The rapidly increasing implementations of oilfield technologies such as horizontal wells and multistage hydraulic fracturing, particularly in unconventional formations, have expanded the need for fresh water in many oilfield locations. In the meantime, it is costly for services companies and operators to properly dispose large volumes of produced water, generated annually at about 21 billion barrels in the United States alone. The high operating costs in obtaining fresh water and dealing with produced water have motivated scientists and engineers, especially in recent years, to use produced water in place of fresh water to formulate well treatment fluids. The objective of this brief review is to provide a summary of the up-to-date technologies of reusing oilfield produced water in preparations of a series of crosslinked fluids implemented mainly in hydraulic fracturing operations. The crosslinked fluids formulated with produced water include borate-and metal-crosslinked guar and derivatized guar fluids, as well as other types of crosslinked fluid systems such as crosslinked synthetic polymer fluids and crosslinked derivatized cellulose fluids. The borate-crosslinked guar fluids have been successfully formulated with produced water and used in oilfield operations with bottomhole temperatures up to about 250 °F. The produced water sources involved showed total dissolved solids (TDS) up to about 115,000 mg/L and hardness up to about 11,000 mg/L. The metal-crosslinked guar fluids prepared with produced water were successfully used in wells at bottomhole temperatures up to about 250 °F, with produced water TDS up to about 300,000 mg/L and hardness up to about 44,000 mg/L. The Zr-crosslinked carboxymethyl hydroxypropyl guar (CMHPG) fluids have been successfully made with produced water and implemented in operations with bottomhole temperatures at about 250+ °F, with produced water TDS up to about 280,000 mg/L and hardness up to about 91,000 mg/L. In most of the cases investigated, the produced water involved was either untreated, or the treatments were minimum such as simple filtration without significantly changing the concentrations of monovalent and divalent ions in the water. Due to the compositional similarity (high salinity and hardness) between produced water and seawater, crosslinked fluids formulated with seawater for offshore and onshore jobs were also included. The crosslinked guar and derivatized guar fluids have been successfully formulated with seawater for operations at bottomhole temperatures up to about 300 °F. Operating costs have been significantly reduced when produced water or seawater is used to formulate fracturing fluids in place of fresh water. With various challenges and limitations still existing, the paper emphasizes the needs for new developments and further expansion of produced water reuse in oilfield operations.

Nanotechnology has attracted a great attention in enhancing oil recovery (EOR) due to the cost-effective and environmental friendly manner. The size of nanoparticles for EOR usually is in a range of 1-100 nm, which may slightly differ from various international organisations. Nanoparticles exhibit significantly different properties compared to the same fine or bulk molecules because of much higher concentration of atoms at their surface as a result of ultra-small size. In particular, one of the most useful and fascinating properties of these particles is to creating a massive diffusion driving force due to the large surface area, especially at high temperatures. Previous studies have shown that nanoparticles can enhance oil recovery by shifting reservoir wettability towards more water-wet and reducing interfacial tension, yet this area is still open for discussion. It is worth noting that the potential of nanoparticles to reduce the oil viscosity, increase the mobility ratio, and to alter the reservoir permeability has not been investigated to date. Depending on the operational conditions of the EOR process, some nanoparticles perform more effectively than others, thus leading to different levels of enhanced recovery. In this study, we aim to provide a summary on each of the popular and available nanoparticles in the market and list their optimum operational conditions. We classified nanoparticles into the three categories of metal oxide, organic and inorganic particles in this article.

Although commercial gas flow was produced in several wells with recent years' exploration of Longfengshan area in Changling fault sag, the formation mechanism and controlling factors for high-quality reservoirs still remained undefined. Here, the Yingcheng tight gas reservoirs of Longfengshan area are used as an example to characterize high-quality reservoir formation mechanism and distribution rules. Based on the thin section, SEM, X-ray diffraction, computed tomography (CT) scanning, burial history, constant-rate mercury penetration and physical properties testing, formation mechanism and controlling factors for high-quality reservoirs were analyzed. Results show the following characteristics. First, the reservoir is dominated by chlorite and laumontite cements, and compaction is the most important factor to control reservoir physical properties. According to this, the reservoir can be divided into compacted tight sandstones, chlorite-cemented sandstones and laumontite-cemented sandstones. Second, the high-quality reservoirs are formed due to early extensive laumontite precipitation and the later dissolution of laumontite by organic acid. Meanwhile, it is found that the distribution of cementation and dissolution exhibits some regulations in sedimentary facies, and the distribution is mainly effected and controlled by the lake water and charging of fresh water. Besides, the distribution model of various types of sandstones was established. Studies over diagenesis and sedimentary facies reveal that the high-quality laumontite-cemented sandstones exist in the outside subaqueous fan-delta of the deep sag in Longfengshan area. These findings have been validated by recent exploration wells which obtained high industrial gas flow.

In this paper, a new robust approach based on Least Square support Vector Machine (LSSVM) as a proxy model is used for an automatic fractured reservoir history matching. The proxy model is made to model the history match objective function (mismatch values) based on the history data of the field. This model is then used to minimize the objective function through Particle Swarm Optimization (PSO) and Imperialist Competitive Algorithm (ICA). In automatic history matching, sensitive analysis is often performed on full simulation model. In this work, to get new range of the uncertain parameters (matching parameters) in which the objective function has a minimum value, sensitivity analysis is also performed on the proxy model. By applying the modified ranges to the optimization methods, optimization of the objective function will be faster and outputs of the optimization methods(matching parameters) are produced in less time and with high precision. This procedure leads to matching of history of the field in which a set of reservoir parameters is used. The final sets of parameters are then applied for the full simulation model to validate the technique. The obtained results show that the present procedure in this work is effective for history matching process due to its robust dependability and fast convergence speed. Due to high speed and need for small data sets, LSSVM is the best tool to build a proxy model. Also the comparison of PSO and ICA shows that PSO is less time-consuming and more effective.

Fluidized catalytic cracking slurry oil-in-water emulsion (FCCSE) was prepared by using interfacial complexes generation method that was simple and versatile. The critical factors influencing the sample preparation process were optimized, for instance, the optimum value of the mixed hydrophile-lipophile balance of compound emulsifier was 11.36, the content of compound emulsifier was 4 wt%, the emulsification temperature was 75 °C, the agitation speed was 200 rpm, and the emulsification time was 30-45 min. The performance as a drilling fluid additive was also investigated with respect to rheological properties, filtration loss and inhibition of FCCSE. Experimental results showed that FCCSE was favorable to inhibiting clay expansion and dispersion and reducing fluid loss. Furthermore, it had good compatibility with other additives and did not affect the rheological properties of drilling fluids. FCCSE exhibited better performance than the available emulsified asphalt. It has a promising application as anti-collapse agent in petroleum and natural gas drilling.

Asphaltene precipitation can cause serious problems in petroleum industry while diagnosing the asphaltene stability conditions in crude oil system is still a challenge and has been subject of many investigations. To monitor and diagnose asphaltene stability, high performance intelligent approaches based bio-inspired science like artificial neural network which have been optimized by various optimization techniques have been carried out. The main purpose of the implemented optimization algorithms is to decide high accurate interconnected weights of proposed neural network model. The proposed intelligent approaches are examined by using extensive experimental data reported in open literature. Moreover, to highlight robustness and precision of the addressed approaches, two different regression models have been developed and results obtained from the aforementioned intelligent models and regression approaches are compared with the corresponding refractive index data measured in laboratory. Based on the results, hybrid of genetic algorithm and particle swarm optimization have high performance and average relative absolute deviation between the model outputs and the relevant experimental data was found to be less than 0.2%. Routs from this work indicate that implication of HGAPSO-ANN in monitoring refractive index can lead to more reliable estimation of addressed issue which can lead to design of more reliable phase behavior simulation and further plans of oil production.

Water injection can compensate for pressure depletion of production. This paper firstly investigated into the equilibrium issue among water influx, water injection and production. Equilibrium principle was elaborated through deduction of equilibrium equation and presentation of equilibrium curves with an “equilibrium point”. Influences of artificial controllable factors (e.g. well ratio of injection to production and total well number) on equilibrium were particularly analyzed using field data. It was found that the influences were mainly reflected as the location move of equilibrium point with factor change. Then reservoir pressure maintenance level was especially introduced to reveal the variation law of liquid rate and oil rate with the rising of water cut. It was also found that, even if reservoir pressure kept constant, oil rate still inevitably declined. However, in the field, a stabilized oil rate was always pursued for development efficiency. Therefore, the equilibrium issue of stabilized oil production was studied deeply through probing into some effective measures to realize oil rate stability after the increase of water cut for the example reservoir. Successful example application indicated that the integrated approach was very practical and feasible, and hence could be used to the other similar reservoir.

The deposition of asphaltenes on the inner wall of oil wells and pipelines causes flow blockage and significant production loss in these conduits. The major underlying mechanism(s) for the deposition of asphaltene particles from the oil stream are still under investigation as an active research topic in the literature. In this work, a new deposition model considering both diffusional and inertial transport of asphaltene toward the tubing surface was developed. Model predictions were compared and verified with two sound experimental data available in the literature to evaluate the model's performance. A parametric study was done using the validated model in order to investigate the effect of the asphaltene particle size, flow velocity and oil viscosity on the magnitude of asphaltene deposition rate. Results of the study revealed that increasing the oil velocity causes more drag force on wall's inner surface; consequently, particles tend to transport away from the surface and the rate of asphaltene deposition is decreased. In addition, the developed model predicts that at low fluid velocity (~0.7 m/s), the less viscous oil is more prone to asphaltene deposition problem.

Acrylamide copolymers are often used as acidizing diverting and thickening agents for their advantageous thickening, flocculation, adhesion and resistance reduction properties. Experimental results indicate that the acid concentration greatly affects the properties of acrylamide polymers, which varies from results reported by other researchers. Considering the theoretical and field application value of the present study, four comparable acrylamide-based polymers were synthesized, and their macro-and micro-changes as well as the related changes in viscosity and molecular weight were studied in high-concentration hydrochloric acid. A proposed mechanism of acrylamide copolymer stability and degradation is provided, and further suggestions are made for the modification of acrylamide copolymers.

One of the most common methods for calculating the production oil rate in a gas lift well is nodal analysis. This manner is an accurate one, but unfortunately it is very time consuming and slow. In some modern studies in petroleum engineering such as close loop control of the wells this slowness makes it impossible to have an online optimization. In fact, before the end of the optimization the input parameters have changed. Thus having a faster model is necessary specially in some of the new studies. One of the sources of slowness of the nodal analysis is the temperature profile estimation of the wells. There are two general approaches for temperature profile estimation, some like heat balance are accurate but slow. Others, similar to linear profile assumption are fast but inaccurate and usually are not used commonly. Here, as a new approach, a combination model of heat balance and linear temperature profile estimation has represented which makes the nodal analysis three times faster and it is as accurate as heat balance calculations. To create this, two points (gas injection point and end of tubing) are selected, then using heat balance equations the temperature of those two points are calculated. In normal nodal analysis the temperature of each wanted point in the well is estimated by heat balance and it is the source of slowness but here just two points are calculated using those complex equations. It seems that between these points assuming a linear temperature profile is reasonable because the parameters of the well and production such as physical tubing, and casing shape and properties and gas oil ratio are constants. But of course, it still has some deviation from the complete method of heat balance which using regression and assigning a coefficient to the model even this much of the deviation could be overcame. Finally, the model was tested in various wells and it was compared with the normal nodal analysis with complete heat balance models. Results showed that the new model is as accurate as normal heat balance but three times faster.

Due to the high viscosity of heavy crude oils, production from these reservoirs is a demanding task. To tackle this problem, reducing oil viscosity is a promising approach. There are various methods to reduce viscosity of heavy oil: heating, diluting, emulsification, and core annular flow. In this study, dilution approach was employed, using industrial solvents and gas condensate. The viscosity of two Iranian heavy crude oils was measured by mixing with solvents at different temperatures. Dilution of both oil samples with toluene and heptane, resulted in viscosity reduction. However, their effect became less significant at higher concentrations of diluent. Because of forming hydrogen bonds, adding methanol to heavy crude oil resulted in higher viscosity. By adding condensate, viscosity of each sample reduced. Gas condensate had a greater impact on heavier oil; however, at higher temperatures its effect was reduced. Diluting with naphtha decreased heavy oil viscosity in the same way as n-heptane and toluene. Besides experimental investigation, different viscosity models were evaluated for prediction of heavy oil/solvent viscosity. It was recognized that Lederer' model is the best one.

Accurately predicting the solubility of elemental sulfur in sour gas mixtures is a primary task. As a current and widely-used model on the solubility of elemental sulfur in sour gas mixtures, Chrastil's association model has a big error in the process of predicting experimental data based on different fitting methods. This paper combined with experimental data reported by relevant scholars about elemental sulfur solubility in sour gases and selected density, temperature and pressure as three important influential factors. According to different fitting methods, we can calculate the correlation parameters in Chrastil's model. Then different solubility formulas can be used to predict the solubility of elemental sulfur in sour gas mixtures. Through in-depth research and analysis of Chrastil's solubility model from numerical aspects, it's easy to find the irrationality about Chrastil's solubility model and fitting methods. Especially in fitting methods, further improvement of the fitting method is proposed and used to predict the solubility of elemental sulfur in sour gas mixtures. The calculation results show that some improvements of the predicting precision have been achieved by using the improved fitting method in Chrastil's association model.