Multi-phase separators are crucial components in the petroleum industry as they separate different phases from produced fluids. One key element that influences their performance is the wire mesh demister. Typically, the design of these demisters is based on semi-empirical correlations, which may contain errors. This study involved designing and manufacturing wire mesh demisters using semi-empirical correlations. Subsequently, a gas-liquid flow loop was created in the laboratory, incorporating a horizontal gas-liquid separator. The wire mesh demisters were tested under various operational conditions within the laboratory separator, and the Stokes number in theory and experiment was measured to determine correction factors for use in the correlations. Due to limitations in water and gas flow rates in the laboratory, a CFD model was developed and verified using experimental results. After acquiring 76 simulation data points with the validated CFD model, a neural network was established to predict correction factors for the semi-empirical correlations. A new correlation was proposed for designing wire mesh demisters, with a mean square error value below 1.9%. The novelty of this study lies in introducing a new correlation for designing wire mesh demisters for field applications. [Received: November 19, 2023; Accepted March 3, 2024]

Fractures and tectonic settings cause azimuthal anisotropy in reservoirs. Recognizing the fracture model from the seismic data is a useful tool for identifying the productive zone in reservoirs. We applied azimuthal velocity analysis in seismic processing to improve the image quality and to estimate the anisotropic model parameters. Using azimuthal residual moveout analysis, the direction of azimuthal anisotropy in the reservoir was predicted, and it was found that the results are consistent with fracture orientations obtained from image logs in the reservoirs. Bayes' theorem and a cascaded procedure in least-squares inversion, which matched observed amplitudes to linearized Zoeppritz equations, were used to estimate the elastic moduli as a first step, and the normal and tangential fracture weaknesses were estimated in a second step. Laboratory experiments were carried out on core samples to validate the first-step inversion results. It was found that the propagation wavelets varied in space and reflection time, and so a library of extracted wavelets in the time-frequency domain was used for seismic inversion. Maps of the computed fracture fluid index and estimated fracture weaknesses were used to help to visualize the role of fractures in reservoir productivity, and revealed a consistency with the seismic peak frequency attribute in identifying zones of highly compliant fracture fill. The estimated fracture model demonstrates a good fit with the fractures seen in the available core samples and implies that the fracture fluid index is a useful attribute for determining the productive zones in the reservoir.

Waterflooding is a widely-used secondary oil recovery technique employed in the oil industry. In mature oil fields, waterflooding becomes increasingly essential in order to maximize oil recovery and extend field life, but optimizing its performance remains a complex and challenging task. In recent years, there has been growing interest in developing integrated approaches combining reservoir simulation, well modeling, and data-driven techniques to improve waterflood performance. The Capacitance–Resistance Model (CRM) has been proven to be a fast and effective tool for predicting waterflooding and reservoir characterization. Previous studies have successfully applied CRM to waterflood management to increase oil recovery. This paper develops a novel integrated and iterative workflow for waterflooding optimization in mature fields using the CRM for multilayer reservoirs equipped with Interval Control Valves (ICVs). The proposed approach, which integrates geological and well data with CRM results, was validated using a benchmark field model named the Olympus. This new workflow will help to put connected injection and production wells in different groups to reduce computational costs. In addition, this workflow can be used to determine the optimized number and proper location of the ICVs inside production wells. We determined the workover programs for existing wells, such as installing sensors and ICVs, deepening the wells, or plug-backs. Finally, it can be used for determining optimal water injection rates and well control strategies, such as valve openings in different production layers. As a result, the oil recovery factor increased, and the NPV was maximized, respecting the Olympus field's economic and operational constraints.

The activation of the tectonic setting primarily affects the azimuthal anisotropy, as the poroelastic moduli vary. Seismic imaging to analyze wellbore stability and characterize the reservoirs must take azimuthal anisotropy into account. We investigated the azimuthal anisotropy during seismic processing to show the imaging improvement from isotropy to horizontal transverse isotropy states. We estimated the direction of anisotropy in the reservoir with horizontal transverse isotropy (HTI) moveout analysis and confirmed the results with the direction of active stresses obtained from imaging petrophysical logs and experimental tests. We developed the relationships between strains and stresses in the anisotropy state and combined the results with the failure criterion to express the point for critical pore pressure in breaking onset. We used the experimental analysis to determine the Biot coefficient. We then determined the compliance fractures and the horizontal stresses using the Mohr-Coulomb failure criterion. We evaluated the stresses in isotropic and anisotropic state and analyzed them in reservoir conditions. The study showed that the calculated stresses under anisotropic conditions are 26% higher than under isotropic conditions. This point must be taken into account in the wellbore stability analysis and the reservoir characterization.

Abstract During oil production, the reservoir pressure declines, causing changes in the hydrocarbon components. To ensure better separation of produced phases, separator dimensions should also be adjusted. It is not possible to change the dimensions of the separator during production. Therefore, to improve the separation of the phases, the level of the separator needs to be adjusted. An intelligent system is required to ensure that the liquid level is maintained at the desired level for optimal phase separation during changes in reservoir pressure. In this study, a novel correlation is presented to measure the desired liquid level using new separator pressures. For this purpose, an intelligent system was built in the laboratory and tested in different operational conditions. The intelligent system effectively maintained the desired liquid level of the separator through a new correlation technique. The system accomplished this by acquiring new separator pressure readings collected by installed sensors. This approach helped mitigate the negative effects of the slug flow regime and minimized issues such as foam formation and over-flushing of the separator. It could achieve a 99.1% separation efficiency between gas and liquid phases. This was possible during liquid and gas flow rates ranging from 0 to 2.35 and 8–17 m3/h, respectively. The system could operate under bubble, stratified, plug, and slug flow regimes. Then the intelligent model obtained from lab experiments was integrated into the production model for the southern Iranian oil field. The smart model increased oil production by 13% and prevented the separator from over-flushing in 840 days.

PDC drill bits are an important part of drilling engineering, but improper selection or design can lead to decreased performance and increased costs. Then, accurate modeling of rock-bit interaction for Oil/gas well drilling is critical. Although several mathematical models are presented for this purpose, they have not been able to present a comprehensive model for the rock-bit interaction. In-situ stresses in real drilling conditions affect the force required for rock failure. However, the models proposed so far either have not considered the effects of in-situ stresses or have assumed that the rock failure angle in the downhole conditions is equal to the one calculated in the atmospheric conditions. In this work, after reviewing the background of studies conducted on the rock and bit interaction, with an analytical method, stresses applied to the bottom hole element are examined, including stresses resulting from bit and in-situ stresses. Based on the principle of superposition, the total stress imposed on the bottom hole element is calculated to determine the angle and force of rock cutting. Finally, a novel mathematical model of rock-bit interaction in vertical and deviated oil/gas wells drilling by Considering In-Situ Stresses is presented. Also, the study compares the current model to the Nishimatsu and Xin Ling models using data from a southwest field in Iran. The results show that the simplifying assumption made by previous models leads to a significant underestimation of the failure angle and the amount of force required to the rock failure, with reductions of up to 21% and 48%, respectively, in the case of a vertical well. In an inclined well, the current model predicts cutting force at about 0.14 of that predicted by the previous model.

The calibration of reservoir models using production data can enhance the reliability of predictions. However, history matching often leads to only a few matched models, and the original geological interpretation is not always preserved. Therefore, there is a need for stochastic methodologies for history matching. The Ensemble Kalman Filter (EnKF) is a well-known Monte Carlo method that updates reservoir models in real time. When new production data becomes available, the ensemble of models is updated accordingly. The initial ensemble is created using the prior model, and the posterior probability function is sampled through a series of updates. In this study, EnKF was employed to evaluate the uncertainty of production forecasts for a specific development plan and to match historical data to a real field reservoir model. This study represents the first attempt to combine EnKF with an integrated model that includes a genuine oil reservoir, actual production wells, a surface choke, a surface pipeline, a separator, and a PID pressure controller. The research optimized a real integrated production system, considering the constraint that there should be no slug flow at the inlet of the separator. The objective function was to maximize the net present value (NPV). Geological data was used to model uncertainty using Sequential Gaussian Simulation. Porosity scenarios were generated, and conditioning the porosity to well data yielded improved results. Ensembles were employed to balance accuracy and efficiency, demonstrating a reduction in porosity uncertainty due to production data. This study revealed that utilizing a PID pressure controller for the production separator can enhance oil production by 59% over 20 years, resulting in the generation of 2.97 million barrels of surplus oil in the field and significant economic gains.

Optimisation of the production of an integrated model is the best method to increase production from hydrocarbon reservoirs. Constraint optimisation of an integrated model using a genetic algorithm can optimise and govern production. This paper presents a novel method for optimising integrated production systems. The novel approach is constraint optimisation with a genetic algorithm. The elements of the integrated model are the reservoir, well, choke, pipeline, and separator. One of the essential issues in integrated modelling is evaluating flow regimes before surface equipment. The target function of this study is maximising oil in the stock tank. The constraint for optimisation approaches is that no slug flow regime has formed at the separator inlet. The optimisation integrated model with the genetic algorithm increases the oil in the stock tank by about 16%. [Received: March 6, 2023; Accepted: February 13, 2024]

In the oil industry, multiphase separators are of paramount importance in oil production, as they have a significant impact on overall oil production capacity. However, the occurrence of slug flow, which is characterized by undesirable behavior, can cause extensive damage to the surface separator and pipelines. Consequently, the development of intelligent separators and the implementation of effective flow regime control mechanisms are crucial. To address this issue, our research aimed to investigate the behavior of different flow regimes entering the separator and evaluate the intelligence system of the separator. Initially, we constructed a laboratory-scale multiphase flow loop as a platform to examine various flow regimes entering the separator. Through laboratory tests employing a PID controller, we collected data concerning the liquid level, gas pressure, input flow rate, and control signals of the separator. Subsequently, we accurately modeled the laboratory system and conducted simulations in a multiple-input-multiple-output mode with model predictive control. After ensuring the effective operation of the laboratory smart control system, we integrated its control model with a production system containing a real fractured reservoir. The results demonstrated that the implementation of the smart integrated production system could enhance oil production by approximately 53% over a 20-year simulation period.

The low oil price and production decline of oil and gas reservoirs, coupled with pressure reduction, necessitate the adoption of cost-effective enhanced oil recovery techniques that yield the greatest recovery. Among different well stimulation methods, hydraulic fracturing plays a key role in creating a conductive conduit to transfer fluids into the well. Extensive experimental studies have investigated different factors affecting proppant conductivity. Most studies ignore the significance of non-Darcy flow. In this paper, two affordable and accessible silica sands, namely Firuzkooh and Hamedan, were chosen as natural proppants. Experimental flow regime recognition was carried out to study the dominant flow regime in propped fracture porous media and determine the flow rates corresponding to the Darcy and Forchheimer equations. Fracture conductivity experiments were conducted based on flow rates compatible with Forchheimer's equation to address the non-Darcy effect. Experiments were conducted on two types of sand and all proppant effective parameters were analyzed. The type, size, and concentration of the proppants, crushing percentage, roundness, and sphericity of the proppants are all factors considered in measuring fracture conductivity. Additionally, fracture width, porosity, and permeability of proppant packs were evaluated. As a result of its better roundness and sphericity, Firuzkooh sand performed better in the experiments. In comparison to 16/30, 20/40 and 30/50 mesh sizes for Firuzkooh sand, 16/30 mesh size sand revealed higher conductivity values at low closure stress. However, when closure stress increased, conductivity values decreased dramatically. Furthermore, 16/30 sand leads to a higher crushing percentage. Based on two proppant concentrations of 0.5 and 2lb/ft2 for Firuzkooh sand proppant packs, results indicate that the higher the proppant concentration, the greater the conductivity.

Separators are a vital part of almost every oil and gas production facility. Because of their importance, optimal separator design is critical. Semi-empirical design method is a conventional and more primitive way of determining the optimal dimensions for separators. However, because of the simplifying assumptions used to derive semi-empirical correlations, this method can only be used to obtain a rough estimate for separator dimensions. In this study, a novel hybrid method to design multiphase separators is presented using experimentation, dimensional analysis, and CFD simulation. This method contains performing experiments on a pilot two-phase separation unit; CFD simulating of the laboratory-scale separator and validating the simulation using the experimental data; determining a range for the slenderness ratio of practical surface separators using dimensional analysis; CFD simulating the separators with slenderness ratios within the specified range using the procedure, and determining the optimum slenderness ratio. The pilot two-phase separation unit consists of a laboratory-scale horizontal two-phase separator, pumps, compressors and a static mixer to create a two-phase flow, and a liquid filter to extract liquid droplets from the separator gas outflow. The diameter of the trapped liquid droplets and their weight are, then, determined by imaging and weighing processes. The CFD model is validated with the experimental data (with less than 8% relative error). Using these steps, the dimensions of a surface separator for one of the production wells located in phase 9 of South Pars gas field are determined. One of the most important achievements of this research is to provide the necessary basis for the optimal design of surface separators.

Assessing, predicting, and controlling injection-induced seismicity is a major challenge for developing enhanced geothermal systems (EGS) due to the complexity of coupled thermo-hydro-mechanical (THM) processes. This study aimed to develop a fully coupled numerical model to assess the complex behavior of a low permeable matrix-fracture during non-isothermal single-phase fluid injection process. A thermo-poroelastic displacement discontinuity (DD) method combining with different forms of finite element method are implemented to encapsulate the fractured medium response and transport processes, respectively. The nonlinear characteristics of normal (changing the joint to hydraulic fracture status) and shear (changing the stick to slip fracture status) fracture deformation are taken into account through fracture constitutive relations. Developed numerical approach was applied to simulate cool water injection into fracture/matrix systems, analyzing the role of coupled processes on spatiotemporal variation of matrix-fracture stresses, temperature and pore pressure and assessing induced seismicity (slippage) and permeability alteration. Numerical simulations demonstrate a fully coupled relation between matrix dilation, shrinkage, and non-linear fracture deformation. The redistribution of dynamic and kinematic parameters along with non-linear fracture deformation showed that although the poroelastic effects are dominant in the early stages, thermoelastic effects dominate in the long-term injection stages.

One of the most challenging issues during drilling operations is lost circulation, which can cause several problems that could lead to increasing the non-productive time (NPT) and drilling cost. Wellbore strengthening techniques have been applied as a well-known approach to increase the mud weight window by improving mud cake properties or adding lost circulation materials (LCMs) to the drilling fluid. The success-to-failure ratio of remedial or preventive solutions during the field operation is highly dependent on the appropriate selection of wellbore strengthening strategy. Initial studies, which have often focused on trial and error and operational practices, have not provided a clear understanding of fundamental mechanisms and performance of LCMs in strengthening of a formation. Hence, in the last decades, several analytical and numerical studies, as well as experimental evaluations have been performed by numerous researchers to simulate the fluid loss process and LCM effectiveness. Conducting a comprehensive and well-designed experimental investigation can be a more applicable and cost-effective approach to select proper wellbore strengthening method and recommend the best drilling fluid formulation to treat the loss zone. The aim of this paper is to present an overall review on the various published experimental investigations, to assess the different aspects of lost circulation and wellbore strengthening theory. This extensive literature review collects limitations, advances, and differing opinions from experts. It also broadens the scope for future work and helps in solving industrial problems from an operational point of view.

One of the most persistent and complicated challenges during drilling a well is lost circulation, which leads to more operational cost, time, and risk. Wellbore strengthening (WBS) with the addition of special solid particles, means lost control materials (LCMs), in drilling fluid is a major solution to control the fluid loss and improve the formation pressure-bearing capacity. The preventive approach of wellbore strengthening is based on the plastering effect of mud cake to inhibit the initiation of new induced fractures or the growth of pre-existing ones. The sealing capability of the mud cake can be affected by LCM properties which has been evaluated by some plugging apparatus with slotted disk in previous researches. However, in this paper, a self-designed core fracturing laboratory setup has been developed to simulate the fracturing process of a rock sample in a more realistic situation and study the effect of LCM particles on the creation of an efficient filter cake to improve the fracture gradient of the formation. Artificial cylindrical concrete cores with a central hole have been used to eliminate the heterogeneity effect of the rock and achieve the same experimental conditions. The fracture breakdown pressure (FBP) and fracture reopening pressure (FRP) have been considered as the objective parameters for evaluation of LCM performance. The experimental results on 18 core samples with two different types of LCM and different particle size distribution show that the addition of LCM particles into drilling fluid can improve FBP and FRP up to 33 % and 72 %, respectively. This indicates that the sealing/plastering effect of mud cake can be improved by LCM properties to achieve a higher fracture pressure. In addition, different fluid systems with different LCM types and LCM sizes have various effects on the preventive approach of wellbore strengthening. Finally, one of the drilling fluid formulations with a desirable performance during laboratory tests was selected to apply for drilling the 12-1/4" hole section in one of Iranian oil fields as a preventive approach where a history of severe lost circulations had been reported. The results of field test showed that using this approach was more successful than the remedial approach used in all previous wells of this field and resulted in a significant reduction in cost and material consumption.

In recent years, there has been a substantial increase in the induced seismicity associated with geothermal systems. However, understanding and modeling of injection-induced seismicity have still remained as a challenge. This paper presents a two-dimensional fully thermo-hydro-mechanical (THM) coupled boundary element approach to characterize the fault response to forced fluid injection and assess the effect of different injection protocols on seismic risk mitigation as well as permeability enhancement. The laboratory-derived rate-and-state friction law was used to capture the frictional paradigm observed in mature faults produced in granite rocks. All phases of stick-slip cycles, including aseismic slip, propagation of dynamic rupture, and interseismic periods, were simulated. The modeling results showed that the residual values of effective normal stress and static shear stress after a particular event completely dominate the constitutive behavior of fault friction during the next seismic event. The seismic energy analyses indicated that there is a negative correlation between the seismic magnitude and the total injected volume, such that a prolonged monotonic injection eventually results in the steady slip, rather than the seismic slip. Several fluid injection protocols were designed based on a volume-controlled (VC) approach and traffic light systems (TLS) to explore their effectiveness on the seismic risk mitigation and permeability enhancement. The results showed that cyclic injection based on TLS is the most effective approach for irreversible permeability enhancement of faults through promoting slow and steady slips. Our numerical simulations also revealed that fluid extraction (backflow-fixing bottom hole pressure at atmospheric pressure), regardless of the injection style, can considerably reduce the seismicity-related risks by preventing the fast-accelerated fracture slip during the post-injection stage. This study presents novel insights into modeling the rate-and-state governed faults exposed to forced fluid injection, and provides useful approaches for shear stimulation of faults with reduced seismic risks.

In low-permeability geothermal reservoirs, hydro-shearing of pre-existing natural fractures can be a suitable method to establish sufficient connectivity between the injection and production wells and increase heat extraction efficiency. In this method, the initial conductivity of natural fractures is increased irreversibly through the dilation resulting from injection-induced slip. In some cases, forced-fluid injection associated with hydro-shearing treatments leads to induced earthquakes, which poses significant challenges for developing geothermal projects. In this study, a boundary element-based fully coupled hydro-mechanical numerical model was developed to simulate hydro-shearing of natural fractures using monotonic fluid injection and traffic light system (TLS)-based cyclic injection. The developed model was used to analyze the efficiency and effectiveness of each proposed injection regime in terms of permeability enhancement and mitigating the associated seismic hazards. Results show that applying monotonic fluid injection for hydro-shearing of a fault leads to a sequence of seismic events, undesirable for successful geothermal projects. This type of injection scheme also perturbs the initial distribution of pressure and stress at neighboring faults and generates complex seismic/aseismic slip interactions on them. The results from the TLS-based cyclic injection show that if the criterion for stopping the injection is set properly, this injection approach is highly efficient in promoting stable and slow slip and enhancing the initial fault conductivity to a significant level. Applying TLS-based cyclic injection simultaneously in two parallel seismogenic faults (simultaneous stimulation) allows controlling seismic slip for a long time while stimulation of each fault separately (multi-stage stimulation) can prevent induced earthquakes for a shorter time. However, the multi-stage approach results in an improved permeability enhancement compared with the simultaneous stimulation.

For addressing the behavior of a reservoir with different fluid types, the Biot-Gassmann equation often is the base of the practical simulation. Despite the prevalence application of this equation with the isotropy conditions, the unforeseen errors always expose in simulation results because of the anisotropy state in reality. We investigated the anisotropy model with the integration of two analytical strategies using a three-component VSP data set. We obtained an initial anisotropy model in the region of acquired walkaway VSP using slowness polarization inversion, and updated the anisotropy model with the application of anisotropy ray-tracing and tomography. We applied a layer-stripping approach to the anisotropy model during raytracing to optimize the inversion. Given a computed geomechanical model and extracted rock properties of a carbonate reservoir, we developed the anisotropy Biot-Gassmann model, for finding the elastic moduli. We used the substitution strategy to generate the dynamic model of elastic moduli. We showed how the compressional modulus and rigidity change with the anisotropy model in different fluid content. We found that integration of slowness polarization and raytracing tomography increases the maneuverability to control the predicted anisotropy model and intensifies the convergence rate of the inverse problem. We observed that the isotropy assumption in modeling the elastic parameters makes around 8-10 % drift value in compressional modulus relevant to the reality, whereas rigidity showed reluctant behavior to fluid.

Summary The safe mud window is determined from 1D Mechanical Earth Model (MEM) of the well. In cases of narrow safe mud window, it is essential to use Managed Pressure Drilling (MPD) technology to evaluate wellbore stability during pipe connection operations. MPD is designed using the closed circulation system in which flow rate, mud density and choke back pressure are used to set and control the bottomhole pressure at a set point of interest. For estimating unmeasured state variables and uncertainty parameters, especially bottomhole pressure, observers’ role is vital. In this paper, the safe narrow mud window of an Iranian oil well is taken from MEM of the well. In continue, the nonlinear Extended Kalman Filter (EKF) is applied to estimate bottomhole pressure at the critical depth. The observer is designed based on topside measurements. Consistency of measurements and estimations indicates that the nonlinear EKF is recommended for estimating down hole pressure and uncertainty parameters.

Separators play a critical role in oil and gas industry by separating well outflows into natural gas, oil and/or water. A common method to design separators is using semi-empirical correlations. However, separator design is a complicated procedure and these correlations include several simplifying assumptions. Hence, evaluating their capability to design separators is necessary. In this study, a pilot two-phase separation unit is designed and constructed to examine the reliability of a selected correlation. The unit consists of a laboratory-scale horizontal two-phase separator, pumps and compressors to pressurize liquid and gas flows, a static mixer to create a two-phase flow, and a liquid filter. The experimental results from the unit show that the correlation could be modified to yield more accurate results. Therefore, including a correction factor into the correlation to reduce the error between the experimental and theoretical results is necessary. The experiments also show that the correction factor is not a constant value and depends on several parameters. Some of these parameters are gas flow rate, liquid density, liquid droplet diameter, drag coefficient, separator diameter, etc. Conducting experiments using the separation unit is time-consuming and costly. In addition, the sensitivity analysis required to develop a correlation between the correction factor and the parameters affecting it is not experimentally possible for some of the parameters. Thus, an artificial neural network is used to predict the correction factor and conduct sensitivity analysis. Because of the reasons mentioned above, obtaining enough experimental data to be used as input for the network is not possible. Therefore, computational fluid dynamics (CFD) simulation is chosen as the proxy model to generate more data for the neural network. The developed CFD model is validated with the experimental data (with less than 8% relative error) and enough data are then exported from it and added to the experimental data set to be used as input for the neural network. Finally, the network is used to predict the required correction factors. The feature parameters affecting the correction factors are also determined using sensitivity analysis. A new neural network developed using only those parameters predict the correction factors with even better accuracy. The semi-empirical equation modified by adding the correction factor can be implemented in separator design with high accuracy, leading to a considerable reduction in cost and time.

Summary Wellbore strengthening (WBS) through plugging the existing fractures on the wellbore wall using lost control materials (LCM) is an effective strategy to handle the problem of drilling fluid loss due to the presence of natural or induced fractures. This process has been modeled in various analytical studies, most of which have neglected the effects of formation temperature and poroelastic properties. In the present research, it has been attempted to add fluid temperature effects and pore pressure variations to previously proposed elastic models to present a thermo-poroelastic analytical solution based on fracture mechanics. Comparing the outputs of this model with those of elastic models indicates that neglecting the impacts of temperature and pore pressure can cause underestimation or overestimation of parameters and reduce modeling accuracy.