Multiphase Flow Effects Research Articles

Effect of Fluid Type and Multiphase Flow on Sand Production in Oil and Gas Wells

Summary Controlled laboratory experiments and some field studies have shown that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3D sand-production numerical model are presented to explain the differences in the onset of sanding and sand-production volume for different fluids and under different flow and in-situ stress conditions. The sand-production model accounts for multiphase-fluid flow and is fully coupled with an elasto-plastic geomechanical model. The sanding criterion considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed on the basis of the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) resulting from gas flow is modeled using phase equilibrium calculations. The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared with oil wells. The primary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand-production rate when non-Darcy effects are considered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and, consequently, smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosion perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multiphase- and compressible-fluid flows, helping us to predict sanding issues in both oil and gas wells.

Flow Regime Affects Erosion Prediction in Multiphase Flow

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28360, “Investigation of Erosion Caused by Fine Particles in Multiphase Flow,” by Tran Nguyet Ngo, SPE, and Deng-Jr Peng, Intecsea, and William Pao, Hamdan Ya, and Rohaizad M. Norpiah, SPE, Petronas, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Erosion caused by fine solid particles presents one of the greatest threats to oil and gas flow assurance, consequently affecting material selection and wall-thickness design. The authors of this paper conclude that the erosional effect caused by microsized particles is dependent on the flow patterns in the pipe, determined by superficial velocities of each phase. The results of the proposed modeling using multiphase computational fluid dynamics (MCFD) are expected to benefit erosion-impact assessment in multiphase hydrocarbon-production and -piping systems. Introduction Understanding the effect of key parameters that regulate erosion mechanisms is essential. Studies addressing these issues have concluded that particles rebound and that the erosion profile is dependent on particle motion inside oilfield conduits. Researchers also have found that the direct-impingement (semiempirical) model agreed with results achieved with the discrete-phase model implemented in CFD, while the pure empirical model severely under-predicted the erosion, thus emphasizing the importance of flow-behavior modeling. Furthermore, the majority of available erosion-prediction models involve single-phase systems, not taking into account multiphase flow patterns that address the characteristics of individual flow behaviors. In other studies, the erosional effect caused by microsized particles in single-phase carrier fluid also has been reported. One hypothesis is that the presence of these microsized particles acts as an enabler, which produces homogeneous pits on the surface of metal, increasing significantly the contact surface area upon which chemical and mechanical interactions can take place. The effect of multiphase flow and its interaction with sand particles, specifically fine solids, is often neglected. Hence, integrating both the erosion and fluid-flow models is essential in enhancing the accuracy of erosion evaluation. MCFD Model for Erosion Prediction In a pipeline system, the eroded spots caused by particles are detected typically at locations with restricted flow characteristics or radically changing flow directions, where the bend or elbow is identified as an erosion-susceptible area. Hence, in the present study, a 1-in. elbow is designed with a horizontal inlet and vertical upward outlet orientation. A length of 10 times the elbow internal diameter is placed upstream and down-stream of the 90° elbow. The computational procedure for this work includes MCFD simulation, where an annular flow regime of air and water is modeled in the elbow, incorporated with the division of grids to represent predefined flow conditions (Step 1). By tracking particle impingement within the carrier fluids (Step 2), erosion rate is calculated and analyzed (Step 3).

Computational analysis of compressibility effects on cavity dynamics in high-speed water-entry

The objective of this study is to analyze the compressibility effects of multiphase cavitating flow during the water-entry process. For this purpose, the water-entry of a projectile at transonic speed is investigated computationally. A temperature-adjusted Tait equation is used to describe the compressibility effects in water, and air and vapor are treated as ideal gases. First, the computational methodology is validated by comparing the simulation results with the experimental measurements of drag coefficient and the theoretical results of cavity shape. Second, based on the computational methodology, the hydrodynamic characteristics of flow are investigated. After analyzing the cavitating flow in compressible and incompressible fluids, the characteristics under compressible conditions are focused upon. The results show that the compressibility effects play a significant role in the development of cavitation and the pressure inside the cavity. More specifically, the drag coefficient and cavity size tend to be larger in the compressible case than those in the incompressible case. Furthermore, the influence of entry velocities on the hydrodynamic characteristics is investigated to provide an insight into the compressibility effects on cavitating flow. The results show that the drag coefficient and the impact pressure vary with the entry velocity, and the prediction formulas for drag coefficient and impact pressure are established respectively in the present study.

Proppants—What 30 Years of Study Have Taught Us

Summary The earliest hydraulic-fracture stimulations used poorly sorted river sand as the proppant. Since this first experiment with proppants, the industry has evolved to offer a broad range of proppant choices although, by far, natural sand of some type remains the proppant of choice for a variety of reasons. For the past 30 years, an industry Consortium has engaged in a continuous program of building knowledge and understanding in the behavior of all types of proppants used in hydraulic fracturing. There are many basic understandings about the behavior of proppant packs under downhole reservoir conditions that have been developed through thousands of tests that have been performed through this work. These include the effects of proppant type, grain failure, fines migration, embedment, non-Darcy and multiphase flow, cycling, loading, packing arrangement, fracture-fluid damage, and others. All these effects can be at work simultaneously to negatively affect flow in the propped fracture, and the recognition of these effects assists in explaining observed well performance. This paper will present current knowledge of proppant performance that is sometimes misunderstood or wrongly applied and will assist the practicing engineer in well diagnostics and stimulation design.

Proppant-packed fractures in shale gas reservoirs: An in-situ investigation of deformation, wettability, and multiphase flow effects

The results of a systematic, micro-scale experimental investigation on two-phase gas/brine flow through proppant-packed fractured shale samples under increasing effective stresses of up to 5000 psi are presented in this paper. We use a miniature core-flooding apparatus integrated with a high-resolution X-ray micro-CT scanner to perform the flow experiments. Geomechanical deformation and its impact on displacement mechanisms governing fluid transport within the packed fractures are studied at the pore scale under certain flow and stress conditions. These conditions were carefully designed to represent reservoir depletion and transport of water through such media. Since proppant grains are placed to maintain the long-term conductivity of the induced fractures, they significantly influence the geomechanical and multi-phase flow behavior of these conduits during reservoir depletion. We particularly examined the effectiveness of modified resin-coated sand (compared to a basic white sand) in maintaining the hydraulic conductivity of induced fractures. Significant bullet-like embedment and proppant crushing under severe stress conditions were found to be the shortcomings of these proppants, respectively. We then developed a methodical framework to design improved proppants with a similar mechanical strength to the host shale rock to withstand these drawbacks.Sphericity, roundness, and size of the proppant grains also impacted the critical properties of the constructed pore space such as pore size distribution and pore-throat aspect ratio. Such parameters control pore-scale gas-to-brine and brine-to-gas displacements within the hydraulic fractures. We specifically studied the non-wetting phase trapping and its subsequent impact on reduction of available pore space for other fluids to flow. It was found that trapped gas globules are very likely to deform within the medium and redistribute/reconnect under a higher effective stress. For the first time, wettability alteration of the proppant pack from water-wet to oil-wet was observed in a gas/brine fluid system. Wettability alteration occurred non-uniformly and was thought to be due to deposition of the shale organic matter released after significant proppant embedment. Such wetting characteristics aggravate multi-phase trapping within the fractures, which in turn leads to dramatic reductions in effective gas permeability. This study is concluded with a set of recommendations that can be used to effectively maintain the productivity of propped fractures for extended period of time.

Numerical simulation of radiation distribution in a slurry reactor: The effect of distribution of catalyst particles

The multiphase flow leads a non-uniform distribution of catalyst particles in a slurry reactor. The previous studies used the inlet catalyst loading to compute the absorption coefficient and the scattering coefficient in the slurry reactor, which did not consider the non-uniform distribution of catalyst particle. The present study numerically studies the effect of multiphase flow on the radiation distribution in a slurry reactor. Herein, the absorption coefficient and the scattering coefficient are related to the local volume fraction of catalyst. The volume fraction of catalyst is obtained using the Eulerian-Eulerian method. The radiative transfer equation is solved using the DO model. Results show that the local catalyst loading are non-uniform in the slurry reactor. The reactor-averaged catalyst loading is always less than the inlet catalyst loading. It may leads to the underestimation of the incident radiation as well as UV disinfection and the overestimation of LVREA and as well as photocatalytic reaction rate. It is more reasonable to compute the absorption coefficient and the scattering coefficient using the local catalyst loading. A large diameter and a large inlet catalyst loading can lead to a large catalyst loading in the reactor, the large absorption coefficient and scattering coefficient, meaning a low radiation intensity in the reactor. There exists an optimal inlet catalyst loading for the photocatalytic reaction.

A review of multiphase flow and deposition effects in film-cooled gas turbines

This paper presents a review of particle deposition research in film-cooled gas turbines based on the recent open literature. Factors affecting deposition capture efficiency and film cooling effectiveness are analyzed. Experimental studies are summarized into two discussions in actual and virtual deposition environments. For investigation in virtual deposition environments, available and reasonable results are obtained by comparison of the Stokes numbers. Recent advances in particle deposition modeling for computational fluid dynamics are also reviewed. Various turbulence models for numerical simulations are investigated, and solutions for treatment of the particle sticking probability are described. In addition, analysis of injecting mist into the coolant flow is conducted to investigate gas-liquid two-phase flow in gas turbines. The conclusion remains that considerable re-search is yet necessary to fully understand the roles of both deposition and multi-phase flow in gas turbines.

Evenly spaced columns in the Bishop Tuff (California, USA) as relicts of hydrothermal cooling

Author(s): Randolph-Flagg, N; Breen, S; Hernandez, A; Manga, M; Self, S | Abstract: A few square kilometers of the Bishop Tuff in eastern California (USA) have evenly spaced columns that are more resistant to erosion than the surrounding tuff owing to the precipitation of mordenite, a low-temperature (100-130 °C) zeolite. We hypothesize that the columns are a result of instabilities at the liquid water and steam interface as cold water seeped into the still-cooling Bishop Tuff. We use two methods to quantitatively assess this hypothesis. First, scaling shows which hydrodynamic instabilities exist in the system. Second, to account for the effects of multiphase flow, latent heat, and the finite amplitude and temporal evolution of these instabilities we use two-dimensional numerical models of liquid water infiltrating hot tuff. These tests highlight several features of boiling hydrothermal systems. (1) The geometry of at least some convection appears to be broadly captured by linear stability theory that neglects reactive transport, heterogeneity of the host rock, and the finite amplitude of instabilities. (2) Slopes g 10% set the wavelength of convection, meaning that these columns formed somewhere with relatively gentle topography. (3) For permeabilities of g 10-13 m2, the wavelength of the instability changes through time, slowing infiltration, while for permeabilities l 10-15 m2, cooling is dominated by conduction. The spacing and stability of columns increase with higher vertical permeability and decrease with higher horizontal permeability. These columns are a rare window into hydrothermal processes that may be widespread.

3D CFD simulation of Multi-phase flow separators

During the exploitation of natural gas, some water and sands are contained. It will be better to separate water and sands from natural gas to insure favourable transportation and storage. In this study, we use CFD to analyse the effect of multi-phase flow separator, whose detailed geometrical parameters are designed in advanced. VOF model and DPM are used here. From the results of CFD, we can draw a conclusion that separated effect of multi-phase flow achieves better results. No solid and water is carried out from gas outlet. CFD simulation provides an economical and efficient approach to shed more light on details of the flow behaviour.

Forecasting production of liquid rich shale (LRS) reservoirs using simple models

Due to the advent of shale reservoirs as important sources of oil and gas production, there has been a critical need for reliable techniques for forecasting production and estimating reserves from these plays. This work presents the results of a study to determine whether simple decline models can be used to forecast production and estimate reserves of both oil and gas in liquid rich shale (LRS) reservoirs with reasonable accuracy. We found that hybrid models (i.e., one model such as the Duong model for transient flow coupled with a different model, such as the Arps hyperbolic model with an appropriate value of the parameter “b”) are appropriate for forecasting oil production and that it is possible to forecast solution gas production with availability of adequate data.To establish the “truth case” for comparison, we simulated production with four different reservoir fluids using a commercial compositional reservoir simulator. We tested a variety of hybrid and simple DCA models on simulated data (and later on field data) with a work flow that included identifying flow regimes with diagnostic plots for each fluid sample. We analyzed 0.5–3 years of production history to estimate model parameters for forecasting future production. Also, we forecasted gas production using a technique similar to one recently presented in the literature.Lengthy transition periods between transient linear flow and boundary dominated flow (BDF) were observed on the diagnostic plots. This is presumably due to multi-phase flow effects, as this transition period is typically much shorter in single-phase shale reservoirs. As in single-phase flow, the Arps decline model proved to be good for forecasting in the BDF regime. For transient flow, we examined the Duong model (which includes transient linear flow as a special case) and YM-SEPD (modified form of Stretched Exponential Production Decline model). In some cases, we applied the Arps model for both the transition period and BDF regimes (with different b values). We concluded that hybrid DCA models are more appropriate for multi-phase flow analysis than simple DCA models. In most of the cases, the hybrid YM-SEPD and Arps models led to more accurate oil production forecasts than other alternatives. Our analyses of solution gas forecasts indicated that solution gas production forecasting is possible but there is still need for more research in this area.

Statistical, Data-Driven Approach to Forecasting Production from Liquid-Rich Shale Reservoirs

The oil and gas industry needs fast and simple techniques of forecasting oil and gas production. Forecasting production from unconventional, low permeability reservoirs is particularly challenging. As a contribution to the continuing efforts of finding solutions to this problem, this paper studies the use of a statistical, data-driven method of forecasting production from liquid-rich shale (LRS) reservoirs called the Principal Components Methodology (PCM). In this study, production of five different highly volatile and near-critical oil wells was simulated for 30 years with the aid of a commercial compositional simulator. Principal Components Methodology (PCM) was applied to production data from the representative wells by using Singular Value Decomposition (SVD) to calculate the principal components (PCs). These principal components were then used to forecast oil and solution gas production from the near-critical oil wells with production histories ranging from 0.5 to 2 years, and the results were compared to simulated data and the Modified Arps’ decline model forecasts. Application of the PCM to field data is also included in this work. Various factors ranging from ultra-low permeability to multi-phase flow effects have plagued the mission of forecasting production from liquid rich shale reservoirs. Traditional decline curve analysis (DCA) methods have not been completely adequate for estimating production from shale reservoirs. The PCM method enables us to obtain the production decline structure that best captures the variance in the data from the representative wells considered. This technique eliminates the need for parameters like the hyperbolic decline exponents (b values) and the task of switching from one DCA model to another. Also, production forecasting can be done without necessarily using diagnostic plots. With PCM, production could be forecasted from liquid-rich shale reservoirs with reasonable certainty. This study presents an innovative and simple method of forecasting production from liquid-rich shale (LRS) reservoirs. It provides fresh insights into how estimating production can be done in a different way.

Displacement Efficiency for Low-Salinity Polymer Flooding Including Wettability Alteration

SummaryPolymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date.This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator.The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Thermal–hydraulic–mechanical behavior of bentonite and sand-bentonite materials as seal for a nuclear waste repository: Numerical simulation of column experiments

Depending on the repository concept, buffer materials around the canister may play an important role for the performance of deep geological repositories for high-level radioactive waste (HLW). Coupled thermo-hydro-mechanical (THM) processes are initiated in the buffer material, as heat produced by the HLW typically causes an initial drying of this sealing layer, which may be followed by re-saturation with fluid from the host rock. In this study, a fully coupled and process-oriented numerical model was applied to simulate laboratory experiments investigating two buffer materials, i.e. clay pellets as well as a sand-bentonite mixture. The developed models account for heat transport, multiphase flow and mechanical effects from swelling and thermal expansion. Model calibration was achieved by first determining the most sensitive parameters for heat and multiphase flow effects. A good fit between experimental data and model results was achieved for temperature, relative humidity, water intake and swelling pressure measurements. It is found that a unique set of thermal parameters for the insulation materials of the two experiments can be identified, which allows for a reliable estimate of the heat balance of the experiments. The most important parameters identified are the intrinsic and relative permeability, the water retention curve and the saturation dependent thermal conductivity of the buffer materials. It is further shown that the transient saturation state of the buffer material strongly influences its hydraulic and thermal behavior. The buffer material behavior thus identified contributes to the evaluation of larger scale in-situ experiments, and to better design deep geological repositories.

A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II

Summary Horizontal wells combined with successful multistage-hydraulic-fracture treatments are currently the most-established method for effectively stimulating and enabling economic development of gas-bearing organic-rich shale formations. Fracture cleanup in the stimulated reservoir volume (SRV) is critical to stimulation effectiveness and long-term well performance. However, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls to less than expectations. A systematic study of the factors that hinder fracture-fluid cleanup in shale formations can help optimize fracture treatments and better quantify long-term volumes of produced water and gas. Fracture-fluid cleanup is a complex process influenced by multiphase flow through porous media (relative permeability hysteresis, capillary pressure), reservoir-rock and -fluid properties, fracture-fluid properties, proppant placement, fracture-treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best and most-practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent effect on fracture-fluid cleanup and well deliverability. In this paper, a 3D, two-phase, dual-porosity model was used to investigate the effect of multiphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir-rock compaction, gas slippage, and gas desorption on fracture-fluid cleanup and well performance in Marcellus Shale. The research findings have shed light on the factors that substantially constrain efficient fracture-fluid cleanup in gas shales, and we have provided guidelines for improved fracture-treatment designs and water management.

Numerical Investigation of Coupling Multiphase Flow and Geomechanical Effects on Water Loss During Hydraulic-Fracturing Flowback Operation

SummaryLess than half the fracturing fluid is typically recovered during the flowback operation. This study models the effects of capillarity and geomechanics on water loss in the fracture/matrix system, and investigates the circumstances under which this phenomenon might be beneficial or detrimental to subsequent tight-oil production. During the shut-in (soaking) and flowback periods, the fracture conductivity decreases as effective stress increases because of imbibition. Previous works have addressed fracture closure during the production phase; however, the coupling of imbibition caused by multiphase flow and stress-dependent fracture properties during shut-in is less understood.A series of mechanistic simulation models is constructed to simulate multiphase flow and fluid distribution during shut-in and flowback. Three systems—matrix, hydraulic fracture, and microfractures—are explicitly represented in the computational domain. Sensitivities to wettability and multiphase-flow functions (relative permeability and capillary pressure relationships) are investigated. As wettability to water increases, matrix imbibition increases. Imbibition helps to displace the hydrocarbons into nearby microfractures and hydraulic fractures, enhancing initial oil rate, but it also hinders water recovery. The results indicate that fracture closure may enhance imbibition and water loss, which, in turn, leads to further reduction in fracture pressure and conductivity. Results also suggest that more-aggressive flowback is beneficial to water cleanup and long-term oil production in stiff rocks, whereas this benefit is less prominent in medium-to-soft formations because of excessive fracture closure. Because no direct correlation between high initial oil-flow rate and improved cumulative oil production is observed, measures for increasing oil relative permeability are recommended for improving long-term oil production.This work presents a quantitative study of the controlling factors of water loss caused by fluid/rock properties and geomechanics. The results highlight the crucial interplay between imbibition and geomechanics in short- and long-term production performances. The results in this study would have considerable impact on understanding and improving current industry practice in fracturing design and assessment of stimulated reservoir volume.

The multiscale restriction smoothed basis method for fractured porous media (F-MsRSB)

A novel multiscale method for multiphase flow in heterogeneous fractured porous media is devised. The discrete fine-scale system is described using an embedded fracture modeling approach, in which the heterogeneous rock (matrix) and highly-conductive fractures are represented on independent grids. Given this fine-scale discrete system, the method first partitions the fine-scale volumetric grid representing the matrix and the lower-dimensional grids representing fractures into independent coarse grids. Then, basis functions for matrix and fractures are constructed by restricted smoothing, which gives a flexible and robust treatment of complex geometrical features and heterogeneous coefficients. From the basis functions one constructs a prolongation operator that maps between the coarse- and fine-scale systems. The resulting method allows for general coupling of matrix and fracture basis functions, giving efficient treatment of a large variety of fracture conductivities. In addition, basis functions can be adaptively updated using efficient global smoothing strategies to account for multiphase flow effects. The method is conservative and because it is described and implemented in algebraic form, it is straightforward to employ it to both rectilinear and unstructured grids. Through a series of challenging test cases for single and multiphase flow, in which synthetic and realistic fracture maps are combined with heterogeneous petrophysical matrix properties, we validate the method and conclude that it is an efficient and accurate approach for simulating flow in complex, large-scale, fractured media.

A coupled geomechanical reservoir simulation analysis of CO2- EOR: A case study

Currently, there is a great interest in the coupling between multiphase fluid flow and geomechanical effects in hydrocarbon reservoirs and surrounding rocks. The ideal solution for this coupled problem is to introduce the geomechanical effects through the stress analysis solution and implement an algorithm, which assures that the equations governing the flow and stress analyses are obeyed in each time step. This paper deals with the implementation of a program (FORTRAN90 interface code), which was developed to couple conventional reservoir (ECLIPSE) and geomechanical (ABAQUS) simulators, using a partial coupling algorithm. The explicit coupled hydro-mechanical behavior of Iranian field during depletion and <TEX>$CO_2$</TEX> injection is studied using the soils consolidation procedure available in ABAQUS. Time dependent reservoir pressure fields obtained from three dimensional compositional reservoir models were transferred into finite element reservoir geomechanical models in ABAQUS as multi-phase flow in deforming reservoirs cannot be performed within ABAQUS. The FEM analysis of the reservoir showed no sign of plastic strain under production and <TEX>$CO_2$</TEX> injection scenarios in any part of the reservoir and the stress paths do not show a critical behavior.

Numerical investigation of limitations and assumptions of analytical transient flow models in tight oil reservoirs

The complex fracture network created by multistage hydraulic fracturing has been recently described by triple porosity models. Existing triple porosity models typically assume sequential flow from matrix to micro fractures and from micro fractures to hydraulic fracture. Modeling simultaneous depletion of a matrix block into both micro and hydraulic fractures entails solution of a two dimensional continuity equation that is challenging by analytical or even semi-analytical methods. In addition, analysis with analytical models and type-curves provides deterministic and homogeneous estimates, rendering uncertainty analysis of fracture properties difficult.In this paper, we use a commercial reservoir simulator to compute the transient response in a segment of a hydraulically fractured horizontal well with a triple-porosity model, where matrix and fracture elements are explicitly discretized. Some limitations in analytical models such as sequential flow, single-phase flow and fully-connected symmetric fractures are investigated using the actual rate data from two tight oil wells completed in the Cardium and Bakken formations. An early drop in production, as commonly observed in many tight oil wells, could be attributed to gas dissolution with pressure decline and multiphase flow effects. Impacts of pressure interference between natural fractures and inter-well fracture communication are also investigated. Uncertainty in model parameter estimation is studied by assuming that results obtained from analytical solutions would characterize the mean estimate of the corresponding fracture parameters, additional heterogeneous models of natural/induced micro-fracture properties including its total number and intensity (spacing) are assigned stochastically. These models are subsequently subjected to flow simulations, and the variability in production performance captures the sensitivity due to model parameter uncertainties. Our results highlight the non-uniqueness of fracture characterization in production data analysis. It is demonstrated that ignoring the uncertainty in history-matched parameters and assumptions associated with analytical models could potentially over- or under-estimate production by up to 30%. The analysis workflow adopted in this study presents a practical framework for integrating numerical simulations with analytical solutions to study the limitations of analytical transient flow models and to quantify the uncertainty in production performance predictions.

A Review of Non-saturated Resin Flow in Liquid Composite Moulding processes

The fundamentals of flow in the liquid composite moulding (LCM) processes are reviewed with an emphasis on multiphase flow effects considering the dual-scale thin porous media constituted by the textiles, and the dynamic wetting effects observed with viscous fluids. The main physical phenomena governing multiphase fluid flow in porous media are presented, using a continuum mechanics approach. Strategies towards solving these equations are then reviewed. Two main approaches are currently developed in the LCM literature. One is a direct solution of the multiphase flow equations, which requires dual knowledge of how permeability varies with saturation, and how saturation varies with pressure. The other is an indirect method based on solution of saturated flow with the introduction of sink terms, representing the dual scale of the fibrous reinforcements, which requires knowledge of the flow kinetics within the tows. Even though a complete and accurate tool to simulate multiphase LCM flow is still far from being available, several recent results have contributed to improving our physical understanding of LCM processes leading to process kinetics optimization and possibly porosity reduction in the final part.

Influence of relative permeability on injection pressure and plume configuration during CO2 injections in a mafic reservoir

Carbon capture and sequestration projects have traditionally targeted deep sedimentary basins; however, mafic reservoirs may also be attractive targets for CO2 disposal on the basis of permanent mineral trapping over relatively short time scales (101 to 102yr). Nevertheless, CCS development in mafic reservoirs is hampered by substantial uncertainty in fracture-controlled reservoir characteristics, particularly with respect to the effects of multi-phase fluid flow, e.g., relative permeability and capillary pressure. The present study quantifies uncertainty surrounding relative permeability effects in a basalt reservoir by developing a numerical modeling experiment on the basis of site characterization data from the Slack Canyon #2 flow top, which is one of three flow tops comprising the injection zone at the Wallula Basalt Sequestration Pilot Project in southeast Washington State. This numerical modeling experiment controls for the effects of curvature in the relative permeability models by performing an ensemble of 399 CO2 injection simulations with constant geometry and reservoir properties, while systematically varying the phase interference parameter (λ) and residual CO2 saturation (Sgr), which govern wetting and non-wetting phase relative permeability, respectively. The relative permeability parameter space is defined by selecting combinations of λ and Sgr that cover a wide range of experimental laboratory measurements. For each simulation, CO2 is injected into the reservoir for 10 years at a constant rate of 2.78kgs−1 (87,856metrictons(MT)yr−1), which is 10% of the annual injection rate proposed for one injection scenario at the Wallula Site. Results from the ensemble of simulations show that relative permeability alone can account for >50MPa of variability in the injection pressure and a two-fold difference in lateral CO2 plume migration. Additionally, this work shows that curvature in the wetting phase relative permeability model is the stronger influence on reservoir pressure accumulation, while curvature in the non-wetting phase relative permeability model strongly governs CO2 plume geometry.