Oil Reservoir Simulation Research Articles

An OpenMP parallel implementation using a coprocessor for numerical simulation of oil reservoirs

The objective of this work is to parallelize, using the Application Programming Interface (API) OpenMP (Open Multi-Processing) and Intel Xeon Phi coprocessor based on Intel Many Integrated Core (MIC) architecture, the numerical method used to solve the algebraic system resulting from the discretization of the differential partial equation (PDE) that describes the single-phase flow in an oil reservoir. The set of governing equations are the continuity equation and the Darcy’s law. The Hydraulic Diffusivity Equation (HDE), for the unknown pressure, is obtained from these fundamental equations and it is discretized by means of the Finite Difference Method (FDM) along with a time implicit formulation. Different numerical tests were performed to study the computational efficiency of the parallelized versions of Conjugate Gradient, BiConjugate Gradient and BiConjugate Gradient Stabilized methods. Speedup results were considered to evaluate the performance of the parallel algorithms for the horizontal well simulation case. The methodology also included a sensibility analysis for different production scenarios including variations on the permeability, formation-value-factor, well length and production rate.

Study of Single Phase Mass Transfer between Matrix and Fracture in Tight Oil Reservoirs

In tight fractured reservoirs, oil in matrices is mainly explored due to mass transfer mechanisms during the pressure depletion process. In the modeling of mass transfer in fractured reservoirs using the dual porosity concept, the shape factor is the most important parameter and should be described accurately. However, the current shape factors are not suited for tight oil reservoir simulation because the characteristics of tight oil reservoirs are not taken into account. In order to solve this problem, a new mass transfer function for tight fractured oil reservoirs is proposed by introducing a new time-related correction factor which could consider not only the existence of the boundary layer in nano-microscale throats in tight porous media but also the heterogeneous pressure distribution in matrix blocks. In addition, special contact relations between matrix and fracture are included. The correction factor presented in this study is verified using the experimental data and numerical simulation results. Data analysis results demonstrate that the lower and slower the pressure propagation velocity, the longer the duration time of unsteady flow compared to conventional reservoirs. Therefore, in the calculation of mass transfer flow in tight oil reservoirs, the unsteady flow between fracture and matrix cannot be ignored.

Numerical Simulation of the Impact of Natural Fracture on Fluid Composition Variation Through a Porous Medium

In order to lessen the computational time in fractured oil reservoir simulations, all fractures are usually assumed to be as one equivalent fracture at the center or around the model. This, specially, has applications in industrial engineering software, where this assumption applies. In this study, using two general contradictory examples, it is shown that ignoring a fracture network and assuming an equivalent single-fracture has no logical justification and results in a considerable error. The effect of fracture aperture on composition distribution of a binary and a ternary mixture was also investigated. These mixtures were C1 (methane)/n-C4 (normal-butane) and C1 (methane)/C2 (ethane)/n-C4 (normal-butane), which were under diffusion and natural convection. Governing equations were numerically solved using matlab. One of the main relevant applications of this study is where permeability and temperature gradient are the key difference between reservoirs. Compositional distribution from this study could be used to estimate initial oil in place. Using this study, one can find the optimum permeability, namely the permeability at which the maximum species separation happens, and the threshold permeability (or fracture aperture), after which the convection imposes its effect on composition distribution. It is found that the threshold permeability is not constant from reservoir to reservoir. Also, one can find that full mixing happens in the model, namely heavy and light densities of top and bottom mix up together in the model. Furthermore, after maximum separation point, convection causes unification of components.

Coupled Capillary-Pressure and Three-Phase Flash Models Simulate Liquid Blockage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190242, “Simulation of Water and Condensate Blockage and Solvent Treatments in Tight Formations Using Coupled Three-Phase Flash and Capillary-Pressure Models,” by Sajjad S. Neshat, SPE, Ryosuke Okuno, SPE, and Gary A. Pope, SPE, The University of Texas at Austin, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Water and condensate blockage near production wells in unconventional reservoirs can reduce oil- and gas-production rates significantly. This paper presents a new approach for more-accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. Introduction In this paper, coupled three-phase flash and capillary-pressure models are presented for simulation of tight oil and gas reservoirs. The capillary pressure between each phase pair (e.g., oil/gas or oil/aqueous) is calculated with a general three-phase capillary-pressure model that integrates the effect of important petrophysical properties including pore-size distribution, phase saturations, and different wettability conditions. The capillary-pressure function is integrated with three-phase flash calculations to define the equilibrium state between oil, gas, and aqueous phases under reservoir conditions. The criterion for selection of cubic equation-of-state (EOS) roots is extended for three-phase mixtures. This method minimizes the global Gibbs free energy (GFE) of the whole mixture instead of minimizing the free energy of each phase separately. The models are then used for simulation of primary production and solvent enhanced-oil-recovery (EOR) processes in tight formations. Using rock and fluid properties for tight oil and gas reservoirs, the effect of water and condensate blockage and capillary pressure on production is simulated. The use of solvents to remove liquid blockage and to increase production rates is extended to tight formations with high capillary pressure. Coupled Three-Phase Flash and Capillary-Pressure Models At three-phase equilibrium conditions, the chemical potential of each component must be equal in all three phases. In the presence of capillary pressure, the chemical potentials are calculated at corresponding phase pressures. Capillary pressure across a two-phase interface is a function of the surface curvature and interfacial tension (IFT). The variation in pore size and interfacial curvature can be accounted for by saturation-dependent functions. In the presence of a third phase, the interface between any two phase pairs would shift toward either larger or smaller pores depending on wettability conditions. A general three-phase model that can be used to define the capillary pressure between any phase pairs under the entire range of wettability conditions has been coupled with a three-phase relative permeability model with three-phase hysteresis and compositional consistency and was validated through measured three-phase relative permeability data. For the applications discussed in this study, it is assumed that the gas phase is always the most nonwetting phase, while a mixed wetting condition for oil and aqueous phases is assumed.

Advances in Pore-Scale Simulation of Oil Reservoirs

At the high water cut stage, the residual oil in a reservoir becomes complex and dispersed. Moreover, it is challenging to achieve good predictions of the movement of oil and water in a reservoir according to the macroscopic models based on the statistic parameters of this scenario. However, pore-scale simulation technology based on directly tracking the interaction among different phases can make an accurate prediction of the fluid distribution in the pore space, which is highly important in the improvement of the recovery rate. In this work, pore-scale simulation methods, including the pore network model, lattice Boltzmann method, Navier–Stokes equation-based interface tracking methods, and smoothed particle hydrodynamics, and relevant technologies are summarized. The principles, advantages, and disadvantages, as well as the degree of difficulty in the implementation are analyzed and compared. Problems in the current simulation technologies, micro sub-models, and applications in physicochemical percolation are also discussed. Finally, potential developments and prospects in this field are summarized.

Numerical simulation of RF heating heavy oil reservoir based on the coupling between electromagnetic and temperature field

At present, a technology of RF (radio frequency) heating is being investigated for enhanced heavy oil recovery, but continued high temperature appears near wellbore, which may destroy the wellbore integrity and RF apparatus. This paper first introduces a novel RF apparatus composed of antenna arrays for heating the heavy oil reservoir, and then the temperature distribution is calculated based on the coupling between electromagnetic and temperature field. To alleviate the high temperature in the vicinity of wellbore, two solutions are proposed: (1) a sleeve made of PTFE (polytetrafluoroethylene) is applied to the outside of the RF apparatus; (2) for improving accuracy of temperature calculation, thermos-physical parameters of reservoir, which are depended on the temperature, are considered specifically in the heat transfer equation and wave equation. Finally, the effect of properties of reservoir and the relative permittivity of sleeve on temperature distribution are investigated. Calculation results indicate that relative permittivity of sleeve has a tremendous influence on temperature distribution, and maximum temperature declines nearby the wellbore as the diminution of relative permittivity, moreover, the positions with highest temperature are moving far from the wellbore. When the parameters of specific heat and thermal conductivity are variable, the maximum temperature near the wellbore is lower than the temperature calculated by constant parameters. Variable relative permittivity of water can’t decrease the temperature around the wellbore.

Modern system of multiphase flow in porous media and its development trend

Fluid flow in porous media is the key scientific problem in the development of oil and gas reservoirs. The traditional mechanics of fluid flow in porous media which based on the continuum hypothesis and Darcy′s law plays an important role in developing conventional oil and gas resources. In recent years, unconventional reservoirs are drawing more and more attention all over the world, therefore the development theory and technology, especially the corresponding flow mechanisms have become the hot research issues. The unconventional reservoirs exhibit distinct multiscale characteristics, even with six orders of magnitude difference. In addition, the application of massive multi-stage hydraulic fracturing can induce strong stress interactions. Therefore, the traditional theory of fluid flow in porous media cannot accurately describe the flow characteristics in unconventional reservoirs. In essence, the development of unconventional oil and gas resources involves multiphase fluids (e.g. oil, water and gas) flow in multi-scale porous media with multi-field coupling and various flow patterns. Therefore, the concept of modern system of multiphase flow in porous media is proposed, which means multiphase fluids flowing in multi-scale porous media with multi-field coupling and various flow patterns. The research status and development tendency are reviewed from the aspects of: (1) micro- and nanoscale oil and gas flow simulation; (2) upscaling for reservoir simulation, (3) macroscale flow simulation of unconventional oil and gas reservoirs; (4) simulation of flow in large scale fractured and vuggy carbonate reservoirs and (5) physical simulation of hydrocarbon transport in porous media. More specifically, in nanoscale the density functional theory and molecular simulation method can be used to study the interfacial phenomena to understand the hydrocarbon transport behavior in nanopores and provide key parameters for mesoscale flow simulation. The current study of nanoscale simulation mainly focuses on developing more realistic molecular structure model to represent the heterogeneous shale samples. Microscale simulation methods involve pore network model, lattice Boltzmann method, direct simulation of Navies-Stokes equation, level-set method and smoothed particle hydrodynamics, etc. Digital core and pore network model are the fundamental research platforms. Various methods can be used to reconstruct digital cores with multiscale pore structures and mineral compositions. The complex physicochemical phenomena namely adsorption/desorption, wettability change and boundary effect should be considered in the microscale flow simulations and extensive works have been done in microscale gas flow simulations. The future work on microscale simulation should focus on the multiphase flow mechanisms with multi-field coupling. The multiscale characteristics of unconventional reservoirs indicate the necessity of upscaling process to introduce the microscale flow mechanisms to macroscale. Homogenization theory and volume averaging method are the main upscaling approaches. Current upscaling methods are mostly based on the periodic boundary condition and are unreliable to be used in complex oil and gas reservoirs, which needs further study. In addition, more research needs to be conducted on the upscaling from molecular scale to mesoscale. In macroscale simulations of unconventional oil and gas reservoirs, the fluid-structure interaction should be considered and high efficiency numerical algorithm needs to be established. For large scale fractured and vuggy carbonate reservoirs, the non-Darcy flow characteristics and different flow regimes in vugs and fractures should be taken into account during flow simulation. Physical simulations of hydrocarbon transport in porous media are conducted at two scales: macroscale, nano- and microscale. Macroscale physical simulations aim at monitoring the dynamic saturation and pressure fields change under the realistic reservoir conditions. Nano- and microscale physical simulations are mainly applied to study the fluid transport mechanisms in single pore or throat. In summary, the proposed theory of multiphase fluids flowing in multi-scale porous media with multi-field coupling and various flow patterns can be applied to study the fluid flow problems in unconventional oil and gas industries.

ICM releases new details about showcase biorefinery

Coal bed methane (CBM) has received increasing attentions as a significant energy resource. Numerical modeling of the CBM recovery processes entails simulation of the complex coupled mechanisms, including desorption of methane from the coal matrix surface, diffusion of gas to coal cleats, and gas flow from coal cleats to the wellbore. Beyond these complex flowing mechanisms, it is crucially important to represent coal cleats, structural fractures, and/or hydraulic fractures realistically in CBM simulators as they provide flow channels and dominate CBM flow behaviors. Existing CBM simulators are typically extended from oil and gas reservoir simulators with either black-oil or compositional formulation, and sorption and desorption are usually modeled by the Langmuir isotherms. The concept of shape factor is commonly used to characterize the flow between matrix and cleats (or fractures). When the shape factor is treated as only a function of cleat spacing, the detailed characteristics of actual cleats (or fractures) are missing, including the spatial distribution of cleats and interconnectivity of cleats. In this study, we propose a new workflow to perform a 2-D coal bed methane recovery simulation with discrete fracture model (DFM) in consideration of both structural fractures (large-scale fractures) and cleats (small-scale fractures). There are two key steps in our approach. First, we use a detailed network of discrete fractures characterized from core samples to represent the actual distribution of identified cleats, and calculate the shape factor of the realistic cleated coal sample by running a flow simulation to pseudo-steady state. Second, we apply the shape factor to field-scale simulations in which large-scale fractures are modeled as DFM. For this purpose, we treat gas sorption and desorption as a “chemical reaction”, and we developed an extension to an existing geochemical-reservoir simulator. We implemented both a “pseudo-compositional” and a “full-compositional” module to study the effect of mass exchange between gas and aqueous phases. We validated our new formulation and simulator development from a benchmark case in which our simulation results show close agreement with commercial simulators. We also demonstrated the significance of modeling mass exchange between fluid phases on CBM recovery in some cases, which is commonly missing in most commercial simulators. Finally, we presented our workflow in modeling an enhanced CO2-ECBM recovery process to a complex fractured coal bed with both large-scale tectonic fractures and small-scale cleats.

SpMV and BiCG-Stab optimization for a class of hepta-diagonal-sparse matrices on GPU

The abundant data parallelism available in many-core GPUs has been a key interest to improve accuracy in scientific and engineering simulation. In many cases, most of the simulation time is spent in linear solver involving sparse matrix–vector multiply. In forward petroleum oil and gas reservoir simulation, the application of a stencil relationship to structured grid leads to a family of generalized hepta-diagonal solver matrices with some regularity and structural uniqueness. We present a customized storage scheme that takes advantage of generalized hepta-diagonal sparsity pattern and stencil regularity by optimizing both storage and matrix–vector computation. We also present an in-kernel optimization for implementing sparse matrix–vector multiply (SpMV) and biconjugate gradient stabilized (BiCG-Stab) solver. In-kernel is intended to avoid the multiple kernels invocation associated with the use of the numerical library operators. To keep in-kernel, a lock-free inter-block synchronization is used in which completing thread blocks are assigned some independent computations to avoid repeatedly polling the global memory. Other optimizations enable combining reductions and collective write operations to memory. The in-kernel optimization is particularly useful for the iterative structure of BiCG-Stab for preserving vector data locality and to avoid saving vector data back to memory and reloading on each kernel exit and re-entry. Evaluation uses generalized hepta-diagonal matrices that derives from a range of forward reservoir simulation’s structured grids. Results show the profitability of proposed generalized hepta-diagonal custom storage scheme over standard library storage like compressed sparse row, hybrid sparse, and diagonal formats. Using proposed optimizations, SpMV and BiCG-Stab have been noticeably accelerated compared to other implementations using multiple kernel exit–re-entry when the solver is implemented by invoking numerical library operators.

A New Non-Darcy Flow Model for Low-Velocity Multiphase Flow in Tight Reservoirs

The pore and pore-throat sizes of shale and tight rock formations are on the order of tens of nanometers. The fluid flow in such small pores is significantly affected by walls of pores and pore-throats. This boundary layer effect on fluid flow in tight rocks has been investigated through laboratory work on capillary tubes. It is observed that low permeability is associated with large boundary layer effect on fluid flow. The experimental results from a single capillary tube are extended to a bundle of tubes and finally to porous media of tight formations. A physics-based, non-Darcy low-velocity flow equation is derived to account for the boundary layer effect of tight reservoirs by adding a non-Darcy coefficient term. This non-Darcy equation describes the fluid flow more accurately for tight oil reservoir with low production rate and low pressure gradient. Both analytical and numerical solutions are obtained for the new non-Darcy flow model. First, a Buckley–Leverett-type analytical solution is derived with this non-Darcy flow equation. Then, a numerical model has been developed for implementing this non-Darcy flow model for accurate simulation of multidimensional porous and fractured tight oil reservoirs. Finally, the numerical studies on an actual field example in China demonstrate the non-negligible effect of boundary layer on fluid flow in tight formations.

Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs

Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]

Displacement mechanisms of air injection for IOR in low permeability light oil reservoirs

Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98°C to 180°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms. [Received: March 22, 2014; Accepted: February 7, 2016]

An improved multilevel Monte Carlo method for estimating probability distribution functions in stochastic oil reservoir simulations

AbstractIn this work, we develop an improved multilevel Monte Carlo (MLMC) method for estimating cumulative distribution functions (CDFs) of a quantity of interest, coming from numerical approximation of large‐scale stochastic subsurface simulations. Compared with Monte Carlo (MC) methods, that require a significantly large number of high‐fidelity model executions to achieve a prescribed accuracy when computing statistical expectations, MLMC methods were originally proposed to significantly reduce the computational cost with the use of multifidelity approximations. The improved performance of the MLMC methods depends strongly on the decay of the variance of the integrand as the level increases. However, the main challenge in estimating CDFs is that the integrand is a discontinuous indicator function whose variance decays slowly. To address this difficult task, we approximate the integrand using a smoothing function that accelerates the decay of the variance. In addition, we design a novel a posteriori optimization strategy to calibrate the smoothing function, so as to balance the computational gain and the approximation error. The combined proposed techniques are integrated into a very general and practical algorithm that can be applied to a wide range of subsurface problems for high‐dimensional uncertainty quantification, such as a fine‐grid oil reservoir model considered in this effort. The numerical results reveal that with the use of the calibrated smoothing function, the improved MLMC technique significantly reduces the computational complexity compared to the standard MC approach. Finally, we discuss several factors that affect the performance of the MLMC method and provide guidance for effective and efficient usage in practice.

A Stochastic Simplex Approximate Gradient (StoSAG) for optimization under uncertainty

SummaryWe consider a technique to estimate an approximate gradient using an ensemble of randomly chosen control vectors, known as Ensemble Optimization (EnOpt) in the oil and gas reservoir simulation community. In particular, we address how to obtain accurate approximate gradients when the underlying numerical models contain uncertain parameters because of geological uncertainties. In that case, ‘robust optimization’ is performed by optimizing the expected value of the objective function over an ensemble of geological models. In earlier publications, based on the pioneering work of Chenet al. (2009), it has been suggested that a straightforward one‐to‐one combination of random control vectors and random geological models is capable of generating sufficiently accurate approximate gradients. However, this form of EnOpt does not always yield satisfactory results. In a recent article, Fonsecaet al. (2015) formulate a modified EnOpt algorithm, referred to here as a Stochastic Simplex Approximate Gradient (StoSAG; in earlier publications referred to as ‘modified robust EnOpt’) and show, via computational experiments, that StoSAG generally yields significantly better gradient approximations than the standard EnOpt algorithm. Here, we provide theoretical arguments to show why StoSAG is superior to EnOpt. © 2016 The Authors.International Journal for Numerical Methods in EngineeringPublished by John Wiley & Sons, Ltd.

Accelerating oil reservoir simulations using POD on the fly

SummaryA reduced order model (ROM) is presented for the long‐term calculation of subsurface oil/water flows. As in several previous ROMs in the field, the Newton iterations in the full model (FM) equations, which are implicit in time, are projected onto a set of modes obtained by applying proper orthogonal decomposition (POD) to a set of snapshots computed by the FM itself. The novelty of the present ROM is that the POD modes are (i) first calculated from snapshots computed by the FM in a short initial stage, and then (ii) updated on the fly along the simulation itself, using new sets of snapshots computed by the FM in even shorter additional runs. Thus, the POD modes adapt themselves to the local dynamics along the simulation, instead of being completely calculated at the outset, which requires a computationally expensive preprocess. This strategy is robust and computationally efficient, which is tested in 10‐ and 30‐year simulations for a realistic reservoir model taken from the SAIGUP project. Copyright © 2016 John Wiley & Sons, Ltd.

A new approach for quality control of reservoir fluid composition data using live oil solubility parameter

Precise physical and chemical description of reservoir fluid is essential for accurate petroleum reservoir evaluation as well as for optimization of development plans of oil and gas fields. The uncertainties in the description of the reservoir oil composition data are the most serious issues for studying the thermodynamic phase behavior of the reservoir fluid. These data are widely used as the basis for calculation of reservoir fluid properties, and for simulation and modeling of underground oil reservoirs. Assumption of correct reservoir fluid (oil) composition is the basis of the most quality control methods presented in the literature, which are used for checking the accuracy of related experiments for thermodynamic phase behavior of reservoir oil (PVT experiments). This assumption may not be satisfied in most cases and affects seriously all related applications in chemical and petroleum engineering. Here, a new approach is introduced to resolve the uncertainties in reservoir fluid (oil) composition using solubility parameter concept of live oil. The solubility parameter of five live oil samples from different Iranian oil reservoirs was used for sensitivity analysis with respect to the molecular weight of the plus fraction to check the accuracy and consistency of the reservoir fluid composition data. Obtained results show that the solubility parameter of live oils at pressure and temperature conditions of oil reservoirs typically varies within a specified rang, which strongly depends on thermodynamic properties and composition of the oil sample as well as pressure and temperature range. The acceptable range of molecular weight of the plus fraction provides the best match for typical range of live oil solubility parameters. This approach provides a new insight into consistency and reliability of reservoir fluid composition data, which is highly beneficial and of special importance for optimization of different processes in both upstream and downstream oil industry.

RETRACTED: Tight oil accumulation mechanisms of Triassic Yanchang Formation Chang 7 Member, Ordos Basin, China

Abstract The sedimentary environment, petrology, pore throat structure, migration and accumulation power, and accumulation process are analyzed to study the oil accumulation mechanism and distribution of Triassic Chang 7 Member tight oil in Ordos Basin. Chang 7 tight oil reservoirs are mainly semi-deep lake – deep lake sandy debris flow deposits and delta front underwater distributary channel deposits. The results of field emission scanning electron microscopy, CT scans and other high-resolution microscopy techniques show the physical properties of Chang 7 oil reservoirs are poor, micro- and nano-meter pore throats are developed, inter-granular pores and feldspar dissolved pores are the main pores, and tube- and strip-shaped pores are favorable reservoir space. The hydrocarbon generation and accumulation simulation of tight oil reservoirs shows that the hydrocarbon charging power of Chang 7 high-quality source rocks is strong. The oil saturation of the Chang 7 were more than 50% in the accumulation phase and even reached 70% or more with the continued power increase and oil enrichment. The source and reservoir rocks of Chang 7 tight oil coexist, so the hydrocarbons migrated under high pressure to migrate along relatively high permeable superimposed sands, reticular fractures and other pathways, and formed large-area continuous or quasi-continuous lithologic oil reservoirs.

A CUDA based parallel multi-phase oil reservoir simulator

Forward Reservoir Simulation (FRS) is a challenging process that models fluid flow and mass transfer in porous media to draw conclusions about the behavior of certain flow variables and well responses. Besides the operational cost associated with matrix assembly, FRS repeatedly solves huge and computationally expensive sparse, ill-conditioned and unsymmetrical linear system. Moreover, as the computation for practical reservoir dimensions lasts for long times, speeding up the process by taking advantage of parallel platforms is indispensable. By considering the state of art advances in massively parallel computing and the accompanying parallel architecture, this work aims primarily at developing a CUDA-based parallel simulator for oil reservoir. In addition to the initial reported 33 times speed gain compared to the serial version, running experiments showed that BiCGSTAB is a stable and fast solver which could be incorporated in such simulations instead of the more expensive, storage demanding and usually utilized GMRES.

Nonlinear stability and ergodicity of ensemble based Kalman filters

The ensemble Kalman filter (EnKF) and ensemble square root filter (ESRF) are data assimilation methods used to combine high dimensional, nonlinear dynamical models with observed data. Despite their widespread usage in climate science and oil reservoir simulation, very little is known about the long-time behavior of these methods and why they are effective when applied with modest ensemble sizes in large dimensional turbulent dynamical systems. By following the basic principles of energy dissipation and controllability of filters, this paper establishes a simple, systematic and rigorous framework for the nonlinear analysis of EnKF and ESRF with arbitrary ensemble size, focusing on the dynamical properties of boundedness and geometric ergodicity. The time uniform boundedness guarantees that the filter estimate will not diverge to machine infinity in finite time, which is a potential threat for EnKF and ESQF known as the catastrophic filter divergence. Geometric ergodicity ensures in addition that the filter has a unique invariant measure and that initialization errors will dissipate exponentially in time. We establish these results by introducing a natural notion of observable energy dissipation. The time uniform bound is achieved through a simple Lyapunov function argument, this result applies to systems with complete observations and strong kinetic energy dissipation, but also to concrete examples with incomplete observations. With the Lyapunov function argument established, the geometric ergodicity is obtained by verifying the controllability of the filter processes; in particular, such analysis for ESQF relies on a careful multivariate perturbation analysis of the covariance eigen-structure.

Gravity Drainage Visualization Experimental Study of Heavy Oil Reservoirs

Liaohe oilfield gravity drainage assisted steam flooding of heavy oil reservoir has made significant development effect, but the drain rule of condensate is unclear in the process of development. Heavy oil drainage microscopic visualization experimental study of using core model of glass etching, drainage process simulation of heavy oil reservoir and its influence factors were analyzed. Its method turns the drainage process of images into computer numerical signal through the image acquisition system, intuitive display flow pattern of drainage, and analyses the influence of homogeneity and the pressure differential regulation of drainage through the experimental data. The experiment results show that condensate around the steam chamber has a corresponding drainage channel, not uniform or diarrhea in the gravity drainage assisted steam flooding process. At the beginning of the drainage channels formation, the instantaneous drainage amount along with the change of pressure difference is not obvious. Instantaneous drainage amount increases with increasing pressure difference in the medium term. It tends to be stable in the later. The time of drainage channels to form homogeneous core is earlier than heterogeneous core. After the drainage channel, differential effects on heterogeneous core than homogeneous core of instantaneous drainage water.