Wang, Jibin (PetroChina Daqing Oil Company) | Zhuang, Xiangqi (Schlumberger) | Chen, Shuli (PetroChina Daqing Oil Company) | Wen, Heng (Schlumberger) | Wang, Yunlong (PetroChina Daqing Oil Company) | Xiang, Chuangang (PetroChina Daqing Oil Company) | Zhang, Qinbin (PetroChina Daqing Oil Company) | Tian, Hong (Schlumberger) | Wang, Lizhi (Schlumberger) | Chen, Yingru (Schlumberger)
Massive hydraulic fracturing and re-fracturing jobs have become very popular operations for developing tight oil & gas reservoir and unconventional shale gas reservoir in China. Experiencing long period of production and injection, in-situ pore pressure, stresses and saturation field were significantly changed. Reservoir re-characterization, fracturing modeling and dynamic simulation efforts are necessary to help understand massive re-fracturing impact on production performance and water injection optimization. In this study, a new integrated geomechanics, hydraulic fracturing model and reservoir simulation workflow is formulated and applied to optimize post-frac injection and production in Zhou-6 tight oil block, Daqing field.
With this new workflow, the injection volume of Zhou-6 field was successfully optimized through this more realistic reservoir simulation model. The production of the re-fractured wells was successfully maintained for more than 1 year with the optimized injectivity. The workflow will be widely applicable to other tight oil fields which are involved in massive hydraulic fracturing treatment and water injection development.
Meng, Zhan (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Yang, Shenglai (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Wang, Lu (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Wang, Zhilin (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Qian, Kun (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Lei, Hao (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Ma, Quanzheng (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum) | Wang, Mibang (Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum)
Horizontal drilling and hydraulic fracturing have been proven to significantly increase production from tight oil formations, however, one of the characteristics of these reservoirs is high production declining rate. In the long term, it is necessary to increase the development efficiency of block matrix, many studies have shown that spontaneous imbibition is a potential way. In addition, precisely predicting the behavior of the imbibition recovery under different viscosity ratios is thus critically important. The goals of this paper include theoretically and experimentally investigating the effect of the viscosity on the imbibition recovery.
In this paper a novel pore-scale spontaneous imbibition model is established by two steps. At first, the spontaneous imbibition equation in a single capillary tube considering that immobile oil is established based on Hagen Poiseuille formula. Then, pore-scale spontaneous imbibition model based on fractal theory has been derived. In addition, the corresponding spontaneous imbibition tests have been conducted on sandstone natural cores collected from Xinjiang oilfield.
The predictions of the imbibition recovery by the proposed model have been validated by comparing them with the experiments conducted. Data of cores H-56 and H-39 are used to comparing the calculated imbibition recovery with the measured imbibition recovery. Under four different oil/water viscosity ratio, 0.5, 1, 5 and 10, the relative errors between calculated data and measured data are less than 7%. And both the theoretical and experimental results show that the viscosity ratio of the mixed oil and brine has a significant effect on the spontaneous imbibition recovery. The predicted and experimental results demonstrate that a higher imbibition recovery corresponds to a lower oil/brine viscosity ratio. In addition, rate of spontaneous imbibition has a significant decline which is the same as the result of the calculation.
In general, since the established model has a high precision, it can be used to analyze the effects of different parameters like the contact angle, the interfacial tension and other structural parameters and the results can be useful for understanding the spontaneous imbibition law. What's more, the conclusion can guide the surfactant screening in surfactant-aided imbibition schemes.
The coupled flow-geomechanics model is required to investigate the stress change, rock-compaction behavior, and stress-dependent properties in many reservoir scenarios. However, the coupled model for large-scale or three-dimensional simulation problems usually encounters large matrix system and high computation expenses, where the time stepping is a crucial factor for numerical stability and computational efficiency. In this paper, an adaptive time stepping with the modified local error method was presented to reduce iteration time and improve the computation efficiency for the coupled flow-geomechanics modeling. Firstly, the iterative coupling approach with the fixed-stress method was introduced, where the flow and geomechanics equations are sequentially solved at each time step. Secondly, due to updating geomechanics module consumes the major computing time for the coupled problems, the modified local error method was mainly used for geomechanics module, where fewer geomechanics time steps are needed after implementation. Specifically, the geomechanics module will be updated until a given local error of displacement is reached, and the time step size will be automatically adapted based on the change of displacement, which is more efficient than the constant time step method. Finally, a synthetic two-dimensional coupled production problem is established to apply the proposed adaptive time stepping approach, where the numerical results including the computing efficiency are compared with the results from regular sequential method and the fully coupled model. The sensitivity about the local error tolerance was also investigated.
The geomechanical responses regarding mechanical loading is validated by comparing with the analytical solution of Terzaghi's consolidation problem. The numerical results about the pressure and displacement change on the two-dimensional coupled model are compared with the results from the regular sequential method and the fully-coupled method. The modified local error method, which adjusts time step size for both flow and geomechanics module, not only yields a higher-order solution for better accuracy, but also significantly reduces the iteration number and computation time, especially for the cases with low truncation error requirement. The error tolerance of displacement is critical on when the step size will be adapted. Small error tolerance can maintain the accuracy while it needs more iteration computing. The strategy about how to modify step size plays an important role in the stability and computing efficiency for the modified local error method. A large increase or cut on one-step size could bring the oscillation results. Overall, the adaptive time stepping approach can both effectively reduce total computation time and simultaneously maintain the accuracy for the coupled flow-geomechanics problems. It is useful for large-scale or three-dimensional coupled problems, where the high computational efficiency is required.
A dual porosity formulations coupled geomechanics to two-phase fluid Flow in fractured reservoirs are developed and a Petrov-Galerkin finite element method is utilized. Formulations for saturation, with a time variable only, is incorporated with the displacement and pore pressures, which are fully coupled and solved simutaneously. A linear shape function is used for the pressures and saturation, and a quadratic one for displacement to avoid numerical oscillation. A consistent weighting function similar to the linear shape function is used for all interpolated variables. Solutions for pore pressures, stresses, and saturations near a wellbore and a hydraulic fracture in the dual porosity system simulating a fractured reservoir and in different phases are presented
Raheem, Oriyomi Nurudeen (The Petroleum Institute) | Fernandes, Martin Olivier (The Petroleum Institute) | Thomas, Nithin Chacko (The Petroleum Institute) | Hashem, Mohamed Hossni (The Petroleum Institute) | Alfazazi, Umar (The Petroleum Institute) | Sulemana, Nuhu Turosung (The Petroleum Institute)
This research work predicts capillary pressure curves at primary drainage from the transverse T2 relaxation times of the NMR pore size distributions with ninety percent accuracy, which could do the trick in reservoir applications. The capillary pressure-water saturation curves are important instructions to reservoir simulators for predicting the dynamic properties of the reservoir as well the fluid saturations at different depths. This study originated from the challenges in forecasting the initial saturations from an NMR logged well. The procedure is a simple and non-damaging construction of capillary pressure curves from plug samples measurements.
Dynamic rock typing was used to assign the capillary pressure data to different layers in the reservoir. Laboratory Nuclear Magnetic Resonance (NMR) equipment has been proven to produce information on pore size distribution and varieties of methods was found in the literature to predict capillary pressure curves from borehole NMR logs. The proposed idea of integrating drainage capillary pressure from centrifuge to T2 distributions from NMR enables rapid synthesis of capillary pressure from plugs and interpretation of logs.
A scaling factor k, is adopted in the T2-Pc conversion. The optimum scaling factors for most research work is built upon the results. Water saturation at certain pressures, is often estimated from capillary pressure curves. It can therefore be argued that the perfect procedure of estimating the best scale factors is to recreate the saturations by the capillary pressure curves developed from NMR. In this research work, the range of pressures and T2 relaxation time was 0 – 500 psi and 1 – 10000 ms respectively. Due to different geological facies usually described by the capillary pressure curves of different formations, the capillary pressure curves of the completely cored reservoir were reconstructed to get the average scaling constant, k of 4 psi.s with a low standard deviation of 0.02. The capillary pressure versus T2 curve tend to fit a power regression with a coefficient of determination of R2= 1, signifying that the regression line analysis fits perfectly with the data for the 18 core samples.
With the T2-Pc conversion established, the capillary pressure data can be predicted continuously in the whole section of the reservoir. The procedure is more accurate compared to others since it takes cognizance of the pore structure from NMR distribution, and it is applicable to T2 distributions estimated at various water saturations. Previous methods are applicable to 100% brine saturated plugs, which nullifies their predicted capillary pressure curves.
Proppant conductivity in fractures at closure is crucial to ultimate hydrocarbon recovery from reservoirs. The proppant distribution inside the fracture determines the conductivity. This paper presents the application of solids-free channel fracturing treatment in microfractures. Microproppant (MP) agglomeration forms mini-pillars that support the microfractures to help prevent their complete closure and to provide conductive flow paths. Mathematical modeling of the conductivity that results from the microproppant pillars is presented and compared with the experimental data for validation using split cores of an Eagle Ford shale outcrop sample. Proppant embedment caused by the fracture deformation is estimated using the numerical model.
This paper presents a new three-dimensional (3-D) mathematical model that couples the solids and produced-fluids fracture-flow fluid mechanics with the deformable proppant pillars. MP aggregates/pillars are modeled as deformable cylindrical agglomerates, and the particles are modeled as deformable aggregates that deform under the closure stress. The fluid flows inside the fracture when there is a pressure differential. The propped microfractures are modeled as deformable solids that interact with the fluid flow. The fracture deforms as a result of closure and fluid stress. The model captures the fracture and pillar deformations using moving-mesh capability.
Simulations of closure stress with multiple pressure differentials for flow through the solids-free channels were performed to compare the conductivity obtained from the experiments using the split Eagle Ford shale core. MP aggregates, with less supporting surface area, must support higher closure stress compared to the conventional packed-proppant fracture, which has higher stiffness and lower embedment. Core samples treated with MP droplets were tested to obtain the experimental conductivity data. The results showed that the MP aggregates provided better conductivity than the partial monolayer of MP particulates were uniformily distributed and the number of droplets was properly limited. This was validated both qualitatively and quantitatively during the experiments. An uncertainty analysis using the simulation model revealed that the MP aggregate height significantly influenced conductivity and, therefore, should be optimized to enhance production.
Hayat, L. (Kuwait Oil Company) | Al-Rushaid, M. A. (Kuwait Oil Company) | Idowu, N. (FEI Oil & Gas) | Fogden, A. (FEI Oil & Gas) | Sommacal, S. (FEI Oil & Gas) | Golab, A. (FEI Oil & Gas) | Zalzale, M. (FEI Oil & Gas)
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.
Alzayer, H. (Centre of Enhanced Oil Recovery and CO2 solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Jahanbakhsh, A. (Centre of Enhanced Oil Recovery and CO2 solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre of Enhanced Oil Recovery and CO2 solutions, Institute of Petroleum Engineering, Heriot-Watt University)
To ensure the physics of multiphase flow in porous media is rightly modelled, the balance between capillary, viscous, and gravity forces need to be understood. Capillary pressure (Pc) and relative permeability (kr) are critical parameters representing capillary and viscous forces respectively. Both are typically determined by special core analysis in the laboratory. The importance of application of proper capillary pressure curves for different processes and the consistency between the kr and Pc input are investigated.
In this study, we used the idea of Numerical Coreflood Experiment (NCFE) where detailed geology and known oil-water relative permeability and capillary pressure curves are used. Various NCFEs' production and pressure data can be generated for different conditions and used to estimate the kr and Pc. Here, we used a commercial application to back calculate a set of relative permeability and capillary pressure that fits the given production and pressure data for the examined cases. Afterward, we compared the resulting kr and Pc curves with those that were used to generate the NCFEs data to begin with.
In this study, we focused on the two-phase oil-water system to assess the process of obtaining a history- matched relative permeability by fitting the core-flood experiment data while setting capillary pressure to zero (ignoring Pc) in the simulation model. We compared different cases that we examined to identify the role and importance of Pc measurements in core-scale and reservoir-scale numerical simulations. The conclusion is that using appropriate input capillary pressure measurement is an essential step to ensure proper representation of the multi-phase flow physics. Ignoring Pc or using inaccurate Pc measurements could lead to inaccurate relative permeability curves and as a results unrealistic production and pressure output.
The results of this study can be used by researchers and practicing reservoir engineers in oil and gas industry. NCFE is an inexpensive and easy-to-use technique to evaluate the current experimental procedures and suggest improvements. NCFE can be extended to cover a wider-range of evaluations including the effect of gravity, injection rate and heterogeneities.
A new absolute permeability upscaling method based on geological hierarchical models that affect different scales reservoir heterogeneities is presented. Reservoir anisotropy is evaluated via horizontal permeability (Kh) and vertical permeability (Kv). The new approach based on the geologic viewpoint that various geologic hierarchical-elements set result in relevant permeability display of different reservoir scales. For reservoirs, from micro-scale to macro-scale, influencing factors of permeability become abstruse. In conventional scenario, the calculation method based on single-phase numerical simulation test, core analysis and data statistics integrates all these factors as much as possible to upscale permeability. Considering reservoir anisotropy, horizontal permeability (Kh) and vertical permeability (Kv) are studied to show how anisotropy changes according to different reservoir heterogeneities. In the case study of Mackay River Oil Sand Block, Alberta, Canada, database includes regional depositional setting, core, and logging data for more than 20 wells. Generally, reservoir sedimentary setting poses a direct effect on permeability. Local rock bedding affects permeability anisotropy greatly, as well. There is no obvious linear parity between horizontal permeability (Kh) and vertical permeability (Kv) in core-plug. Vertical and lateral grain size variance also alters permeability. The mm-cm scale mud drapes have a worse effect on vertical permeability (Kv) than on horizontal permeability (Kh). Besides, bioturbations in the transitional facies could be favor of permeability. The three factors have non-linear relationship on effecting permeability. The new upscaling model synthesizes all these factors to upscale the permeability for nearly all scales of reservoirs, from the scale of core to lithofacies or even to the entire reservoir. Comparisons study is also conducted between this model and current upscaling algorithms such as arithmetic average, harmonic average, etc. The results showed that the upscaling model of this paper is more reasonable. Meanwhile, reservoir characterization hierarchical models can also be applied to explicate heterogeneity effect on the attribute of reservoir fluid qualitatively. The novelty of this approach lies in solving reservoir fluids' attributes quantitatively through exact heterogeneities analysis.
Relative permeability is an essential parameter for reservoir description, engineering, and management. Relative permeabilities are typically obtained in the laboratory through evaluation of the dynamic behavior in cores using fluids that are assumed to be representative of those in the reservoir. In-situ measurements of effective permeability can provide valuable information about fluids, rock, pressure, temperature, and their interactions in the evaluated formation at original reservoir conditions. Recent technological advances allow data obtained from formation testers to be analyzed and interpreted for estimating relative permeabilities.
Formation testers are typically run when wells are drilled; therefore, using acquired data for estimating effective permeability can be cost-effective and less time-intensive compared to existing effective permeability estimation methodologies. However, the measurement process, the meaning of the acquired data, the interpretation of the data, and the resulting relative permeability values are affected by the uncertain environment associated with the entire process, which also affects the confidence of the estimated relative permeabilities and their use as an input for reservoir description, engineering, and management.
Although the use of formation testers as a tool to estimate relative permeabilities is promising, it is crucial to understand the environment in which the dynamic events occur and the impact of the uncertainties related to the physical phenomena and interactions associated with the measurement and interpretation processes. Conversion of the acquired information at the oil/gas well into inputs to properly interpret the acquired data, the models available to interpret the phenomena, and the formation tester tool capabilities all require understanding of the uncertainties associated with the entire process. These uncertainties, when properly qualified and quantified, can serve as the decision criteria to estimate the value of information (VOI) of relative permeability determination using in-situ formation tester data.
This work provides a detailed description of the uncertainties related to relative permeability estimation based on in-situ measurements of formation testers and its impact on the interpretation outputs.