Wellbore Region Research Articles

H2 diffusion in cement nanopores and its implication for underground hydrogen storage

Understanding the transport and adsorption characteristics of hydrogen (H2) in calcium silicate hydrate (C-S-H) nanopores is critical to minimize the leakage risks from cement in the wellbore region during underground H2 storage (UHS). However, the critical physiochemical properties of H2 in C-S-H nanopores remain inadequately understood. In this work, we perform molecular dynamics simulations to comprehensively investigate the H2 distribution and diffusion properties in the C-S-H nanopores, considering the crucial parameters of temperature, pressure, and pore size. We evaluate how the density distribution, mean squared displacement (MSD) and diffusion coefficient of H2 evolve with variations in these crucial parameters by comparing H2 properties in C-S-H nanopores with those of bulk H2. We show that H2 molecules are prone to adsorb on C-S-H walls and form a high-density adsorption layer due to strong interactions between C-S-H walls and H2. We find that the confinement of C-S-H nanopores significantly limits the diffusion of H2, leading to smaller diffusion coefficients. Moreover, the diffusion of H2 demonstrates pronounced anisotropic characteristics, with H2 diffusing significantly faster in the direction parallel to C-S-H walls than in the direction perpendicular to the C-S-H walls. We demonstrate that there is a critical pressure, beyond which the diffusion coefficient of H2 parallel to C-S-H walls is close to that in the bulk phase and remains stable. We also show that the impact of nano-confinement gradually diminishes with increasing pore size. Under a given temperature/pressure condition, once the pore size exceeds a threshold, the H2 diffusion coefficient in the C-S-H nanopore is close to that of bulk H2. Our results provide valuable insights into H2 diffusion and adsorption in the C-S-H nanopores at the molecular level, which is critical to assessing and minimizing H2 leakage risks from cement in the wellbore.

Mechanisms of near-wellbore fracture growth considering the presence of cement sheath microcracks and their implications on wellbore stability

Placement of intended perforations is usually extensive enough into the reservoir to minimize any near wellbore influence on the expected fracture growth. However, some unplanned fractures do not necessarily originate from the intended shot holes. A sufficient volume of published work exists on the processes of crack growth from the near wellbore regions such as from the cement sheath or from fractures observed on the formation wall surrounding the wellbore. A robust quantification of wellbore stability issues should not detach such fracture development, which can potentially result into issues such as cement sheath damage and unnecessary formation damage in the near-wellbore regions. Such fractures may become fluid injection points during stimulation related wellbore pressurization, leading to pronounced development. In such scenarios, fracture development may become a nuisance if it jeopardises the intended structural support and zonal isolation integrity of the cement sheath around the wellbore, leading to wellbore failure, and a potential abandonment. The pressure transmission across this structural seal affects the zonal isolation integrity and its intended structural support leading to wellbore instability. Understanding crack growth behaviour in such cement-rock structural framework is still illusional yet it poses the wellbore to a risky state of instability. Our study provides insight into mechanical and elastic behavior of a tightly bonded cement-rock framework with presence of initial cracks. It also provides insight into how the acting far-field stresses, applied wellbore pressures, crack length, and orientation angle influence the crack growth morphologies including planar fractures, curved and cyclic fractures. The study is important not only for a proper selection of the cement slurry but also for the definition of allowable pressures during the wellbore lifespan. Inappropriately selected parameters might lead to the loss of wellbore integrity to a point as early as the start of a well’s life.

Propagation of CO2 desaturation front in near wellbore region

Understanding the development and propagation of CO2 desaturated front is important for managing the potential of CO2 leakage via injection wells after cessation of CO2 injection. The CO2 desaturation front is the front at which oil becomes fully devoid, referred to as “desaturated”, of CO2. In this research, water injection into an oil reservoir containing CO2 is investigated to understand the effect of CO2 component transfer between brine and oil phases in the near wellbore region, as well as to monitor the development of the CO2 desaturation front. CMG-GEM compositional simulator is used to model the process. A 1D cartesian model, including homogenous properties, is utilised for the modelling. The volume of water needed to be injected to desaturate the oil from the CO2 in the vicinity of the wellbore is determined. Additionally, the velocity of the CO2 desaturation front propagation is calculated, and it is compared with the calculations of the Buckley-Leverett saturation front displacement. The study also examines how different parameters such as salinity, pressure, and temperature affect the velocity of the CO2 desaturation front, as CO2 solubility in water is influenced by these parameters. Results show that while varying the injection water salinity affects the velocity at which the CO2 desaturation front propagates, variation in the initial reservoir temperature and pressure, as well as the formation water salinity, has a minor impact, although they do alter the CO2 solubility and thus the mobilities at the front. The results also indicate that compared to the temperature front, which generally propagates at about one third of the saturation front velocity, the CO2 desaturation front in this specific case study travels at about one tenth of the saturation front velocity, so it takes much longer for the near wellbore region to completely desaturate from CO2. Other sensitivities, such as varying the residual oil saturation, affected the propagation of the CO2 desaturation front. The desaturation front travels at a slower speed at greater residual oil saturations due to the greater mass of immobilised CO2 to be displaced by this mechanism.

A Microfluidic and Numerical Analysis of Non-equilibrium Phase Behavior of Gas Condensates

Conventional assumptions about multiphase flow in gas condensate reservoirs often do not correlate with field production. This discrepancy stems from the various mechanisms influencing the multiphase process, which are inadequately represented in numerical models. One of the least understood mechanisms is the influence of the non-equilibrium thermodynamics on the flow in the wellbore region, where the reservoir pressure is below the dew point pressure. To address this problem, experimental and mathematical analyses were conducted using a microfluidic device designed to replicate the flow dynamics in a gas condensate system. The experimental results showed an 11% deviation from the initial pressure of condensate saturation when compared with the conventional assumption of local equilibrium in numerical models. Similarly, there is a 14% deviation between the experimental and simulated volumes of the condensate. These findings underscore the inadequacy of existing models to accurately predict the saturation profile of the condensate phase. A mathematical model based on a relaxation parameter was applied to account for non-equilibrium phase separation and the fog state of the aerosol as observed in the microfluidic experiment. Incorporating a relaxation parameter (τ\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\ au$$\\end{document}) enhanced the accuracy of the prediction of the initial pressure of the condensate saturation and an improvement in the prediction of the condensate volumes from 76% to 97.2%. Consequently, it provides a valuable framework and insight on the non-equilibrium phase behavior of gas condensate systems under constant flow regimes.

Poromechanics Modeling Forecasts Production, Analyzes Productivity Decline

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212200, “Accurate Production Forecasting and Productivity Decline Analysis Using Coupled Full-Field and Near-Wellbore Poromechanics Modeling,” by Yan Li, Bin Wang, and Jiehao Wang, Chevron, et al. The paper has not been peer reviewed. _ Productivity index (PI) decline is caused by different mechanisms in both the wellbore region and the far field. Damage in the wellbore region can be simulated by detailed wellbore modeling. A newly developed full-field and near-wellbore poromechanics coupling scheme is used in the complete paper to model PI degradation against time. Near-wellbore damage and field and well interactions are identified when applying the coupling scheme for a deepwater well. History matching, production forecasting, and safe drawdown limits are derived for operational decisions. Full-Field Reservoir Model and Near-Wellbore Poromechanics Model Coupling Full-field and near-wellbore modeling involves coupling the simulation of a full-field reservoir model with one or more near-wellbore poromechanics models. In the coupled simulation, the full-field reservoir model dictates the changing flow or thermal boundary conditions for the embedded near-wellbore models. Meanwhile, near-wellbore phenomena affect well productivity in the full-field reservoir model, altering the flow and thermal boundary conditions on all near-wellbore models in the same field. While capturing the dynamic interactions between the full-field model and all embedded near-wellbore models is of vital importance, the traditional near-wellbore modeling work flow considers only one-way coupling. This work flow is labor-intensive and lacks the dynamic interplay between the reservoir and near-wellbore models. A novel near-wellbore coupling framework is developed to automate data exchange and capture dynamic interactions between the full-field model and the near-wellbore model. In the full-field reservoir and geomechanics coupling applications, only a reservoir simulator solves reservoir flow and thermal equations and a geomechanics simulator solves solid mechanics equations. The reservoir and geomechanics simulators exchange 3D field data. Because solid mechanics equations are quasistatic, the geomechanics simulator does not take timesteps in full-field coupling. In near-wellbore coupling, however, both reservoir and geomechanics simulators solve reservoir flow and thermal equations. The near-wellbore geomechanics model also may solve solid mechanics or other equations coupled to flow or thermal equations in the near-wellbore model. All physics are included in the near-wellbore model for the coupling. Both field properties (3D) and transient boundary conditions (2D) must be mapped onto the near-wellbore model. It is important to ensure that the full-field and near-wellbore models are consistent. A 3D data-mapping module is developed to map flow and rock properties and initial conditions from the full-field model to the near-wellbore model. During the simulation, the transient pressure/temperature boundary conditions (2D) at the external boundary of the near-wellbore model must be mapped from the full-field model to the near-wellbore model to update transient boundary conditions. The automated data mapping in the coupling scheme eliminates the need for manual mapping of field properties and transient boundary conditions.

Technology Focus: Well Testing (February 2024)

Standing alone as the shortest month of the year, February also features JPT’s Well Testing Technology Focus, reviewing the latest industry publications on the subject. Well testing has enjoyed a recent uptick in activity and interest as operators continually realize the value in understanding and monitoring the dynamic performance of their reservoirs. Whether it pertains to the deliverability of conventional oil and gas or the storage potential for carbon capture and storage, large-scale dynamic data remains one of the more coveted pieces to the subsurface puzzle. There is no silver bullet for reservoir characterization. Instead, proper characterization will always be the result of integrating static and dynamic data, collected at varying scales, with a macro geological understanding. Technology facilitates the collection of the aforementioned data. With the latest technologies pushing limits of what can be achieved, subsurface engineers must rigorously evaluate what reservoir characterization techniques and tools are suited for project objectives. Formation testing (FT) platforms provide many options for operators to get a first look at dynamic reservoir performance and nearly always precede a well test. After digesting the alphabet soup of acronyms, so many FT options exist that one may encounter what psychologists refer to as “choice overload.” FT objectives also may begin to overlap with objectives traditionally reserved for drillstem tests (DSTs), narrowing a long-standing technology gap. The current advances in FT tools are exciting, and using FT tools to perform a “mini-DST” makes for brilliant marketing. However, “mini” could mean up to 10,000 times less produced volume, which undoubtedly affects objectives thought to overlap. Subsurface complexity is mitigated by defining clear objectives and executing data-collection programs to reduce uncertainty. Caution should be taken in selecting how to dynamically test your reservoirs. Regardless of how advanced hardware becomes, achievable objectives always will be dependent on key factors such as rock and fluid properties, reservoir geometry, and local regulatory and environmental considerations. This month’s papers highlight ongoing developments from different segments of the well-testing discipline. Dive into valuable lessons learned from a frontier carbon capture, use, and storage project, backed by an impressively sized data set and an in‑depth review of multiphase effects. This case study covers differing saturations around the wellbore region and fluid types in operations and should have global applications. Learn about the limitations and potential pitfalls of nonisothermal effects in pressure transient analysis, which pose challenges in the reservoir characterization of geothermal wells. Sensitivities to thermal effects on reservoir rock properties provide intriguing insights. Completion efficiency also may be affected by thermal effects, resulting in additional pressure drop at sandface. Finally, catch up on one of the weapons most recently added to the well-testing arsenal with powerful new FT tools that feature industry improvements for greater flexibility and improved data reliability. Recommended additional reading at OnePetro: www.onepetro.org. OTC 32610 Multiphase Flowmeter Comparison in a Complex Field by Mohammed Alqahtani, Saudi Aramco, et al. IPTC 23050 Frequently Asked Questions in the Interval Pressure Transient Test and What Is Next With Deep Transient Test by Saifon Daungkaew, SLB, et al.

Study of calcium carbonate scaling on steel using a high salinity brine simulating a pre-salt produced water

In Brazilian pre-salt production, high carbon dioxide (CO2) levels in the associated gas, high salinity in the water, and high levels of calcium ions cause problems related to corrosion and scale. In practice, the scaling process already begins in the formation and near the wellbore region. However, this work has addressed this issue only on a steel surface, representing what can occur in oil production tubings and equipment since the build-up of these products in the internal walls can also impact the production flow guarantee. Parameters related to the substrate and the environment can influence calcium carbonate (CaCO3) precipitation mechanisms. In this study, the effect of steel surface roughness on calcium carbonate scaling experiments has been studied in a high salinity brine containing sodium bicarbonate (NaHCO3) and calcium chloride (CaCl2), simulating pre-salt produced water and under flow conditions. The scaling tests were carried out with a set-up composed of a peristaltic pump to recirculate the test solution through a flow cell. The scale build-up was analysed by using techniques such as Inductively Coupled Plasma Optical Emission Spectrometry (ICP-OES), X-ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and Energy Dispersion X-ray Spectroscopy (EDS). For tests carried out in 3 h, the smoother surfaces had lower adhesion of calcium carbonate than surfaces with higher roughness. Lepidocrocite and rokuehnite, which are corrosion products, were formed in the substrates with higher roughness values, promoting aragonite formation. This work demonstrates that roughness influences calcium carbonate scale formation under flow conditions, besides affecting the calcium carbonate polymorphs associated with the corrosion process.

Fines migration poses challenge for reservoir-wide chemical stimulation of geothermal carbonate reservoirs

Fines material, which can compromise the permeability of geothermal reservoirs, is often only considered with regard to existing fines like clay particles that are mobilized. However, fines are also generated due to dissolution. This is a significant risk coming from chemical stimulation techniques in geothermal reservoirs, that try to increase the range of stimulation with retarded acid systems. Deeper in the reservoir, fines cannot be extracted as is done in the near wellbore region after stimulation and the generation of fines has to be prevented. This work investigates the dependence of fines generation on the reaction conditions. Flow-through experiments with citric acid on dolostone were conducted, creating dissolution regimes with a range of different Damköhler numbers. During the stimulation experiments, the creation of wormholes and the widening of existing flow paths could be differentiated by the shape of the differential pressure curves measured across the samples. Fines were always generated and could greatly reduce the permeability of the rock samples. But for very high Damköhler numbers, where the dissolution created large pathways, the fines were transported out of the major pathways as well as dissolved therein, thus not interfering with the increase of permeability due to dissolution.

Impact of interphase component transfer on CO2 distribution and pH during CO2 injection in the subsurface

Single phase CO2 injection and CO2 water alternating gas (WAG) injection processes are simulated using reactive transport modelling to understand the inter-phase component transfer between CO2, brine and oil, and to address geochemical (aqueous) reactions induced by CO2 in the near wellbore region. In this research, calculations are performed using a numerical one-dimensional cartesian model with homogenous properties. We investigate how fast the pH changes as CO2 is injected into the system and how the presence of oil affects the velocity of the pH front. We measure the velocity of the front at which oil becomes completely desaturated with respect to CO2 – referred to as the “CO2 desaturation front” and compare it with the classical Buckley-Leverett saturation front displacement during WAG injection. We also study the impact of the WAG cycles on the CO2 desaturation front velocity and the pH change. The study showed that the presence of hydrocarbons in the model buffers and delays the pH drop. By the end of each water cycle all the CO2 was removed from the contacted oil phase within the first few meters from the well. The CO2 desaturation front travels at approximately one twentieth of the phase saturation front velocity during the first three WAG cycles, but it then stopped for later cycles, which gives an indication of the extent of the desaturation of oil. During the WAG injection, different pH fronts developed due to the impact of each cycle on the fluid composition and component transfer. The pH reduction during the last WAG cycles was greater near the injection well as most of the lighter hydrocarbon components were displaced out of the residual “oil”, meaning the CO2 content of this residual phase was higher than for initial cycles. This would result in a greater risk of calcite dissolution around the injection well if there were calcite present in the rock formation.

An insight into wax/asphaltene deposition behavior in the wellbore regions of gas condensate reservoirs

Wax/asphaltene deposition has been an important problem in the gas condensate reservoirs development. The cold plate device is designed to reveal the effect of operating conditions on the wax/asphaltene deposition behavior. The characteristic of wax/asphaltene deposition with well conditions is determined. The results show that when the temperature difference was considered, the growth rate of wax deposition thickness in the operation period was that stabilizing first, rising again, and then slowing down. However, the temperature and hydrogen bonding interaction significantly affects the asphaltene deposition process. The asphaltene deposition rate was stable at the beginning period of operation, then increased significantly, and decreased gradually after reaching the peak value of 21.61 g/cm2·h. An identification diagram of the wellbore deposition location is established. Increased deposition surface area of the cold plate structural design ensures qualitative and quantitative characterization of wax/asphaltene deposition traits. The real well fluids components were employed in the experiments to obtain critical conditions for wax/asphaltene deposition which approximated actual production conditions. This diagram facilitates the reliable identification of wax/asphaltene removal areas in the wellbore during production. This study provides a comprehensive understanding of the wax/asphaltene deposition behavior, which helps the gas condensate well operation safety and efficiency.

Productivity Formula of Horizontal Well in Low-Permeability Gas Reservoir considering Multiple Factors

For horizontal well in low-permeability gas reservoir, the effects of threshold pressure gradient, stress sensitivity, and gas slippage have significant impacts on the well productivity. At present, there are few productivity formulas for horizontal gas well considering all these factors. In this paper, based on the flow analysis of horizontal well in low-permeability gas reservoir, the whole flow field was divided into two parts, namely, far wellbore region and near wellbore region, among which the far wellbore region is composed of plane linear flow region and plane radial flow region and the near wellbore region is composed of vertical plane radial flow region and spherical plane central flow region. Then, a new productivity formula is established based on the steady-state seepage theory and the equivalent seepage resistance method, with the consideration of threshold pressure gradient, stress sensitivity, and gas slippage effect. The accuracy of the formula in this paper is verified through comparing with other classical models, and the influence of various factors on the well productivity is analyzed. The analysis results show that stress sensitivity has the most significant effect on horizontal gas well production, followed by threshold pressure gradient, and the gas slippage has the least effect. With the consideration of all influencing factors, the higher the formation pressure and reservoir thickness, the higher the productivity, and the increase of productivity increases with the increase of flow pressure difference. The increasing trend of gas productivity index per meter with the increase of reservoir permeability is first fast and then slow. When the reservoir permeability is greater than 1.2 mD, the increment of gas productivity index per meter (MGPI) decreases. When the length of horizontal well is greater than 1400 m, the increment of gas productivity index per meter decreases with the increase of gas reservoir thickness. Therefore, it is recommended to control the horizontal well length within 1400 m in low-permeability gas reservoir. In addition, the absolute open flow charts corresponding to reservoir thickness and horizontal well length under different reservoir permeability conditions were also given, which can provide theoretical guidance for the selection of horizontal well length during the development of low-permeability gas reservoirs.

Productivity optimization of the oil wells using matrix acidizing- Haoud Berkaoui field case study

Mixed organic and mineral deposits clogging perforations in the near wellbore area is a significant problem in the oil and gas industry. Matrix acidizing is widely applied to relieve this damage in the Haoud Berkaoui region using three different acid systems proposed by company services to restore the initial properties. This work aims to understand and interpret the history to investigate the efficient acid system adapted to the reservoir of two candidate wells. Different data are collected and analyzed. However, laboratory tests were conducted to verify the performance of each acid. Matching laboratory results, Acid Response Curves (ARC) interpretation, and microscopic photos with field data analysis show that only one mud acid system (6% HCl-1.5% HF) among the three is adequately used in the field to minimize the skin factor. It also increases the relative permeability in the wellbore region (7 for well N1 and 3.7 for well N2) and a flow rate gain (0.25 m3/h for the well N2). This study allows the best acid selection and suitable additives for maximum oil recovery of wells, solving problems associated with the production of wells and decreasing the cost of the operation in the future.

An Insight Into Wax Precipitation, Deposition, and Prevention Stratagem of Gas-Condensate Flow in Wellbore Region

Abstract Unlike conventional waxy crude oil, the condensate undergoes a complex phase evolution process in high-temperature and high-pressure conditions of a deep gas-condensate reservoir, which makes it more difficult to predict and prevent the wax precipitation. This study measured the component composition, physical properties, and carbon number distribution of the closed sampled condensates from the wellbore region. The fluid component in wells was corrected by combining with the gas–oil ratio of the actual production data. The wellbore temperature and pressure profiles were accurately predicted using the corrected component, and the phase envelope relationship of gas-condensate flow was reasonably determined. A cold finger apparatus was designed to test the wax deposition characteristics. The main test unit consists of a completely closed high-pressure autoclave and a cold finger with a maximum 140 °C temperature-tolerant and 16,000 psi pressure-tolerant ability. The wax deposition characteristics were formulated, including wax appearance temperature (WAT), critical conditions for wax deposition, wax crystal morphology, and wax deposition rate. The primary mechanisms causing wax deposition in the wellbore region of deep gas-condensate reservoirs are still thermal diffusion and molecular diffusion. A wax crystal improved wax inhibitor consisting of hydrocarbons and polymers was collected and employed. The wax crystal improved wax inhibitor showed remarkable wax prevention performance, reducing WAT by up to 80% and achieving a 90% wax inhibiting rate within the experimental measurement concentrations. These results offer insights into the wax precipitation behavior, wax deposition characteristics, and wax prevention of the condensates.

Interactions of Hydraulic Fractures With Grain Boundary Discontinuities in the Near Wellbore Region

AbstractHydraulic fractures often turn or branch, interacting with preexisting discontinuities in the rock mass (e.g., natural fractures or defects). The criteria for fracture penetration or deflection are typically based on the in situ stress, and the angle and strength of discontinuities. However, in hydraulic fracture experiments on carbonate rocks (Naoi et al., 2020, https://doi.org/10.1093/gji/ggaa183), small scale analyses show that the fractures deflected more frequently at discontinuities (grain boundaries) as they propagated farther from the wellbore, a finding not explained by the conventional criteria. Here, we demonstrate that the energy dissipation of a deflecting fracture increases with the distance from the wellbore, such that a propagating hydraulic fracture more easily deflects at a discontinuity from an energetic standpoint. This tendency was confirmed by hydraulic fracture simulations based on a successive energy minimization approach. Our findings, which show that wellbores appreciably affect the behavior of hydraulic fractures, highlight the importance of energetic stability analysis for determining fracture paths.

A NEW METHOD FOR PREDICTION OF THE CONDENSATE BANKING SIZE AROUND A GAS CONDENSATE WELL

The main problem in the production operation from gas condensate reservoirs is well deliverability loss due to condensate formation and banking around the well as pressure falls below the dew point pressure. It is a common practice to calculate gas condensate well production performance based on the three flow regions. The size of Region 1 (a near wellbore region with high condensate saturation) plays an essential role in the productivity loss of gas condensate wells. In this study, a radial reservoir model is constructed using a compositional model to perform a number of analyses on a single well model. Real data from a large gas condensate reservoir located in the Middle East is applied to the reservoir model. Then, the impacts of affecting parameters are studied using the validated reservoir model. The results of this study show that key parameters, which have a significant effect on the size of condensate banking around gas condensate wells, are rock permeability, rock porosity, reservoir thickness, cumulative gas production, and pressure-dependent fluid parameters such as interfacial tension, viscosity, and density. Finally, using dimensionless analysis, a new relation is proposed to predict the radius of condensate banking (Region 1). This procedure is applicable in similar cases.

Technology solutions and challenges for marginal development of heavy oil fields in CuuLong basin, offshore Vietnam

The production of heavy oil at Dong Do field located in CuuLong basin is a success in the application of advanced technologies. Dong Do field is a marginal project in Vietnam, so its development requires to overcome several challenges, such as high water-cut from early stage, highly unconsolidated sandstone reservoir, flow assurance problems of sour and viscous crude oil, high power artificial lift system, and complex crude treatment at topsides, among others. Over the past decades, production technology application in heavy oil production has been widely deployed in the industry. Apart from the thermal method, the combination of gaslift and ESP technology makes the remarkable advances by enlarging the draw-down created over the conventional pumping lift in heavy oil projects. In fact, heavy oil production with a high flow rate has appeared water-coning in near wellbore region that made the water breakthrough early and water-cut increased rapidly. The pilot test of injecting diesel into heavy oil wells has been applied to producers with the positive results while significantly reduced water-cut comparing before wells shutin. This paper provides a thorough analysis of the new technologies that are applied to Dong Do field, highlighting its key difficulties and how they were resolved through a successful pilot and testing of the cutting-edge advanced solutions, improving the project reliability and thus motivating the consortium to move on to the new field. Also, the updated new heavy oil field schedule is described, highlighting the challenges to be faced during the next projects of marginal development.

Impact of crude oil properties on stability of HCl-crude oil emulsion using XDLVO theory

Undesired emulsification of HCl-crude oils during acid jobs may compromise oil production due to clogging of near wellbore region. This may be resulted from the presence of natural surfactants such as asphaltene. In this paper, the relation between some of crude oil properties including API gravity, dynamic viscosity, polarity, total base number (TBN) with the emulsion stability has been studied by applying the XDLVO theory. The results showed that TBN, and polarity of the crude oil medium can be manifested as reliable criteria for predicting the emulsion stability, while the impact of API gravity and dynamic viscosity of the crude oil were marginal. Sensitivity analyses were also carried out to discern the most dominant parameters on the total interaction energy between droplets in the HCl-crude oil emulsions. It was found that in short distances between droplets, the effect of electron acceptor/donor components are important in such a way that a crude oil with high electron donor and low electron acceptor components would form more stable emulsion when it is mixed with the HCl solution, while no noticeable effect was observed for longer distances. In addition, the results of adhesion tests showed that the presence of HCl solution increases the adhesion of different crude oils onto a glass surface. This is imperative for evaluating the extent of formation damage due to acid-crude oil emulsion and acid sludge formation, when they stick to the rock surfaces. These findings can serve as guideline for choosing the appropriate acid stimulation job in connection with crude oil properties for management of formation damage.

Simulation of gas production from hydrate reservoirs (AT1) of Eastern Nankai Trough, Japan

Gas hydrates are regarded as one of the most promising alternative sources of energy, which have the potential to address the energy demand of a contemporary society. Based on the field explorations in the Eastern Nankai Trough (Japan), a multilayered hydrate reservoir model has been conceptualised and its behaviours during depressurisation production are simulated. This model incorporates the effects of the initial reservoir temperature and permeability on the mechanism of hydrate dissociation, which in turn affects the gas production. It is shown that the dissociation process is largely affected by the initial temperature distribution within the reservoir layers, and the ‘warmer’ reservoirs show (consistently) higher production potential. Furthermore, the gas production could be improved significantly, by increasing the permeability of the wellbore region, which can be achieved through the fracturing process. The close match between the simulation results and the field tests is noteworthy. The proposed multilayered model would be quite useful for analysing the efficacy of the ‘production strategy’, in most real-life situations.

Well inflow performance under fines migration during water-cut increase

Fines migration is a widespread cause of productivity problems for oil production wells. Modelling efforts often focus on the effect of high fluid velocities in the near wellbore region on fines detachment and straining. Recent studies have highlighted the importance of capillary detachment of clays by the oil–water meniscus during imbibition, which occurs during commingled oil and water production during water-cut increase. In this study, we develop a new model to quantify the total detachment during increase in water saturation with two-phase flow and the consequent formation damage to production well. The fines-detachment model proposed is presented in the form of the maximum retention concentration as a function of saturation. The model shows good agreement with laboratory measurements. Finally, the maximum retention function (MRF) is incorporated into an inflow-performance homogeneous reservoir model. The resulting model allows calculating the productivity decline occurring during the increase of water-cut due to fines migration. The results are presented as the well impedance versus the water-cut (fractional flow). These curves, summarising well productivity history, allow predicting the growth of formation damage during the well life, determining the time for well stimulation, and calculating the final impedance at abandonment. The model is compared with production histories for three wells, and good agreement is found.

Characterization of a Non-Darcy Flow and Development of New Correlation of NON-Darcy Coefficient

Darcy’s law has long been used to describe the flow in porous media. Despite the progress that took place in oil production industry research, it became clear that there is a loss of pressure, especially in the area near the wellbore region, where Darcy’s law is not applicable. For this reason, Forchheimer presented his equation in 1910, where he added a new term to Darcy’s law dealing with pressure loss due to inertial forces by introducing a new term, the β coefficient, into the equation. This paper presents a study of fluid flow through porous media, where water was used as a working fluid. Furthermore, the characteristics of the non-Darcy flow were analyzed by presenting the corresponding pressure and velocity gradient curves for each pressure. Extensive analysis indicates that many of the correlations available in the literature either have defective units or are the product of a small number of experiments. In this study, we benefit from relatively large samples, the radial flow, and the perforation in the middle of the samples. The properties of the samples were measured using mercury intrusion porosimetry. It was found that there is a direct relationship between the porosity and the grain’s size; the greater the size of the grains, the greater the porosity, and vice versa. The non-Darcy coefficient term, β, is found to be inversely proportional to the porosity and permeability. In a previous study, the β was investigated for compressible flow scenarios; however, this study calculated it for an incompressible flow. Finally, by analyzing the β values of both studies, we could deduce new novelty correlations for the β coefficient term, where the permeability, porosity, and tortuosity are included.