this procedure for a wide range of main treatment volumes allows us to calculate the squeeze "Iso-Lifetime" curve which represents all the possible squeeze designs for the target lifetime. Thereafter, from the iso-lifetime designs, the CPB value (total cost of squeeze per treated barrel of water produced) can be minimized to find the most optimum squeeze design. This approach is shown to result in the optimum scale inhibitor squeeze treatment strategy in the long-term. • Scale inhibitor squeeze treatment to tackle the scale deposition in the well. • Squeeze design optimization using the Gradient Descent algorithm. • Long-term squeeze strategy optimization for the front end engineering design. • Minimizing the carbon footprint by optimizing the offshore vessels' trips to the wells. [ABSTRACT FROM AUTHOR]

In both offshore deepwater and shale fields, a large amount of produced water will be generated during field operations. One consequence of significant produced water production from the field is mineral scale formation. Barium sulfate (barite) is one of the toughest scales to manage in oilfield. To combat scale issues, scale inhibitor has been widely adopted to inhibit scale deposition. Previous studies have confirmed that sorptive interactions between chemical inhibitor and scale particles play a vital role in scale prevention and control. Although extensive studies have been carried out on inhibitor-scale interaction, a comprehensive understanding of inhibition is yet available and the detailed sorptive interaction between inhibitor and mineral scale is not fully understood. In this study, experimental efforts have been made to explore the governing mechanism of sorptive behavior of a common phosphonate inhibitor onto the surface of barite particles. Adsorption and desorption experiments involving phosphonate and barite were carried out over a wide range of physiochemical conditions in a systematic manner. It shows that both adsorption and desorption of inhibitor to and from barite surfaces proceed rapidly. At a low phosphonate concentration, surface adsorption mechanism accounts for the interaction between phosphonate and barite. The release of phosphonate inhibitor from the barite surface is controlled by the dissolution dynamics of the formed Ca-phosphonate precipitate. This study is the first report of investigation of barite with phosphonate inhibitor with low and ultra-low concentrations as well as the inhibitory mechanism. The obtained results will improve our understanding of the interaction between phosphonate inhibitors and mineral scale. The findings can provide fundamental information that can benefit the inhibition performance and efficiency for barite scale control in oilfield operations. [Display omitted] • Study sorptive interaction of DTPMP scale inhibitor with barium sulfate (barite). • Adsorption and desorption of DTPMP to and from barite surfaces proceed rapidly. • A unified Langmuir model can characterize DTPMP sorption at oilfield condition. • Barite surface fractional coverage can satisfactorily predict the nucleation time. • Release of DTPMP from barite is controlled by dissolution dynamics of Ca-DTPMP. [ABSTRACT FROM AUTHOR]

One of the largest wastewater flows generated in the oil and gas industry is produced water (PW), which can come from oil fields, gas fields or a combination of oil and gas fields. This effluent has a complex and variable chemical composition; it contains a significant amount, sometimes up to 500 mg L−1, of water soluble organic compounds (WSO) that are not easily removed by conventional physical-chemical treatment as coagulation and flotation. With the intensification in worldwide industrial activities, the generation of PW has consequently also increased and, from the environmental point of view, it is of fundamental importance to point out the alternatives for its proper management, in order to comply with legislation around the world and to provide safe subsequent destination (reuse and/or disposal). Furthermore, the treatment of this effluent is challenging and requires a lot of attention from both industry and academy. In this context, adsorption is known as one of the most effective technologies for removing WSO in polishing steps, since it is a technique of simple installation and maintenance, with low cost. Thus, this paper aims to review and highlight in detail (i) the main characteristics of produced water and its different forms of reuse, (ii) the theoretical fundaments of the adsorption technique and (iii) through case studies, critically evaluate the technical feasibility of implementing adsorption towers in PW treatment units. [Display omitted] • Adsorption as treatment technology for produced water (PW) is critically reviewed. • Case studies are presented applying the adsorption technique to treat PW. • Technical viability of an adsorption system for PW treatment is investigated. • Challenges and future perspectives for adsorptive processes are presented. [ABSTRACT FROM AUTHOR]

Abstract: The objective of this study was to develop models that could be used to predict frac flowback and produced water volumes considering the unique decline rates that exist for different types of oil and gas wells. Specifically, water production data from the Colorado Oil and Gas Conservation Commission (COGCC) and Noble Energy Inc. were used to develop models for water production for vertical and horizontal wells, a distinction made largely due to the different amounts of water used for each. If centralized water treatment and handling facilities are going to be designed and constructed, it is important to have a reliable estimate of the water that will be produced in the future as wells are completed and brought on line. An Excel-based tool was developed utilizing the horizontal and vertical well models for predicting total volume of water production by current and future wells in Wattenberg Field. Two case studies have been conducted including one with all of the Noble wells in Wattenberg Field and one with a subset assuming a regional treatment center might be established. Uncertainty of the predictions was determined using standard error calculations on the two modeling parameters for water flow decline rates. An interactive Excel-based spreadsheet has been developed to allow predictions of water production based on the number of horizontal and vertical wells drilled in the future. [Copyright &y& Elsevier]

Abstract: One of the most common methods for preventing scale formation is through the use of scale inhibitor. This study was conducted to investigate the permeability reduction caused by deposition of barium sulfate in Malaysian sandstone and Berea cores from mixing of injected Malaysian seawaters (Angsi and Barton) and formation water that contained high concentration of barium ion at various temperatures (50–95°C) and differential pressures (75–200psig). Scale inhibition efficiency was determined in both the bulk jar and core tests by using scale inhibitors Methylene Phosphonic Acid (DETPMP), Poly-Phosphino Carboxylic Acid (PPCA), and Phosphonate-based scale inhibitor (PBSI) at various temperatures (50–95°C) and concentrations. The results showed that a large extent of permeability damage was caused by barium sulfate that deposited on the rock pore surface. At higher temperatures, the rate of BaSO4 precipitation decreases since the solubility of BaSO4 increases with increasing temperature. At 60°C temperature, PPCA showed very efficient BaSO4 inhibition effect where it reduced most amount of BaSO4 compared to the DETPMP and PBSI inhibitors. [Copyright &y& Elsevier]

Abstract: Sidetrack or recompletion time (tR) is optimized for the pair of a production and injection well simultaneously under uncertainty with respect to expected monetary value (EMV) or risked net present value (NPV) as the objective function to properly understand and shed more light on the critical parameters influencing tR. The option to sidetrack or not is also evaluated. Analysis is aided by a recent time dependent analytical waterflood performance model with respect to cumulative injected water for adequate economic analysis. There exist two zones, a productive and lower zone and a lesser producible upper zone that has low recoverable reserves, of which both zones are penetrated by both wells. The injection well enhances oil production in the production well by the displacement mechanism of waterflooding. Though sidetrack is simultaneous considering negligible time interval between sidetrack of both wells, it is actually a sequential operation with regards to the decision tree schematic. A possible outcome is, if sidetrack to produce from the upper zone fails, then no sidetrack to the upper zone through the injection well. Decision tree analysis is brought to fore considering the probability of success (POS) of continual production (injection) from (to) the producing zone and production (injection) commencement possibility for the upper zone. Uncertainty of parameters including POS in evaluating the objective function, EMV, is made possible by probable values using distributions for Monte Carlo simulation run. EMV and tR are optimized for each run by constraining tR to either, after water breakthrough time to the lower zone or from time 0. The objective function is solved with a constrained non-linear generalized gradient optimization scheme. Significant match was obtained for waterflood performance, and NPV of each terminal branch of the decision tree between the analytical approach and reservoir simulator generated data. Notably, optimal tR obtained through the analytical approach is highly dependent on POS of production and injection from (to) the upper zone. Evaluation of possible dependencies of POS is essential as regards to the sequential operation brought largely by geological uncertainties and may be to a lesser extent by the sidetrack operation based on the influence of probable pathways. Other criteria for selection of optimal time are more suitable for selection of an optimal range and not a single value. These criteria in essence, boost the EMV and cannot stand alone as an optimization tool. [Copyright &y& Elsevier]

Abstract: Injectivity formation damage with waterflooding using sea/produced water has been widely reported in the North Sea, the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid and/or liquid particles by reservoir rock that consequently leads to the permeability decline. Another reason for the permeability decline is the formation of a low permeable external filter cake. However, moderate injectivity decline is not too damaging for a waterflood project with long horizontal injectors, where the initial injectivity index is high. In this case, the injection of raw or poorly treated water may significantly reduce the cost of water treatment, which is a cumbersome and expensive procedure in offshore projects. In this paper we investigate the effects of injected water quality on waterflooding using horizontal wells. An analytical model for injectivity decline, which accounts for particle capture and a low permeable external filter cake formation, has been implemented into black oil reservoir simulator. It was found that induced injectivity damage results in a noticeable reduction of water cut and in increased (although delayed) sweep efficiency. [Copyright &y& Elsevier]

During offshore production, it is typical to discharge produced water into the sea after treating it to a level that meets environmental regulations. A growth in the volumes of produced water and increasingly stringent requirements have drawn attention to re-injection of produced water as a more viable disposal method. Produced water re-injection is regarded as an environmentally friendly and cost-efficient approach that allows integration of produced water with reservoir management. However, loss of injectivity, due to the plugging of pores by oil droplets and particles present in produced water, limits implementation of re-injection. This review discusses engineering challenges during re-injection and summarizes the knowledge and the gaps in the literature on the permeability reduction due to the flow of dilute oil-in-water emulsions. First, a short introduction into the origins of produced water, its composition, and the treatment techniques employed offshore are provided. An overview of the water injection strategies as well as a discussion of the past field experience of produced water re-injection is given. This is followed by a detailed review of the flow of diluted oil-in-water emulsions through porous media from the permeability reduction perspective. An overview of models for predicting permeability reduction during the flow of emulsions is provided. The physical parameters affecting the droplet retention and physicochemical interactions between droplets and pore walls are discussed. The studies that investigated co-injection of oil droplets and solid particles are included as well. The review identified that the effect of droplet stability, oil viscosity, wettability, and particles on droplet retention is not sufficiently examined. It was found that drop-to-pore size ratio is a crucial factor for droplet retention, but it is often omitted in the industry. An outlook on the gaps and suggestions to address them was provided. Microfluidics was pointed out as a complementary technique to coreflooding. • Mathematical models describing permeability reduction are discussed. • Behavior of droplets and solids co-injected is different from each component alone. • Physical and physicochemical parameters affecting the droplet capture are reviewed. • Experimental techniques utilized in the literature are reviewed. [ABSTRACT FROM AUTHOR]

Produced water (PW) and formation water are complex mixtures of hydrocarbons and water produced at oil and gas upstream facilities. Submicron oil droplets represent a multitude of issues affecting the performance of downstream advanced water treatment processes, such as micro and ultra-filtration processes. Conventional de-oiling technologies do not efficiently remove submicron oil droplets in PW. An accurate characterization of submicron oil droplets and contaminants is required to improve PW treatment technology. In this study, a methodology for visualization and quantification of submicron oil droplets size distribution (DSD), using optical and electron microscopy techniques, was developed. Various microscopy techniques were evaluated, including epifluorescence microscopy (EpiFM), confocal laser scanning microscopy (CLSM), cryogenic scanning and transmission electron microscopy (cryo-SEM and cryo-TEM, respectively). Synthetic PW was used to improve and standardize the sample preparation and characterization methodology. The improved methodology was then tested with two PW samples from different oilfields in the Middle East region. Two methods were developed for the determination of DSD in oilfield PW samples. The first method is suitable for highly polydisperse PW samples with oil droplets larger than 250 nm. This method is based on using low-temperature agarose to immobilize the samples, avoiding coalescence, and allowing clear visualization of the oil droplets at high magnification in EpiFM. The second method is suitable for concentrated PW samples and oil droplets as small as 20 nm in size. This method is based on cryo-TEM with plunge freezing and without the use of agarose for sample immobilization. The agarose-immobilization technique was also applied for sample preparation in cryo-SEM. Cryo-SEM fixation by high-pressure freezing (HPF) preserved the morphology of oil droplets in synthetic oil-concentrated samples and allowed its visualization in a wide range of sizes from 50 nm up to 20 μm. Cryo-TEM imaging of oilfield PW samples revealed the presence of oil droplets as small as 20 nm in size. However, no quantification of the DSD in the oilfield PW samples was possible due to the low oil concentration. Moreover, a relatively large amount of other submicron particulates/aggregates were observed in PW samples. Cryo-SEM coupled with energy-dispersive X-ray spectroscopy (EDS) provided valuable information on the morphology and elemental composition of the submicron-sized contaminants. These submicron contaminants would not be removed by conventional de-oiling technologies and might cause intrapore blocking in membrane filtration systems downstream. The effect of these submicron contaminants, other than oil droplets present in PW, needs to be addressed to improve the PW treatment technologies. [Display omitted] • A new method based on EpiFM of immobilized gelled samples is proposed to determine the DSD. • Oil droplets as small as 20 nm were observed in oilfield PW samples by cryo-TEM. • Cryo-SEM-EDS complements information on the nature of the submicron contaminants in PW. • Submicron contaminants other than oil droplets should be further studied for improved PW treatment. [ABSTRACT FROM AUTHOR]

Microbial generation of H 2 S in-situ due to injection of seawater, so-called reservoir souring, can induce severe negative impact in terms of health, safety, maintenance and economics in mature oil fields. Historical H 2 S data have been collected for decades at the Norwegian Continental Shelf fields. The Gullfaks field in the North Sea has been negatively impacted by severe H 2 S production, whereas another comparable North Sea field, called Field B, only has minor H 2 S challenges. The difference in cumulative H 2 S development in Gullfaks wells are described as Type I, II and III by an empirical classification. Type I wells show rapid increase in the H 2 S concentration produced (< 1 year or < 1 mill. Sm 3 produced water), whereas Type III show a significant delay and slowly rising H 2 S production (> 10 years or > 10 mill. Sm 3 produced water). Type II can be considered as a mixture of Type I and III. To understand the difference between these types, a microbial reservoir souring model called the Extended Growth Zone (EGZ) model has previously been introduced. Differences in H 2 S development described by the three different well types are supported by the consequences of the EGZ model for both fields on field, platform/installation and well level. The results support that the overall drainage water injection strategy implemented is the single-most important cause governing the development of produced H 2 S over the lifespan of a field: •High H 2 S production is expected when cold seawater is injected directly into oil bearing zones (Type I behavior). •Relatively lower H 2 S production is expected when cold seawater is injected in the water zone below oil bearing zones (Type III behavior). The EGZ model describes the development of reservoir souring based on two main hypotheses (1) Degradation of crude oil as carbon source (2) The importance of temperature on the rate of H 2 S generation as summarized: •The expected H 2 S development according to the EGZ model agrees with observed data from Gullfaks both on platform level (GFA > GFC > GFB) and for individual wells. •The observed slow development of H 2 S for Field B observed for platform and well bore level is explained by the presence of Type III wells only. •Type III wells in Gullfaks and Field B behave similarly within the uncertainty range for H 2 S production. • Historical data collected for decades on reservoir souring at NCS fields are analysed. • The controlling factors for microbial reservoir souring are assessed. [ABSTRACT FROM AUTHOR]

Multi-layer co-production is a mainstream method for efficient development of coalbed methane (CBM) and coal series gas under multi-seam conditions. However, interlayer interferences during CBM co-production caused by differences in reservoir properties (especially permeability and pressure) between stacked CBM systems severely restrict the output of CBM from the production layers. The identification of interlayer interferences and optimization of production layer combinations are important scientific issues that need to be explored to achieve high CBM production. Physical simulation is an effective means of accomplishing this research objective. Physical simulations of CBM co-production were performed under designed permeability and pressure combinations based on self-developed experimental equipment, which is mainly composed of an injection subsystem, a vacuum subsystem, the model body subsystem, and a separation and metering subsystem. Coal samples were collected from three CBM basins in China to form a series of five permeability levels, specifically 0.2, 2, 10, 50, and 100 mD. We focused our analysis on the contribution of gas production from each production layer using the gas flow data obtained from the physical simulation experiments. The co-mining compatibility of the production layers is divided into four types based on the grading evaluation of gas contribution: Grade I, II, and III compatible, and incompatible, which represent gas production contribution of the weak seam ≥37.5%, 25%–37.5%, 12.5%–25%, and ≤12.5%, respectively. On this basis, a template for discriminating CBM co-production compatibility is constructed using the permeability ratio and pressure difference as basic parameters. The gas and water production data of representative CBM wells in the Bide-Santang basin were used to verify the reliability of the template, and the compatibility discrimination results show consistency with the production data. The average daily gas production per unit of coal thickness presents a decreasing trend with deteriorating compatibility of co-producing seams. Finally, an integrated technical process for the development of stacked CBM systems is proposed, including the hierarchical optimization of production layer combinations, identification of interlayer interferences and sources of produced water, and selection of suitable development methods and technology. We divided the production layer combinations into four types representing different development potentials based on the hierarchical method: most favorable, favorable, sub-favorable, and unfavorable. Suggestions are made for the key geological constraints (weak water-bearing reservoir, compatibility of CBM systems, shallow groundwater interference, and deep CBM condition) and specific development strategies for different types of production layer combinations. This study will enrich the geological understanding of CBM co-production and provide theoretical and technical support for the efficient development of stacked CBM systems. • Physical simulation experiments of CBM co-production were performed using self-developed equipment. • A template for quantitatively discriminating CBM co-production compatibility is constructed. • An integrated technical process for the development of stacked CBM systems is proposed. • The production layer combinations were divided into four types: most favorable, favorable, sub-favorable, and unfavorable. [ABSTRACT FROM AUTHOR]

Chemical enhanced oil recovery (EOR) methods are alternatives to increase oil production in mature reservoirs. However, the presence of EOR chemicals in the produced water may impact the separation of gas-water systems in oil platforms. The present work aims to evaluate the impact of polymers, surfactants, inorganic salts, and their interactions on gas holdup in a 32.1-cm-diameter semi-batch bubble column over a range of superficial gas velocities ranging from 0 to 19 cm/s. It has been confirmed through physical-chemical analysis that synthetic produced water containing salts, polymers and organic surfactants is non-Newtonian with low surface tension. Results have shown that both salt and surfactants increase gas holdup regardless of superficial gas velocity, while the effect of polymers depends on superficial gas velocity. This work also innovates by showing how interactions between EOR chemicals and salinity affect transition gas holdup and superficial gas velocity between different flow regimes. Overall results shed some light on how the chemical composition of EOR effluents affect gas holdup and flow regime as a function of a wide range of superficial gas velocities and therefore contributes to the development of gas-liquid systems. • This work shows how EOR chemicals affect the gas holdup and flow regime in a bubble column. • The effect of polymer on the gas holdup depends on the superficial gas velocity. • The presence of polymer shortens the homogeneous flow regime and anticipates the transition. • Both salt and surfactant increase gas holdup and postpone the transition flow regime. • At high superficial gas velocities, all combinations of EOR chemicals increase gas holdup. [ABSTRACT FROM AUTHOR]

Recent experiments on sandstone rocks found more fines migration at higher temperature. They attributed this to temperature-dependent zeta potential. However, temperature also affects mineral reactions. The present study investigates the effect of temperature on both fines migration and mineral reactions. Two sets of single-phase injection experiments are performed using Berea sandstone sister plugs. In one set of experiments, solutions of NaCl brine are injected at a constant temperature of 25 °C, 50 °C, or 70 °C. In the other set, solutions of CaCl 2 brine are injected at a constant temperature of 25 °C or 50 °C. All plugs are subjected to five sequential injections of the designated brine at salinities 0.684 mol/L, 0.171 mol/L, 0.043 mol/L, 0.0085 mol/L, and 0 mol/L. Permeability at each injection stage is calculated from pressure difference across the core. When NaCl brine is used, the percentage of permeability decrease is found to be 99% at 25 °C, 90% at 50 °C, and 40% at 70 °C. The lower permeability decrease at high temperature is found to be accompanied by a smaller concentration of produced fines. Comparison of scanning electron microscope images taken before and at the end of each experiment shows pore enlargement due to mineral reaction at high temperature, which further explains the lower permeability decrease. Ionic concentrations of Ca2+ and Mg2+ in the produced water are found to be greater at higher temperature, due to higher reaction rate. With CaCl 2 brine, a 7% permeability decrease is observed at 25 °C, whereas a 20% permeability increase is observed at 50 °C. The observed fines concentration and increase in Ca2+ ion production are found to be lower than with NaCl brine, which is attributed to ion exchange between Na+ and Ca2+ with NaCl brine. Temperature affects both (1) permeability increase due to pore enlargement caused by mineral reactions, and (2) permeability decrease due to fines migration. • CaCl 2 and NaCl brines of varying concentrations are injected into Berea sandstones at different temperatures. • Permeability decrease due to fines migration and permeability increase due to mineral reactions are observed. • Both of the mechanisms are affected by temperature and the type of salt of the injected brine. • To capture the mechanisms, experiment should be performed using real rock and fluid systems at formation temperature. [ABSTRACT FROM AUTHOR]

Oilfield produced water treatment represent a global challenge due to the presence of several contaminants such as heavy metals and dissolved organic compounds. They cannot be removed by conventional equipment and may threat the environment when discarded. Hence, oil industry has the challenge of manage the produced water according to the disposal standards set by environmental agencies and, at the same time, overcome weight and space limitations in the platforms. Choosing the best technology involves the understanding of the process, construction and operational cost, along with the maintenance and management of the removed pollutants. In addition, different oilfield produced water composition and volume also lead to different options for its management. In this context, the study of technological routes such as liquid-liquid extraction is of great interest to the petroleum industry due to the variety of solvents and the different approaches available to accomplish the produced water treatment decontamination. Despite the extensive liquid-liquid extraction application for analysis and remediation of complex mixtures, there is no literature review on this topic. Thus, this paper presents a review of soluble organic compounds removal from oilfield produced water by the liquid-liquid extraction process. The novelty of each extraction method was highlighted and possible applications in the oil industry were identified. • Review of solvent extraction methodologies used for produced water treatment. • The liquid-liquid extraction as a feasible route to remove organic compounds. • Innovation in industrial liquid-liquid extraction equipment are presented. [ABSTRACT FROM AUTHOR]

Polymeric additives are widely used in the oil and gas industry to increase the viscosity of the water injected into the reservoirs for enhancing oil recovery. This technique, also known as polymer flooding (PF), promotes the cogeneration of polymeric residues in the produced water stream. These residues cause an important efficiency reduction on the removal of oil and greases, by commonly used systems installed on offshore oil production platforms. Since ultrafiltration ceramic membranes have been considered as an improvement for designing more efficient treatment processes for new offshore installation units, the authors decided to conduct this work. The study aimed to assess the impact promoted by the presence of a polymer frequently used for PF on the performance of produced water treatment by an ultrafiltration ceramic membrane. For all the experimental conditions, it was observed that the selected membrane, with an average 0.1 μm pore size of, was able to generate a permeate stream with oil and greases concentration (C O) less than 5 mg/L. However, the polymer caused a significant impact on the membrane permeation flux, even when present in the saline samples at the concentration of 0.1 g/L. Under this condition, a reduction of 84% from the initial permeation flux (430 L/h.m2) was observed after 40 min of operation. Increasing the polymer concentration to 1.0 g/L resulted in an additional cutback of 9% from this value. When this sheared sample was prepared without salt, the permeation flux decrease was less intense, but still very significant. In this case, the final flux was 70 L/h.m2, representing a reduction of 83% from the initial value. Image 1 • Polymers severely impact the permeation efficiency. • Salts decrease polymer hydraulic volume and, therefore, the permeation efficiency. • Minor impacts on the process efficiency are related to the presence of oil. • The membrane selected can partially retain polymers. • Oil and greases were efficiently removed from the water samples. [ABSTRACT FROM AUTHOR]

The use of colloidal silica in high temperature and low-permeability zones of oil fields for controlling excessive water production is a well-known technique. However, the misplacement of the conventional conformance control systems may lead to loss of valuable oil reserves. The Pickering emulsification of silane-modified colloidal silica is a promising solution to this problem. This research demonstrates the use of organophilic micronized phyllosilicate (Cloisite 20) to form an emulsion with silane-modified colloidal silica in a diesel oil phase (invert emulsion) for the first time. The effect of high shear stirring on Cloisite 20 particles and their characteristics were studied to assess their suitability as Pickering stabilizers. Their size, interfacial tension, contact angle, and zeta potential were measured. The developed Pickering-emulsified colloidal silica was characterized using a dilution test, conventional bottle test, vial inversion test, optical and confocal microscopy, and focused-ion-beam scanning electron microscopy. This work provides new insights into the formation and separation of a silane-modified colloidal silica Pickering emulsion. The Cloisite 20 particles were found to be very effective Pickering emulsifier, and the developed emulsion system may have applications for conformance control in high-temperature oil fields with excess water production. Image 1 • The emulsified silane modified colloidal silica system was developed for conformance control. • The developed conformance control system is pickering emulsion stabilized by Cloisite 20. • The developed emulsion system was characterized using dilution test, conventional bottle test, vial inversion test, optical and confocal microscopy and FIB-SEM. • The effect of high shear stirring on Cloisite 20 was studied. • The developed Pickering emulsion was studied for conformance control application. [ABSTRACT FROM AUTHOR]

In the oil extraction process, drilling fluids can create a thin layer on the walls of the oil well known as filter cake. Its removal is essential for proper cementation between the coating and the rock formation. In this work, microemulsion systems based on produced water were formulated containing nonionic surfactants of different degrees of ethoxylation for cleaning the plaster of olefin-based drilling fluid. An experimental planning of Scheffé net was carried out showing the total efficiency of removing filter cake (100%) in 80.5s. Studies on thermogravimetry, wettability, cement compatibility and compressibility analysis have shown that the systems are suitable for the conditions required in oil wells. • This work used microemulsion systems containing water produced to clean wells. • O/W microemulsions with surfactants of different degrees of ethoxylation were used. • Microemulsion systems were able to remove 100% of non-aqueous filter cake. • The reuse of produced water in microemulsions promotes sustainable technology. [ABSTRACT FROM AUTHOR]

Organic geochemical methods were performed on four oil seep samples collected from the Abu-Jir Fault Zone (AJFZ) in the Al-Anbar Governorate, western Iraq. These oil seeps have undergone biodegradation, showing large unresolved complex mixture (UCM) shapes, with degradation of normal alkanes and isoprenoids. The inorganic elements of the Abu-Jir oil seeps, i.e., S, Ni and V, suggest a marine carbonate-rich source rock deposited under reducing environment conditions. The biomarker ratios and parameters of hopane and sterane further suggest that the oil seeps were derived from source rock rich in lipids from phytoplankton and bacteria with less contribution of terrigenous organic debris. The chemical maturity indicators show that the Abu-Jir oil seeps were generated from early mature sulfur -rich source rock, thus in association with a high S content of more than 1.93%. The geochemical characteristics of the analyzed oil seep samples are similar, which is consistent with most of the crude oils in the northern and southern basins in Iraq, and were generated from the Middle Jurassic Sargelu Formation. The overall geochemical correlations and geological information confirm that the Abu-Jir Faultoil seeps in the western Iraq were sourced from the Middle Jurassic Sargelu Formation that reached an early maturity level of oil-generation window and that they migrated into the ground surface through the Abu-Jir major fault during the middle Miocene. • The Abu-Jir oil seeps are generally heavy and degraded oils. • The oil seeps were sourced from the middle Jurassic marine carbonate-rich source rock. • Genetic relationship is found between oil seeps and the Middle Jurassic Sargelu Formation. • The Abu-Jir oil seeps were migrated upto the ground surface through the Abo Jir major faults. [ABSTRACT FROM AUTHOR]

In naturally fractured unconventional reservoirs, naturally present fractures will interact with hydraulic fractures, and divert fracture propagation. Because of complex fracture growth, the ultimate goal of hydraulic fracturing operation in naturally fractured unconventional reservoirs should be changed from achieving the desired fracture geometry to maximizing the total fracture surface area (TFSA) for given fracturing resources, as it will allow more drainage area available for oil recovery. Unfortunately, there are no such techniques available to develop pumping schedules to maximize TFSA for given fracturing resources in naturally fractured unconventional reservoirs. Motivated by this, in this work, we will develop a new model-based pumping schedule by utilizing a recently developed unconventional complex fracture propagation model called Mangrove as our virtual experiment describing complex fracture networks by accounting for the interaction between hydraulic fractures and natural fractures. Initially, using the simulation data from Mangrove, a reduced-order model (ROM) is constructed, which is then used to develop a Kalman filter utilizing the available measurement to estimate the unmeasurable ROM states. Then, we propose a model-based feedback control system to determine the fracturing fluid pumping schedule that maximizes TFSA, which will lead to an enhanced oil production rate from naturally fractured unconventional reservoirs. We demonstrate that by using the proposed control scheme, TFSA can be greatly enhanced which will lead to an oil production rate greater than those of existing pumping schedules which were developed without considering natural fractures. • The interaction of natural fractures and hydraulic fractures is modeled through Mangrove. • A sensitivity study is performed to show that the oil production depends on total fracture surface area (TFSA). • A controller is designed to compute a pumping schedule that maximizes TFSA. • The performance of the proposed pumping schedule is compared with existing pumping schedules. [ABSTRACT FROM AUTHOR]

Understanding the relationship between produced gas and flowback/produced water is important for both shale gas well operation optimization and well performance enhancement; however, it is not fully understood due to complex flow mechanisms and interactions/feedback among various geoscience and engineering controls. Data-driven analysis, as an alternative way, could inversely provide valuable insights on the relationship between produced gas and water, to adjust future development plans for well/regional optimal economic production. An auto-updated nonlinear data analytics method was applied to evaluate the relationship between water and gas in different spatial and temporal domains, to inversely correlate the micro-scale flow mechanisms from macro-scale data. In this study, the cases were covered with both wet and dry shale gas regions, as well as short and long shale gas production periods. Fracture-fluid flowback is defined as water production within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water is 1–3 years cumulative water production. 114 wells from the Marcellus Formation, in wet and dry gas regions of northwestern West Virginia, were selected to investigate the relationship between fracture-fluid flowback and corresponding one-month gas production. 67 Marcellus wells in Pennsylvania were selected to study the relationship between produced water and corresponding gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. The discussion of water flow format was done by comparing the water gas ratio at reservoir conditions and at the surface condition. WGR (water gas ratio) is high (>9 bbl/mmcf) during the 1st-year and then leveled off at 3 bbl/mmcf after the 1st-year, indicating water initially be produced through displacement, and then be produced through evaporation. • Mathematic models using nonparametric estimation methods were developed to identify the relationships between gas and water in different spatial and temporal domains. The well data was partitioned into different subgroups based on the hydrocarbon composition and water-gas ratio decline trend. • The relationships between first-month gas and fracture-fluid in wet and dry gas region show opposite trends. Water was drawn into both inorganic and organic pores around fracture network area, which may result in gas expulsion from organic pores into effective flow path to the wellbore, or cause 'micro-water block' effect on gas flow. • The relationship between gas and water in 1st-year production is negative, and then shifts to a positive relationship in the 2nd-and 3rd-year. In the 1st-year, the average WGR is larger than Yw, which may indicate water is primarily carried out by immiscible displacement in the liquid phase. However, in the 2nd-and 3rd-year, the average WGR is smaller than Yw, which may indicate water is predominantly carried out by evaporation in the vapor phase. [ABSTRACT FROM AUTHOR]

Potential field methods are capable to provide satisfactory results on the tectonics and geology, especially when dealing with the hydrocarbon reservoirs and ore-bearing mineralization. In this study, magnetic and gravity survey were conducted at the west of Kifl area in central Iraq to image the subsurface geological structure and consequently the characteristics of the oil and gas reservoirs. Ground measurements were conducted on an area of 16 by 24 km with a regular grid spacing of 250 m. The results clarified the tectonic setting of the study area, where the fault system in the Kifl oil field was recognized by resembling both magnetic and gravity anomalies with distinct trends along NS and NW. A 3D inversion algorithm based on a weighted minimum length solution was used for reconstruction of the subsurface physical properties of magnetic susceptibility and density contrast. Weighting matrix is composed of multiplication of compactness and depth weighting functions, and truncated singular value decomposition (TSVD) was used for regularization. 3D inversion was first applied to a synthetic model to simulate the geological reality of the study area, while satisfactory results were obtained. Implementing the algorithm on the real potential field data, the physical properties of the hydrocarbon reservoir were determined. Four cross sections have been extracted from the inversion result to show geometric characteristics (depth and shape) of the main reservoir in the Kefl oil field. The results indicated the presence of a fault system in the middle area within a column of sedimentary sequences represented as a graben-horst structure. This phenomenon in the area could be attributed to the tectonic deformation and tension over the area and the Eurasian and Arabian plates collided back to the Permian - Paleocene periods. Image 1 • Magnetic and gravity investigations at the west of the Kifl oil field in central Iraq. • Characterizing of the oil and gas reservoirs. • A 3D inversion of potential field data based on a weighted minimum length solution. • Weighting matrix is composed of compactness, depth weighting and truncated singular value decomposition (TSVD). • Simulation of a synthetic geological model. [ABSTRACT FROM AUTHOR]

Removal of solids is a critical step in the treatment of produced water generated by offshore hydrocarbon exploration. Present work evaluates a new design of a settling tank that can be used for continuous separation of fine particles from produced water. The novelty of the design lies in its ability generate swirling flow that promotes the settling of fine particles. The tank was investigated by conducting CFD simulations and experiments. The CFD model was initially validated using the experimental data measured in a lab-scale replica of the tank by using particle image velocimetry (PIV) technique. The validated model was then used to investigate flow patterns and settling behavior of different sized particles at varying operating flow rates and with different inlet-outlet configurations. Simulations revealed that the angled entry of water in to the bulk of the tank caused rotational flow that transported the suspended particles towards wall, where downward axial velocity resulted in the settling of particles. The flow patterns showed inward flow at the bottom, which caused the accumulation of settled particles near the center hatch. The flow patterns also indicated an upward flow and the lifting of the settled particles near the hatch at the bottom. The impact of the lifting of particles was mitigated by adjusting the size of inlet openings and operating flowrate. For inlet openings of 40 × 20 cm2, simulations predicted capture of more than 80% of particles having a size range of 30–1000 μm at 30000 barrels per day operating flow rate. The settling tank has no moving element, rotating part or filtering medium; and its settling ability is solely governed by the induced hydrodynamics. Due to its simplicity and high efficiency, the settling tank could be used in continuous operation with high operating flowrate, and for both onshore and offshore operations. Image 1 • A new settling tank for removal of fine solids from produced water was developed. • Design of the settling tank was evaluated by CFD simulations and PIV experiments. • Effect of inlet/outlet configuration, particle size distribution, and operating flow rate was investigated. • The tank could capture >80% of 30–1000 μm particles at flow rate of 30000 bpd. [ABSTRACT FROM AUTHOR]