bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Coupled Discrete Dual Continuum and Discrete Fracture Model for the Simulation of Naturally Fractured Reservoirs
Authors: Zhu Langtao , Liao Xinwei , Chen Zhiming , Mu Lingyu 
Published: May 2017

Abstract
Accurate and efficient numerical simulation of naturally fractured reservoirs is challenging. One of the main challenges is to model the flow behavior in a complex fracture network of multi-scale natural fractures. Though conventional dual porosity and dual permeability(DP/DK) models are accurate and efficient in simulating the ideal fractured reservoirs, the DP/DK models are not adequate for modeling these complex networks of multi-scale fractures. Therefore, it is critical important to develop a new approach to model the complex fracture network with a wide range of fracture-length scales and fracture topologies.
In this paper, we develop a coupled discrete fracture and discrete dual continuum model to simulate the fluid flow in fractured systems. Large-scale fractures(LF) are modeled explicitly using a discrete fracture model, called UDFM, and the local-grid refinement is used to accurately handle the transient-flow regime around LFs. Sparse small-scale fractures(SF) are modeled using a discrete dual continuum approach, called EDFM, which is different from the conventional DP/DK models. This coupled model includes three domains: matrix, discrete LFs, and discrete SFs domains. Moreover, an upscaling technique, applying EDFM on the detailed realization of discrete SFs to generate an appropriate discrete dual-permeability model, is also developed. The upscaling technique is suitable for cases where a detailed prior model for the complete fracture network is available.
The simulation studies of model verification demonstrate the applicability, and robustness of the coupled model for fractured oil reservoirs. We examine naturally fractured reservoirs with multiple configurations in the presence of numerous pre-existing fractures. The simulations of depletion development show that LFs have a noticeable impact on the pressure profile. However, the effect of discrete SFs is weak but can't be ignored. In addition, the LFs and SFs both have a remarkable effect on the water saturation field during the water flooding process.
This study further improves the accuracy and efficiency of modeling irregular and no-ideal fracture geometries.
Using Cross-Well Electromagnetics EM to Monitor the Impact and Efficiency of CO2 Injection
Authors: Zhang Ping , Ramadhan Moemen 
Published: May 2017

Abstract
Applying water alternating gas (WAG) process as an enhanced oil recovery method became a well-known strategy in the industry. In a typical WAG process, either water or gas initially is injected for a designed injection cycle followed by another injection cycle for the other phase. Both cycles are repeated sequentially aiming to optimize the overall sweep efficiency. In this paper, we will explore the benefits of using cross-well EM to monitor the water and CO2 injection in WAG applications and address particularly the following two issues: 1) does cross-well EM has the required sensitivity to evaluate the performance of water and CO2 injection? 2) Cancross-well EM monitor the different cycles of a typical WAG application?
Cross-well EM involves applying inductive physics and 2D/3D inversion to define the inter-well conductivity distribution. Due to its unique spatial configuration, both transmitters and receivers are close to the intended survey targets, the cross-well EM is a proper tool for EOR and time lapse studies. CO2 normally has very low conductivity, which is not a good target for induction method. In a WAG project, both water and CO2 are injected into a reservoir, each has its own cycle (typically three to six months). The water used in WAG normally has much higher conductivity than that of CO2, therefore, by alternating the injection cycle the resulting conductivity change could be large enough to be a good target for cross-well EM.
The model used for simulation consists of injection, production and monitor wells. CO2 and water are injected sequentially, each with three-month cycle. The formation porosity and permeability are selected based on real field results. The water and CO2 floods are simulated using dynamic reservoir simulation software. The water and CO2 injection cycles were continued for 5 years to provide opportunity for time-lapse surveys. The formation resistivity variations due to water and CO2 were calculated using Archie's law. The cross-well EM fields were calculated between injection and monitor wells before and after water/CO2 injection cycles to study the sensitivity. Data inversions were performed to understand how well we could reconstruct the water and CO2 fronts.
The preliminary studies suggested that the cross-well EM is an appropriate tool for tracking CO2 and water flood for the models tested and the technique has an excellent ability to define the reservoir volume being affected by the injected fluid. The modeling results positively answer the sensitivity and efficiency questions for the use of cross-well EM as a surveillance tool for a WAG application.
Dynamic Characterization of Different Reservoir Stacked Patterns for a Giant Carbonate Reservoir in Middle East
Authors: Yong Li , Qi Zhang , Chenji Wei , Benbiao Song 
Published: May 2017

Abstract
Understanding reservoir stacked styles is critical for a successful water injection in a carbonate reservoir. Especially for the giant carbonate reservoirs, different regions with different reservoir architecture stacked patterns developed may be applied to different development options. So reservoir stacked pattern characterization are especially important for the giant carbonate reservoir. This paper propose a systematic method of dynamic characterization on different reservoir stacked pattern, which applied to a giant carbonate reservoir in Middle East.
This paper focuses on a giant carbonate reservoir, which is a Cretaceous carbonate reservoir in Middle East, with conducting waterflooding pilots currently. Thief zones are developed in this reservoir. Four patterns of reservoir architecture stacked style are classified based on geological study. Then the proposed systematic dynamic characterization method are applied, which mainly based on the dynamic data analysis (production data, formation test pressure, production logging test data etc.) and reservoir engineering methods (material balance analysis, well test analysis). Finally, distribution of the four patterns are mapped combined geological and dynamic understanding.
The four patterns have distinctive geological features and dynamic characteristics. For example, pattern A are mostly composed by good quality reservoirs with high production rate for most intervals. Pressure gradient has almost no change from top to bottom, and well test log-log curve shows typical homogeneous reservoir characteristics. And OOIP of pattern A well is large with drainage radius mostly larger than 900m. While from pattern A to pattern D, poor reservoir and barriers increase, which change from massive reservoir to multi-layered reservoir. For pattern D, pressure gradient are separated as zigzag curve, and boundary response is clearly shown in well test log-log curve. Well OOIP and well drainage radius become smaller. After systematic dynamic characterization, reservoir architectures of all wells are calibrated and validated with geological results, and lateral distribution of architecture patterns are mapped.
This paper offers a case study of systematic dynamic characterization of reservoir architectures for carbonate reservoirs. And understanding of reservoir architectures is much valuable for the next development options decision, which means different waterflooding well pattern, well type etc. are applied to different reservoir architectures. It also provides a methodology and reference case for engineers and geologists to investigate on other similar fields.
Digital Rock Analysis of the Transition Zone in the Minagish Formation, Kuwait
Authors: Hayat L. , Al-Rushaid M. A. , Idowu N. , Fogden A. , Sommacal S. , Golab A. , Zalzale M. 
Published: May 2017

Abstract
We present the results of a comprehensive multiscale imaging and simulation projecton core plugs from the Minagish formation in South East Kuwait. The objective of the study was to calculate petrophysical and two-phase flow properties of core plugs representative of well BG-0836. The well contains multiple rock types ranging from packstone to coarse grainstone and includes an oil-water transition zone.
Nine plugs were selected to represent the different rock types and wettability conditions encountered in the well. A digital rock analysis (DRA) program was established to characterize the plugs by combining experiments, imaging, modeling, and simulations. The plugs were imaged at multiple scales by X-ray micro Computed Tomography (microCT), Scanning Electron Microscopy (SEM) and SEM-Energy Dispersive X-ray Spectroscopy (SEM-EDS) to allow a detailed characterization of the pore space and the construction of representative rock models.
The rock models were used to calculate the petrophysical properties of the core plugs including porosity, permeability, formation factor and the cementation exponent (m). The simulation of two-phase flow properties requires plausible pore-scale wettability distribution input. This is particularly important in the transition zone where the samples can range from oil-wet to water-wet. Consequently, to increase the reliability of the results, the DRA workflow was complemented by an advanced 3D pore-scale imaging workflow in which the fluid distributions in the samples were imaged by micro CT after experimental water saturation, primary drainage, spontaneous and forced imbibitions. The 3D images obtained at different saturation states were used to quantify the wettability and guide the two-phase flow simulations. Oil/water capillary pressure and relative permeability curves for primary drainage and water imbibition as well as the saturation end-points were generated.
Developing Infill and EOR Opportunities While Managing Subsurface Uncertainties in a Mature Complex Field Using Probabilistic Dynamic Modeling
Authors: Karim R. Abd , Tewari R. D. 
Published: May 2017

Abstract
This paper discusses about a systematic approach of probabilistic dynamic modeling which was used to assess subsurface uncertainties, and to forecast range of ultimate recovery (P90, P50, and P10) for infill and EOR opportunity (immiscible Water-Alternating-Gas, iWAG) in a mature offshore oilfield.
The field is very complex, with multi-layered and highly compartmentalized reservoirs and has been on production under natural depletion since the last 47 years. It is in "mid-life crisis", facing problems of high watercut and GOR, with bypassed oil areas and pressure depletion, and therefore in need for redevelopment to increase its recovery factor. However, despite the long production history, subsurface uncertainties remain high due to its reservoirs complexity and limited reservoir data.
To assess the subsurface uncertainties and their impact on field redevelopment plan, a fine-scaled sector model was built for a focused area of the field with substantial remaining opportunity. Multiple static realizations were used to represent different reservoir connectivity that can be highly influential on the ultimate recovery, especially for iWAG injection. Along with these multi-static realizations, key dynamic uncertainties such as fault transmissibility, kv/kh, aquifer properties, etc. were also incorporated. It is very important to note that uncertainty parameters may vary between history matching and forecast period, especially when there is a change in drive mechanisms. Therefore, additional uncertainty parameters such as residual oil saturation (Sorw, Sorg), in the case for iWAG scenario, have also been included from the very beginning to ensure seamless transition from history matching up to forecasting.
Another big challenge to conduct probabilistic dynamic modeling in a mature field is, to generate multiple equally probable history matched realizations for subsequent proxy modeling and probabilistic forecasting. The uncertainty and optimization (U&O) modeling tools, including experimental designs, have made this possible and proven to be the most efficient way to speed up the modeling process. It has helped to generate the physical P90, P50, and P10 dynamic models that could be used to assess the robustness of various development options, hence able to deliver the optimum strategies while managing subsurface uncertainties.
All these proved to be a comprehensive probabilistic workflow to firm up several sizeable infill and injection portfolios in this complex mature field, with potential to increase recovery factor by 8% to 13%. Most importantly, decision makers were given a range of outcomes instead of a deterministic forecast, allowing proper risks mitigation plans to be devised to deliver a robust project definition and superior performance.
Coupled Geomechanics And Flow Simulation For Water Injection Induced Fracture Propagation in Tight Reservoirs During Waterflood Process
Authors: Lei Zhengdong , Li Junchao , Tang Huiying 
Published: May 2017

Abstract
During waterflooding process, the characteristics of injection water induced fracture propagation and resulting percolated fracture network remain unclear and are of great importance for the optimization of waterflood performance. In this paper, a coupled geomechanics and flow model based on discrete fracture model is developed to model the fracture propagation induced by injected water. A displacement discontinuity method is applied to simulate the stress redistribution and newly formed fractures. The fracture geometry is updated and re-gridding procedures are carried out according to the situation at the certain time step. A validate case and a real field case are studied and results demonstrate the effectivity of the proposed method.
Estimation of Three-Phase Relative Permeabilities for A WAG Process Using An Improved Ensemble Randomized Maximum Likelihood Algorithm
Authors: Fan Zhaoqi , Zhang Yin , Yang Daoyong 
Published: May 2017

Abstract
In this paper, a modified ensemble randomized maximum likelihood (EnRML) algorithm has been developed to estimate three-phase relative permeabilities with consideration of hysteresis effect by reproducing the actualproduction data. Ensemble-based history matching uses an ensemble of realizations to construct Monte Carlo approximations of the mean and covariance of the model variables, which can acquire the gradient information from the correlation provided by the ensemble. A power-law model is firstly utilized to represent the three-phase relative permeabilities whose coefficients can be automatically adjusteduntil production history is matched. A damping factor is introduced as an adjustment to the step length since a reduced step length is commonly required if an inverse problem is sufficiently nonlinear. Arecursive approach for determining the damping factor has been developed to reduce the number of iterations and the computational loadof the EnRML algorithm. The restart of reservoir simulations for reducing the cost of reservoir simulations is of significant importance for the EnRML algorithm where iterations are inevitable. By comparing a direct-restart methodand an indirect-restart method for numerical simulations, we optimize the restart method used for a specific problem. Subsequently, we validate the proposed methodologyby using a synthetic water-alternating-gas (WAG) displacement experiment and then extend it to match laboratory experiments. The proposed technique has proved toefficientlydetermine the three-phase relative permeabilities for the WAG processes with consideration of the hysteresis effect, while history matching results are gradually improved as more production data are taken into account. The synthetic scenarios demonstrate that the recursive approach saves 33.7% of the computational expense compared to the trial-and-error method when the maximum iteration is 14. Also, the consistency between the production data and model variables has been well maintained during the updating processes by using the direct-restart method, whereas the indirect-restart method fails to minimize the uncertainties associated with the model variables representing three-phase relative permeabilities.
Innovative Testing for Potential Compaction of Heterogeneous Carbonate Reservoir in A Giant Field, Abu Dhabi, UAE
Authors: Noufal A. , Ateeq B. , Al Amari K. , Masoud R. , Al Gohary M. , Sirat M. , Bois A.-P. , Dadouche H. , Kpatta D. , Mohajerani M. 
Published: May 2017

Abstract
A carbonate reservoir has an average thickness of 90 feet and an average porosity of 24% (with localized porosity stringers up to 32%). After 25 years production, it experienced a reduction in pore pressure from 4,300 psi to 2,000 psi. Subsequent modeling indicated that continued production would reduce the reservoir's pore pressure to 600 psi. This led to concerns related to increase in effective stresses, which could result in reservoir compaction and subsequent surface subsidence.
To assess this risk, ADCO performed a geomechanical testing campaign using carbonate plugs with high porosity (25-30%). Because of the heterogeneous nature of the reservoir, it was not possible to use conventional testing methods, which would require a set of five to ten "identical" plugs. Moreover, conventional multi-stage triaxial tests could not be used to evaluate cohesion and friction angle parameters of high-porosity plugs because the yield cap was reached before the critical state line. Consequently, a dedicated multi-stage triaxial testing method was developed, which consisted of performing a series of loading/unloading cycles starting from an isotropic cycle, followed by deviatoric-stress cycles with confining pressures decreasing from one cycle to the next one, until the critical state line is reached.
These innovative tests were used to evaluate the parameters of a capped constitutive law by back-analyzing the stress-strain curves of all cycles in one operation, which gave very good matches between measured and back-analyzed curves, with high-confidence estimation of the constitutive law parameters. This allowed developing trends of Young's modulus, cohesion, and friction angle versus porosity. However, the point characterizing the in situ stress was sometimes located outside the envelope, meaning that some plugs were damaged before testing.
Numerical Simulation of Electrical-Heating Assisted SAGD in Heterogeneous Heavy Oil Reservoirs
Authors: Yongbin Wu , Xingmin Li , Wanjun He , Fang Zhao , Yueyue Fang , Weinan Ai , Youwei Jiang , Xiaoxiong Liu 
Published: May 2017

Abstract
In order to massively enhance the performance of heterogeneous SAGD projects, the targeted Electrical-Heating in poor steam chamber segment assisted SAGD (EH-SAGD) was proposed, the simulation method was established coupling geo-mechanics of both payzone and interbeds, and delivery of energy by electrical heating into the subsurface. The screening criteria of EH-SAGD was formed and the typical SAGD wellpair performance was predicted and compared.
As the EH-SAGD is quite complex in its mechanisms, the precise simulation must reflect the impact of these mechanisms. Therefore, systematic experiments were carried out firstly to provide the key parameters of the rock and fluid to the simulation model. The geo-mechanic characteristics of barriers with different rock types was obtained by tri-axial compression tests, and the mineral composition change and reaction at elevated temperatures were obtained by means of X ray diffraction and interpretation.
The numerical simulation model of EH-SAGD was established based on the experimental results. The geo-mechanic model were added into the simulation based on the experimental results illustrating the Young's modulus, Poisson's ratio, compression strength, yield stress and the corresponding changes of the porosity and permeability.
From numerical simulation, the screening criteria for reservoirs that feasible for EH-SAGD was optimized by multi-parameters. The SAGD wellpairs with barriers in between the horizontal segments were the applicable targets for electrical heating. The combination heating of downhole heaters in both injector and producer was recommended for rapid breakthrough of the barriers. The heat power of the heaters with time was also optimized which required the highest power of 2500W/m for each heater. Following which a typical SAGD wellpair was selected to make the comparison. It is simulated that by targeted electrical heating, the oil drainage route can be established, the steam chamber along the whole horizontal segment can be developed, and the oil rate can be enhanced by 45% from conventional SAGD. It is forecasted that the oil recovery factor of EH-SAGD is 12.1% higher than SAGD.
The results indicate that the EH-SAGD has encouraging effect to enhance the oil rate, steam chamber uniformity, and the final oil recovery factor, which is a practical and novel EOR approach for heterogeneous SAGD reservoirs.
Proposing Low Temperature CO2 for Enhancing Miscibility in High Temperature Reservoirs
Authors: Hamdi Zakaria , Awang Mariyamni , Bataee Mahmood , Vatanparast Maryam 
Published: May 2017

Abstract
For several decades, CO2 injection has been used as a successful recovery method in enhanced oil recovery. The main impact of CO2 is on lowering minimum miscibility pressure (MMP). Reaching the miscibility pressure is often limited by the reservoir pressure and temperature. Based on the earlier studies, lowering the temperature of the medium by the injection fluid may help in a decrease of MMP, resulting in miscible flooding. However, the proposed method should be determined by experimental procedures and numerical calculation. For the evaluation of MMP reduction and the limitations involved, the slimtube displacement experiments were used along with simulation runs. Then the results were compared with empirical correlations. The results showed that injection of low temperature CO2 (LCO2) has a direct impact on the MMP of a high temperature system. However, it limited when the injection temperature is below the critical temperature of CO2. A modification equation was presented to be applied on available empirical correlations. In terms of MMP, LCO2 injection is more beneficial than CO2 when it enters the reservoir at lower temperatures with respect to injection limitations.
Coupled Fluid Flow to Geomechanics in Fractued Reservoir: Governing Equation, Geomechanics Parameters and Numerical Method
Authors: Wang Yarlong 
Published: May 2017

Abstract
The effectiveness of a hydraulic fracturing technology has been primarily attributed to a creation of the geometry in the primary fracture. This concept however has been challenged particularly in low-permeability formations in which the size of a Stimulating Reservoir Volume (SRV) becomes the most important issue. Unlike the primary fracture, the area in the SRV is controlled by the fundamental geomechanics behaviors of the formation and a secondary fracture network propagation with possible different modes, and more importantly by the formation permeability change which is controlled by the induced stresses near the primary fracture. In this paper, the induced stresses near a hydraulic fracture in a pure elastic, poroelastic, dual-porosity media are analyzed and compared in order to characterize the low-permeability, sandstone and fractured formations, respectively. The general formulation for a fractured reservoir by a dual porosity model is developed and pore pressures and stresses near a wellbore and a hydraulic fracture are highlighted for production enhancement as the permeability change near a wellbore or a hydraulic fracture may contribute to such an enhancement significantly. Those key parameters controlling the pressure and stresses change and numerical method used are analyzed and presented.