Conventional Reservoir Simulation Research Articles

Modeling Dynamic Behaviors of Complex Fractures in Conventional Reservoir Simulators

Summary Field data have shown the decline of fracture conductivity during reservoir depletion. In addition, refracturing and infill drilling have recently gained much attention as efficient methods to enhance recovery in shale reservoirs. However, current approaches present difficulties in efficiently and accurately simulating such processes, especially for large-scale cases with complex hydraulic and natural fractures. In this study, a general numerical method compatible with existing simulators is developed to model dynamic behaviors of complex fractures. The method is an extension of an embedded discrete-fracture model (EDFM). With a new set of EDFM formulations, the nonneighboring connections (NNCs) in the EDFM are treated as regular connections in traditional simulators, and the NNC transmissibility factors are linked with gridblock permeabilities. Hence, manipulating block permeabilities in simulators can conveniently control the fluid flow through fractures. Complex dynamic behaviors of hydraulic fractures and natural fractures can be investigated using this method. The proposed methodology is implemented in a commercial reservoir simulator in a nonintrusive manner. We first present one synthetic case study in a shale-oil reservoir to verify the model accuracy and then combine the new model with field data to demonstrate its field applicability. Subsequently, four field-scale case studies with complex fractures in two and three dimensions are presented to illustrate the applicability of the method. These studies involve vertical- and horizontal-well refracturing in tight reservoirs, infill drilling, and fracture activation in a naturally fractured reservoir. The proposed approach is combined with empirical correlations and geomechanical criteria to model stress-dependent fracture conductivity and natural-fracture activation. It also shows convenience in dynamically adding new fractures or extending existing fractures during simulation. Results of these studies further confirm the significance of dynamic fracture behaviors and fracture complexity in the analysis and optimization of well performance.

Estimating local capillary trap volume capacities using a geologic criterion

Capillary pressure heterogeneity causes local capillary trapping of CO2 in saline aquifers. However, quantifying local capillary trapping using conventional reservoir simulation is computationally intensive. This work employs a geologic criterion (GC) to rapidly estimate the volume capacity of local capillary traps in static geologic models. The criterion refers to the ‘critical capillary entry pressure’ that is used to indicate flow barriers and flow paths during buoyant flow. A previous study (Saadatpoor, 2012) found that issues exist in the criterion method: unknown physical critical capillary entry pressures and boundary barriers. This work addresses the two issues. It is shown that the criterion method gives a close upper bound estimation of local capillary trap volume capacities. Several fine-scale geostatistical realizations of capillary entry pressure fields are considered, and the effects of reservoir heterogeneity, system sizes, aspect ratios, and boundary types are examined. The results from the GC are also strictly interpreted through invoking a simple counting argument. The overall work enhances our mechanistic understanding of the geological controls of local capillary traps.

Simulation of tight fluid flow with the consideration of capillarity and stress-change effect

The horizontal wells and multi-stage hydraulic fracturing technologies play a significantly important role in developing unconventional reservoirs. Due to the nanopore effects and stress deformation in tight formations, the fluid equilibrium and thermodynamics become more complex and the conventional reservoir simulation models cannot accurately handle these mechanisms. Hence, the objective of this work is to propose a comprehensive simulation model considering the effects of confined space and stress-dependent deformation. We first evaluated the phase envelope and fluid properties in the confined nanopores. Results show that bubble-point pressure and oil viscosity decrease, while formation volume factor and gas-oil ratio increase. The heavy components cause large deviation on the P-T phase envelope at the reservoir condition. Subsequently, a reservoir simulation model of the Bakken tight oil reservoir was built including the effect of stress-dependent deformation. The proposed phase behavior model was applied into the reservoir simulator to predict the hydrocarbon production from the Bakken tight oil reservoir. Finally, the role of the confined space and the stress-dependent deformation on the production are examined in detail. This novel simulation approach can shed light on the better understanding of the key parameters affecting well production of in developing tight oil reservoirs in the future.

Multiresolution coupled vertical equilibrium model for fast flexible simulation of CO2 storage

CO2 capture and storage is an important technology for mitigating climate change. Design of efficient strategies for safe, long-term storage requires the capability to efficiently simulate processes taking place on very different temporal and spatial scales. The physical laws describing CO2 storage are the same as for hydrocarbon recovery, but the characteristic spatial and temporal scales are quite different. Petroleum reservoirs seldom extend more than tens of kilometers and have operational horizons spanning decades. Injected CO2 needs to be safely contained for hundreds or thousands of years, during which it can migrate hundreds or thousands of kilometers. Because of the vast scales involved, conventional 3D reservoir simulation quickly becomes computationally unfeasible. Large density difference between injected CO2 and resident brine means that vertical segregation will take place relatively quickly, and depth-integrated models assuming vertical equilibrium (VE) often represent a better strategy to simulate long-term migration of CO2 in large-scale aquifer systems. VE models have primarily been formulated for relatively simple rock formations and have not been coupled to 3D simulation in a uniform way. In particular, known VE simulations have not been applied to models of realistic geology in which many flow compartments may exist in-between impermeable layers. In this paper, we generalize the concept of VE models, formulated in terms of well-proven reservoir simulation technology, to complex aquifer systems with multiple layers and regions. We also introduce novel formulations for multi-layered VE models by use of both direct spill and diffuse leakage between individual layers. This new layered 3D model is then coupled to a state-of-the-art, 3D black-oil type model. The formulation of the full model is simple and exploits the fact that both models can be written in terms of generalized multiphase flow equations with particular choices of the relative permeabilities and capillary pressure functions. The resulting simulation framework is very versatile and can be used to simulate CO2 storage for any combination of 3D and VE-descriptions, thereby enabling the governing equations to be tailored to the local structure. We demonstrate the simplicity of the model formulation by extending the standard flow-solvers from the open-source Matlab Reservoir Simulation Toolbox (MRST), allowing immediate access to upscaling tools, complex well modeling, and visualization features. We demonstrate this capability on both conceptual and industry-grade models from a proposed storage formation in the North Sea. The current implementation assumes a sharp interface for the VE model, where the capillary forces do not lead to a capillary fringe. While the examples are taken specifically from CO2 storage applications, the framework itself is general and can be applied to many problems in which parts of the domain are dominated by gravity segregation. Such applications include gas storage and hydrocarbon recovery from gas reservoirs with local layering structure.

Stochastic porous media modeling and high-resolution schemes for numerical simulation of subsurface immiscible fluid flow transport

This paper proposes stochastic petroleum porous media modeling for immiscible fluid flow simulation using Dykstra–Parson coefficient (VDP) and autocorrelation lengths to generate 2D stochastic permeability values which were also used to generate porosity fields through a linear interpolation technique based on Carman–Kozeny equation. The proposed method of permeability field generation in this study was compared to turning bands method (TBM) and uniform sampling randomization method (USRM). On the other hand, many studies have also reported that, upstream mobility weighting schemes, commonly used in conventional numerical reservoir simulators do not accurately capture immiscible displacement shocks and discontinuities through stochastically generated porous media. This can be attributed to high level of numerical smearing in first-order schemes, oftentimes misinterpreted as subsurface geological features. Therefore, this work employs high-resolution schemes of SUPERBEE flux limiter, weighted essentially non-oscillatory scheme (WENO), and monotone upstream-centered schemes for conservation laws (MUSCL) to accurately capture immiscible fluid flow transport in stochastic porous media. The high-order schemes results match well with Buckley Leverett (BL) analytical solution without any non-oscillatory solutions. The governing fluid flow equations were solved numerically using simultaneous solution (SS) technique, sequential solution (SEQ) technique and iterative implicit pressure and explicit saturation (IMPES) technique which produce acceptable numerical stability and convergence rate. A comparative and numerical examples study of flow transport through the proposed method, TBM and USRM permeability fields revealed detailed subsurface instabilities with their corresponding ultimate recovery factors. Also, the impact of autocorrelation lengths on immiscible fluid flow transport were analyzed and quantified. A finite number of lines used in the TBM resulted into visual artifact banding phenomenon unlike the proposed method and USRM. In all, the proposed permeability and porosity fields generation coupled with the numerical simulator developed will aid in developing efficient mobility control schemes to improve on poor volumetric sweep efficiency in porous media.

Near-wellbore modeling of a horizontal well with Computational Fluid Dynamics

The oil production by horizontal wells is a complex phenomenon that involves flow through the porous reservoir, completion interface and the well itself. Conventional reservoir simulators can hardly resolve the flow through the completion into the wellbore. On the contrary, Computational Fluid Dynamics (CFD) is capable of modeling the complex interaction between the creeping reservoir flow and turbulent well flow for single phases, while capturing both the completion geometry and formation damage. A series of single phase steady-state simulations are undertaken, using such fully coupled three dimensional numerical models, to predict the inflow to the well. The present study considers the applicability of CFD for near-wellbore modeling through benchmark cases with available analytical solutions. Moreover, single phase steady-state numerical investigations are performed on a specific perforated horizontal well producing from the Siri field, offshore Denmark. The performance of the well is investigated with an emphasis on the inflow profile and the productivity index for different formation damage scenarios. A considerable redistribution of the inflow profile were found when the filtrate invasion extended beyond the tip of the perforations.

An examination of the concept of apparent skin factor in modeling injectivity of non-Newtonian polymer solutions

In a conventional reservoir simulation, analytical well models relate well block pressure, wellbore pressure, fluid mobility, and geometric factors such as wellbore radius and grid size. Basically, fluid viscosity is assumed to be Newtonian in these models. Commercial reservoir simulators using these well models often predict unrealistic well injectivity in simulation of processes involving non-Newtonian fluids such as polymer solutions. Apparent viscosity of a polymer solution is a complicated function of flow velocity, polymer properties, permeability, porosity, salinity, etc. As the distance away from an injection well increases, flow velocity decreases; meanwhile, the apparent polymer viscosity changes drastically. For shear-thinning polymers, the average flow velocity in a well block is several orders of magnitude smaller than the flow velocity near the wellbore, especially when grid size is large. Using the average flow velocity for apparent viscosity calculation leads to an underestimate of well injectivity. Thus it is crucial to consider non-Newtonian effects in simulation of injectivity of polymer solutions.UTCHEM, a general purpose chemical flooding simulator developed at the University of Texas, uses a semi-analytical polymer injectivity model based on an extension of Peaceman's well model to non-Newtonian fluids. This model corrects the apparent viscosity in well index calculation and gives a more realistic estimate of polymer injectivity. However, the model needs to be programmed and implemented in a code. It is not practical for users of commercial simulators which do not have semi-analytical polymer injectivity model. Compared with UTCHEM, CMG-STARS, the thermal and advanced processes reservoir simulator developed by Computer Modeling Group, uses an apparent skin factor to account for non-Newtonian effects of power law fluids. The apparent skin factor can be used as an input parameter to the simulator.In this study, we revisited the analytical polymer injectivity model and proposed a general form for the calculation of apparent skin factor. The apparent skin factor is estimated using polymer rheological properties, grid size, wellbore radius, etc., and can apply to any polymer rheology. Simulation studies of polymer flooding cases were conducted to verify the concept of apparent skin factor. The results show that for shear-thinning polymers, the apparent skin factor can be estimated properly and correct the analytical well model to give close predictions compared to the semi-analytical polymer injectivity model and fine-grid simulation. The concept of apparent skin factor was proved to be useful for improving the accuracy of well injectivity calculations by commercial simulators. However, it is also worth pointing out that the apparent skin factor cannot be used for polymers which show shear-thickening behavior at high shear rates for cases of heterogeneous reservoir.

Simulation of CO2 Migration for the Planning of Well Test Configurations at the South West Hub Project, Western Australia

Containment of injected CO2 at the South West Hub project in Western Australia is dependent on non-structural trapping mechanisms in the 1500 m thick Wonnerup Member of the Lesueur Sandstone due to uncertainties regarding the sealing character of the ∼600 m thick overlying Yalgorup Member. Therefore, vertical migration distance and sweep efficiency and their impact on residual saturation and CO2 dissolution need to be properly assessed through reservoir simulations. We find that conventional Darcy-flow reservoir simulations result in significantly different predictions of plume migration compared to invasion percolation modelling when injecting at the base of the Wonnerup Member. If numerical predictions of the fate of injected CO2 are sensitive to the choice of model, care must be taken when selecting the methodology. One way to validate simulation predictions at a scale appropriate to the modelling is the use of well tests. In the Wonnerup Member a vertical migration test is recommended for consideration to confirm whether conventional reservoir simulations or percolation invasion modelling accurately predict the CO2 migration processes at the site. This test would involve a small injection of CO2 that is allowed to migrate upwards. The migration would be monitored with repeat pulsed neutron logging. This represents a new kind of test unique to the situation for the South West Hub site.

Stability analysis for multicomponent mixtures including capillary pressure

Despite the large potential of unconventional resources, many unknowns still exist regarding the physics controlling the extraction processes in these settings. These include accurate representation of phase equilibrium in tight formations and effective implementation of relevant models in simulation tools.When a fluid is confined in pore spaces of nanometer size, significant interfacial curvatures may occur that can result in large capillary pressures between the liquid and vapor phases: The pressure difference between the two phases will likely affect the vapor-liquid equilibrium state. Previous efforts have shown that this effect is negligible for conventional reservoirs (with pores in the micron range) and current commercial reservoir simulators commonly ignore the effect of capillary pressure in the VLE calculations. However, experimental and modeling efforts have shown that ignoring capillary pressure in the VLE calculations will not be a valid approximation for unconventional (tight) reservoirs.In this work, we analyze the numerical aspects of including capillarity phenomena in VLE calculations in an effort to arrive at robust and efficient algorithms for stability analysis that can be used in compositional modeling/simulation of unconventional reservoirs. While the equality of chemical potentials is a necessary condition for equilibrium, it is not a sufficient one. A sufficient condition for equilibrium is the minimization of Gibbs energy, and the latter can be tested using the tangent plane distance (TPD) criteria. We show that stability analysis based on the TPD criteria remains valid for systems with large capillary pressures and propose effective/robust algorithms for stability testing. The proposed algorithms are tested for multicomponent reservoir fluid systems over a range of relevant temperatures, pressures and pore radii.

Numerical simulation of two-phase flow in fractured porous media using streamline simulation and IMPES methods and comparing results with a commercial software

Streamline simulation is developed to simulate waterflooding in fractured reservoirs. Conventional reservoir simulation methods for fluid flow simulation in large and complex reservoirs are very costly and time consuming. In streamline method, transport equations are solved on one-dimensional streamlines to reduce the computation time with less memory for simulation. First, pressure equation is solved on an Eulerian grid and streamlines are traced. Defining the “time of flight”, saturation equations are mapped and solved on streamlines. Finally, the results are mapped back on Eulerian grid and the process is repeated until the simulation end time. The waterflooding process is considered in a fractured reservoir using the dual porosity model. Afterwards, a computational code is developed to solve the same problem by the IMPES method and the results of streamline simulation are compared to those of the IMPES and a commercial software. Finally, the accuracy and efficiency of streamline simulator for simulation of two-phase flow in fractured reservoirs has been proved.

Coupled solid and fluid mechanics simulation for estimating optimum injection pressure during reservoir CO2-EOR

Reservoir geomechanics can play an important role in hydrocarbon recovery mechanism. In CO2-EOR process, reservoir geomechanics analysis is concerned with the simultaneous study of fluid flow and the mechanical response of the reservoir under CO2 injection. Accurate prediction of geomechanical effects during CO2 injection will assist in modeling the Carbon dioxide recovery process and making a better design of process and production equipment. This paper deals with the implementation of a program (FORTRAN 90 interface code), which was developed to couple conventional reservoir (ECLIPSE) and geomechanical (ABAQUS) simulators, using a partial coupling algorithm. A geomechanics reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case. The reservoir geomechanics coupled models show that in the case of lower maximum bottom hole injection pressure, the cumulative oil production is more than other scenarios. Moreover at the high injection pressures, the production rates will not change with the injection bottom hole pressure variations. Also the FEM analysis of the reservoir showed that at CO2 injection pressure of 11000 Psi the plastic strain has been occurred in the some parts of the reservoir and the related stress path show a critical behavior.

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.

Optimizing Carbon Sequestration With the Capacitance/Resistance Model

Summary Carbon dioxide (CO2) storage in deep brine-filled structures accompanied by brine extraction has several more advantages than conventional injection-only storage schemes, but avoiding CO2 arrival at extraction wells becomes a paramount concern. The use of conventional reservoir simulators to optimize CO2 injection/brine extraction requires a model of the petrophysical properties of the storage formation. Unfortunately, those properties are unlikely to be adequately characterized in storage reservoirs, especially at the outset of a project. An attractive alternative tool to manage injection/extraction storage processes is the capacitance/resistance model (CRM), which only requires the wells' injection/extraction histories as input. A useful characteristic of CRM for this application is that it identifies the connectivities between injectors and extractors. We show the effectiveness of the method on a homogeneous aquifer with variable injection rates. We describe a work flow that optimizes subsequent CO2 storage in the aquifer with the CRM parameters obtained from the injection/extraction history. A reasonable estimate of CRM parameters requires a sufficient length of injection/extraction history. We present further a dynamic work flow that allows updating the history and the optimal control strategy. The applications on the example storage aquifers show significant improvements in the amount of CO2 stored by injection/extraction strategies.

Identifying sweet spots and moving CBM reservoirs into production

C oalbed methane (CBM) is well recognised as an important natural gas resource. However, producing it commercially has proven to be a challenging process, primarily due to the complex nature of its gas storage and flow mechanisms. Although CBM reservoirs are naturally fractured due to the presence of face and butt cleats, gas stor­age and saturation depend on the adsorption capacity of the coal matrix. The ability to predict permeability variations and its evolu­tion in a CBM reservoir, which is affected by several dynamic CBM properties and operating conditions, also define the design, optimization, and analysis of the gas recovery process. As the permeability is naturally low, interventions are necessary in order to achieve commercially viable gas production rates. CBM are also dual-porosity media where the vast majority of the gas is stored in the low permeability coal matrix by sorp­tion. The flow to production wells, however, occurs through the coal’s natural fracture system, that stores relatively small amounts of gas, because coal matrix practically has no perme­ability. The result is that properties of the coal matrix have the greatest effect on the estimates of gas in place and recovery. It is well understood that the key parameter controlling gas flow in CBM reservoirs are cleat networks, gas storage, desorp­tion and permeability anisotropy (coal shrinkage and swelling). While the role of reservoir simulation is well under­stood for conventional oil and gas reservoirs and its related techniques for prediction and production optimisation, for unconventional reservoirs (CBM, Shale, etc.) current reservoir simulation software needs to be further developed and adapted to represent the performance of these types of fields and gener­ate more acceptable results. For example, the basic governing fluid flow regime in conventional reservoir simulations is limited to Darcy flow. For unconventional reservoirs, however, another flow regime term comes into the equation that reflects the flow of gas in the coal matrix and stands for diffusion. This new flow regime is not very well defined in the current simulators and needs further studies to appropriately address the production performance of a reservoir. Furthermore, the concept of multi-phase flow in reservoirs is well defined by the introduction of relative permeability equations in the flow equations. However, measuring relative permeability in coal is relatively complex (Ham and Kantas, 2008) due to its friability, heterogeneity, stress dependence and porous morphology. Young et al. (1992), for example, noticed that the derived relative permeability from a history match does not resemble the laboratory measurement. This phenomenon could be due to the change of matrix structure on phase flow in addition to wettability and capil­larity. In other words, both phases may flow through different passages over time due to heterogeneity. Thus dynamic rela­tive permeability (phase saturation) is required to accurately predict recovery from a CBM reservoir. As the focus on CBM has increased in the past decades, so has the quest for more effective technologies to help bring the reserves in such complicated conditions into production and to identify sweet spots. Reservoir modelling and reservoir simulation are technologies that are likely to play a key role in achieving this. Firstly, however, it is necessary to look at the challenges of CBM property variations.

On the uncertainty of interwell connectivity estimations from the capacitance-resistance model

The capacitance-resistance model (CRM) is an alternative to conventional reservoir simulation. CRM, a simplification of complex numerical models, uses production and injection rates to infer a reservoir description. There is no prior geologic model. The principal output of CRM fitting is the fraction of injected fluid (usually water) that is produced at a producer at steady-state. These fractions are interwell connectivities. Interwell connectivities are fundamental information needed to manage waterfloods in oil reservoirs. The data-driven CRM is a fast tool to estimate these parameters in mature fields and allows one to make full use of the dynamic data available. This paper considers the problem of setting an upper bound on the uncertainty of interwell connectivities for linear-constrained models. Using analytical bounds and numerical simulations, we derive a consistent upper limit on the uncertainty of interwell connections that can be used to quantify the information content of a given dataset.

Application of Integrating Seismic Attribute with Simulation in Volcanic Rock Reservoir

The conventional reservoir simulation is only reasonably consistent with history matching. An application will be presented in this paper by integrating seismic data and production data to achieve history matching. It is hard to accurately describe the reservoir and fracture modeling due to lack of fracture logging data in volcanic rock reservoir area of Bin 3. The study found that it has a close relationship between the distribution characteristics of volcanic rock and seismic attributes.The high-value region of coherence cube attribute usually correspond to tight basalts, so it is very like a fracture broken zone. With denser lithology and higher impedance value, the high-angle fractures will be better abundant. Great deals of intensive fracture and comprehensive effect have been simulated through volcanic rock reservoir simulation restricted by seismic data. By improving history matching, the approach also deepens the possible distribution pattern of fracture-developed zone in 3D space. On the basis of that, stable and high production wells have been designed and put forward.

A Two-Level Strategy to Realize Life-Cycle Production Optimization in an Operational Setting

Summary We present a two-level strategy to improve robustness against uncertainty and model errors in life-cycle flooding optimization. At the upper level, a physics-based large-scale reservoir model is used to determine optimal life-cycle injection and production profiles. At the lower level, these profiles are considered as set points (reference values) for a tracking control algorithm, also known as a model predictive controller (MPC), to optimize the production variables over a short moving horizon on the basis of a simple data-driven model. In the process industry such a two-level approach is a well-known strategy to correct for small local disturbances that may have a negative (cumulative) effect on the long-term production strategy. We used a conventional reservoir simulator with gradient-based optimization functionality to perform the life-cycle optimization. Next, we applied this long-term strategy to a reservoir model, representing the truth, with somewhat different geological characteristics and near-wellbore characteristics not captured in the reservoir model used for the longterm optimization. We compared the performance (oil recovery) of this truth model when applying the life-cycle strategy with and without the corrections provided by the data-driven algorithm and the tracking controller. In this theoretical study we observed that the use of the lower-level controller enabled successful tracking of the reference values provided by the upper-level optimizer. In our example, a performance drop of 6.4% in net present value (NPV), caused by differences between the reservoir model used for life-cycle optimization and the true reservoir, was successfully reduced to only 0.5% when applying the two-level strategy. Several studies have demonstrated that model-based life-cycle production optimization has a large scope to improve long-term economic performance of waterflooding projects. However, because of uncertainties in geology, economics, and operational decisions, such life-cycle strategies cannot simply be applied in reality. Our two-level approach offers a potential solution to realize life-cycle optimization in an operational setting.

Modeling of sulfur plugging in a sour gas reservoir

In order to scientifically and accurately predict the damage of sulfur deposition in a sour gas reservoir. Glomeration mechanism of precipitated sulfur in pores was analyzed, based on conventional black-oil reservoir simulator, given the effect of sulfur deposition and irreducible water, a reservoir damage model is established in the presence of non-Darcy flow, the model can be used to describe the change of pressure with deposited sulfur. The results show that when reservoir pressure is lower than critical pressure, higher saturation degree of irreducible water may lead to pressure drop more quickly and velocity of sulfur precipitation becomes faster, gas limited production time becomes shorter when non-Darcy flow is considered.

Optimizing CO2 Storage in a Deep Saline Aquifer with the Capacitance-resistance Model

CO2 storage in deep brine-filled structures accompanied by brine extraction has several advantages over conventional large-scale storage schemes. Using conventional reservoir simulators to optimize CO2 injection/brine extraction requires a model of the petrophysical properties of the storage formation. When those properties are poorly characterized, a useful alternative tool is the Capacitance-injection/extraction histories as input. One important characteristic of CRM is that it identifies the connectivities between injectors and extractors. We show the effectiveness of the method on a homogeneous aquifer with variable injection rates. We further describe a workflow that optimizes subsequent CO2 storage in the aquifer using the CRM model parameters obtained from the injection/extraction history. The approach is illustrated on a heterogeneous storage aquifer and the results show a significant improvement in the amount of CO2 stored in the aquifer.

CFD-based representation of non-Newtonian polymer injectivity for a horizontal well with coupled formation-wellbore hydraulics

Polymers are often injected into horizontal wells during enhanced oil recovery (EOR) processes. During injection of these high-viscosity, non-Newtonian polymers, a significant pressure drop may occur along the length of the well. Accurate models for pressure drop in the well and polymer leakage into the reservoir are necessary for simulation but presently do not exist. We developed new, approximate models for pressure in horizontal wells based on Computational Fluid Dynamics (CFD) modeling of coupled well/reservoir flow. Here, the polymer is shear-thinning in the wellbore and may exhibit viscoelastic effects (such as shear-thickening behavior) in the surrounding reservoir. The CFD results are used to improve existing analytical models for simple, Newtonian flows. The closed-form model accounts for fluid, well, and reservoir properties and can easily be implemented into conventional reservoir simulators. The CFD-based model was directly implemented into the reservoir simulator UTCHEM to evaluate the effect of pressure loss in the well on sweep efficiency. Early times (less than 100 days) yielded a significant loss in oil recovery when compared to the uniform-pressure assumption for the well. However, at later times the recovery loss was negligible, suggesting a uniform-pressure well may be a reasonable assumption at these time scales, even for highly-viscous polymer fluids.