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Shiqing Cheng - One of the best experts on this subject based on the ideXlab platform.
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Investigation on the transient pressure response of water injector coupling the dynamic flow behaviors in the wellbore, waterflood-induced fracture and reservoir: Semi-analytical modeling and a field case
International Journal of Heat and Mass Transfer, 2019Co-Authors: Yang Wang, Shiqing Cheng, Kaidi Zhang, Luis F. AyalaAbstract:Abstract There is growing evidence showing that water injection may induce formation fracturing around injectors in tight reservoirs. Because waterflood-induced fractures (WIFs) are not strengthed by proppants, they close gradually during the field-testing period, which results in “fracture-closure-induced” flow rate, shrinking fracture length (SFL) and decreasing fracture conductivity (DFC). In this paper, we propose a novel semi-analytical model to characterize the bottom-hole pressure (BHP) behavior of water injectors by coupling the dynamic flow in the wellbore, WIF, and reservoir. Flows between reservoir and WIF are linked through a fracture-storage coefficient and fracture-face Skin Factor, while flows between WIF and wellbore are coupled via wellbore-storage coefficient and choked-fracture Skin Factor. Perturbation theory method is deployed to include the DFC effect, and Duhamel principle is invoked to characterize flow rate changes caused by wellbore and fracture storage effects. Results show that bi-storage effects can be identified as two unit slopes in the pressure derivative curve. In the absence of extra pressure drop between wellbore and WIF, i.e., choked-fracture Skin equals to zero, a prolonged storage period with a considerably large storage coefficient can be obtained. In addition, we find that SFL could cause the variable fracture storage effect while DFC may lead to the upward of pressure derivative curve at late times. Finally, the model is successfully applied in the Changqing Oilfield to validate its reliability.
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Diagnosis of Water-Influx Locations of Horizontal Well Subject to Bottom-Water Drive through Well-Testing Analysis
Geofluids, 2018Co-Authors: Jiazheng Qin, Shiqing Cheng, Le Luo, Xinzhe ShenAbstract:Horizontal well (HW) has been widely applied to enhance well productivity and prevent water coning in the anisotropic reservoir subject to bottom-water drive. However, the water-cut increases quickly after only one or two years’ production in China while oil recovery still keeps at a very low level. It becomes a major challenge to effectively estimate production distribution and diagnose water-influx locations. Ignoring the effect of nonuniform production distribution along wellbore on pressure response may cause erroneous results especially for water-influx location determination. This paper developed an analytical method to determine nonuniform production distribution and estimate water-influx sections through well-testing analysis. Each HW is divided into multiple producing segments (PS) with variable parameters (e.g., location, production, length, and Skin Factor) in this model. By using Green’s functions and the Newman-product method, the novel transient pressure solutions of an HW can be obtained in the anisotropic reservoir with bottom-water drive. Secondly, the influences of nonuniform production-distribution on type curves are investigated by comparing the multisegment model (MSM) with the whole-segment model (WSM). Results indicate that the method proposed in this paper enables petroleum operators to interpret parameters of reservoir and HW more accurately by using well-testing interpretation on the basis of bottom-hole pressure data and further estimate water-influx sections and nonproducing segments. Additionally, relevant measures can be conducted to enhance oil production, such as water controlling for water-breakthrough segments and stimulation treatments for nonproducing locations.
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semi analytical modeling for water injection well in tight reservoir considering the variation of waterflood induced fracture properties case studies in changqing oilfield china
Journal of Petroleum Science and Engineering, 2017Co-Authors: Yang Wang, Naichao Feng, Youwei He, Shiqing Cheng, Jianchun Xu, Haiyang YuAbstract:Abstract It is well acknowledged that water injection may induce formation fracturing in tight reservoir, and the injection well may experience shrinking fracture length (SFL) and variable fracture conductivity (VFC) during fracture-falloff period, which shows the bi-storage behavior. However, available pressure-transient analysis (PTA) models hardly consider these effects (SFL, VFC and bi-storage behavior) on pressure-transient response, which can lead to erroneous results. This paper aims at presenting an innovative approach to model the water injection wells considering the dynamic characteristics of waterflood-induced fracture (WIF). We first modeled fluid flow between reservoir and the fracture which characterized by fracture-storage coefficient and fracture-face Skin Factor, and flow between wellbore and the fracture which represented by wellbore-storage coefficient and choked-fracture Skin Factor. In addition, the effects of SFL and VFC were included by finite difference method. A semi-analytical solution was then derived to model injection well with waterflood-induced fracture (IWWIF). Finally, this methodology has been successfully applied in Changqing oilfield, China. There are six flow regimes for the IWWIF model in the tight reservoir, including wellbore-storage regime, transitional-flow regime, fracture-storage regime, the second transitional regime, linear flow regime and bilinear flow regime. Compared to current models, the bi-storage phenomenon is discovered and validated as two straight lines with unit slope in the pressure derivate curve of type plot. The WIF that closely links with the wellbore can be regarded as an “expanding wellbore”, which illustrates the reason that the “wellbore-storage coefficients” are increased by up to several orders of magnitude in a great many of water injection wells. The VFC behavior could cause the upward of pressure-derivative curve, which is generally recognized as the characteristic of closed boundary condition while the variable fracture-storage effect may occur because of SFL. In addition, the relation between matched fracture-storage coefficient and fracture length is given, which provides us another way to obtain the probable length of WIF. Finally, this new model has been successfully used to evaluate well performance and reservoir characteristics based on bottom-hole pressure (BHP) history of five field cases in Changqing oilfield, China.
Jiang Ruizhong - One of the best experts on this subject based on the ideXlab platform.
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Pressure Transient and Rate Decline Analysis for Hydraulic Fractured Vertical Wells with Finite Conductivity in Shale Gas Reservoirs
'Springer Science and Business Media LLC', 2015Co-Authors: Guo Chaohua, Xu Jianchun, Wei Mingzhen, Jiang RuizhongAbstract:Producing gas from shale strata has become an increasingly important Factor to secure energy over recent years for the considerable volume of natural gas stored. Unlike conventional gas reservoirs, gas transport in shale reservoirs is a complex process. In the organic nano pores, slippage effect, gas diffusion along the wall, viscous flow due to pressure gradient, and desorption from Kerogen coexist; while in the micro fractures, there exist viscous flow and slippage. Hydraulic fracturing is commonly used to enhance the recovery from these ultra-tight gas reservoirs. It is important to clearly understand the effect of known mechanisms on shale gas reservoir performance. This article presents the pressure transient analysis (PTA) and rate decline analysis (RDA) on the hydraulic fractured vertical wells with finite conductivity in shale gas reservoirs considering multiple flow mechanisms including desorption, diffusive flow, Darcy flow and stress sensitivity. The PTA and RDA models were established firstly. Then, the source function, Laplace transform, and the numerical discrete methods were employed to solve the mathematical model. At last the type curves were plotted and different flow regimes were identified. The sensitivity of adsorption coefficient, storage capacity ratio, inter-porosity flow coefficient, fracture conductivity, fracture Skin Factor, and stress sensitivity were analyzed. This work is important to understand the transient pressure and rate decline behaviors of hydraulic fractured vertical wells with finite conductivity in shale gas reservoirs
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Production Performance Analysis of Tight Oil/Gas Reservoirs Considering Stimulated Reservoir Volume using Elliptical Flow
'Elsevier BV', 2015Co-Authors: Xu Jianchun, Guo Chaohua, Wei Mingzhen, Teng Wenchao, Jiang RuizhongAbstract:Most tight oil/gas reservoirs are naturally fractured with dual-porosity characteristics. After fracturing or re-fracturing, the stimulated reservoir volume (SRV) always exists around the wellbore. This paper demonstrates a composite elliptical mathematical model to analyze the pressure transient and rate transient behaviors in tight oil/gas reservoirs with SRV. This model focuses on two main dual-porosity media regions which are the inner region and outer region divided based on micro-seismic observation. The inner region which has higher flow capacity characterizes the SRV. The inter-porosity flow between matrix and fracture was assumed as unsteady flow for both the inner region and outer region. We solve the model with the elliptical flow model and using Mathieu modified functions, Laplace transform, and Stehfest algorithm comprehensively. The model solution was verified with previous work thoroughly. Also, we presented the pressure transient and rate transient type curves based on which seven flow regimes were recognized including the early wellbore storage period, Skin Factor period, linear flow period, transfer flow period, first radial flow period, transition flow period, and later radial flow period. Then, effect of four related parameters including SRV size, outer region fracture permeability, fracture half-length, and inner region matrix radius on tight oil/gas transient behavior were investigated. At last, we tested the model with field cases to analyze fractured wells performance in tight reservoirs. History matching results were shown according to real production data and micro-seismic results. The presented model and obtained results can enrich the production performance analysis methods for tight oil and gas reservoirs
Jan Ziaja - One of the best experts on this subject based on the ideXlab platform.
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hydraulic fracturing new uncertainty based modeling approach for process design using monte carlo simulation technique
PLOS ONE, 2020Co-Authors: Awad Ahmed Quosay, Dariusz Knez, Jan ZiajaAbstract:Hydraulic fracturing is a key method used in completion of shale gas wells as well as in well stimulation. There are a lot of Factors affecting the hydraulic fracturing treatment; i.e. formation in-situ stresses, fracturing fluid properties, proppant, pumping rate, reservoir fluid and rock properties…etc. For predictive modeling, these Factors are associated with a lot of uncertainties, since most of them are laboratory measured, calculated or subjectively estimated. Moreover, the precise contribution of each Factor on the final fracturing result is unknown for each individual case. Therefore, for better treatment performance and in order to find the best range of designing parameters, a hydraulic fracturing predictive model that involves these uncertainties is required specially for newly exploited shale gas reservoir. In this paper a new uncertainty-based approach is described for hydraulic fracturing processes. It is based on assigning probability distribution for some variables and parameters used in the designing process. These probability distributions are used as input data for analytical equations that describe the fracturing processes. Monte Carlo Simulation technique is used to apply uncertainty-based values on the designing analytical formulas. A hypothetical hydraulic fracturing example is used to simulate the effect of different variables and designing parameters on the entire fracturing process. The simulation results are illustrated into probability distribution curves and variance-based sensitivity analysis is performed to assess the contribution and the correlation between different variables and outcomes. Fracture geometry is almost controlled by the injection fluid's viscosity, in case of constant injection rate; while rock properties have insignificant effect on the fracture width compares to fracturing fluid's effect. Therefore more emphases shall be directed to rheological modeling of the fracturing fluid. It is found also that fracture height, which is difficult to be estimated, is the most crucial parameter in the calculation of treatment size or the injected fluid's volume. Proppant porosity, injected fluid viscosity and formation strength are slightly affecting propped fracture width, while proppant final concentration plays the main role of determining the calculated propped fracture width. It is observed from the simulation results that the initial formation permeability will extremely affect the post fracturing Skin Factor while other formation rock properties have almost no effect on the Skin Factor. Throughout the implementation of the uncertainty-based modeling approach for hydraulic fracturing process design, it is found that uncertainties in the value of many variables and parameters are slightly affecting the process outcomes. However, injected fluid viscosity, shale formation permeability and proppant final concentration are found to be the most influencing Factors in the entire process. Therefore, it is highly recommended to perform in-depth study for these Factors prior conducting any designing process of hydraulic fracturing.
A. Malallah - One of the best experts on this subject based on the ideXlab platform.
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Rate Derivative Analysis of Oil Wells Intercepted by Finite Conductivity Hydraulic Fracture
2015Co-Authors: I.s. Nashawi, A. MalallahAbstract:filed in writing with the technical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will be considered for publication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to correction. Early time conventional transient pressure test data are generally influenced by wellbore storage effects. These effects prohibit good formation description of the area in the vicinity of the wellbore. One of the advantages of constant bottomhole pressure tests is that they are immune of these effects. This study presents an analysis method for finite conductivity fractured oil wells producing at constant bottomhole pressure from closed systems. The reciprocal rate and reciprocal rate derivative data are used to calculate the fracture and reservoir parameters. Bilinear, pseudo-radial, and pseudosteady state flow regimes are analyzed using log-log plots of the reciprocal rate and reciprocal rate derivative data. The slopes of the straight lines of the various flow regimes are used to determine reservoir and fracture parameters such as fracture conductivity, reservoir permeability, Skin Factor, drainage area, and shape Factor. A 0.65 slope straight-line equation describing the transition between the pseudo-radial and the pseudosteady state periods in rectangular systems is presented. This straight line can be used to either determine the formation permeability in the absence of the pseudo-radial flow, or calculate the drainage area. Moreover, the intersection points of the various straight lines can be used to verify the accuracy of the results obtained from the different flow regimes. A systematic step-by-step procedure showing the methodology of the proposed technique is illustrated using two simulated cases
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Rate Derivative Analysis of Oil Wells Intercepted by Finite Conductivity Hydraulic Fracture
Canadian International Petroleum Conference, 2006Co-Authors: I.s. Nashawi, A. MalallahAbstract:Early time conventional transient pressure test data are generally influenced by wellbore storage effects. These effects prohibit good formation description of the area in the vicinity of the wellbore. One of the advantages of constant bottomhole pressure tests is that they are immune of these effects. This study presents an analysis method for finite conductivity fractured oil wells producing at constant bottomhole pressure from closed systems. The reciprocal rate and reciprocal rate derivative data are used to calculate the fracture and reservoir parameters. Bilinear, pseudo-radial, and pseudosteady state flow regimes are analyzed using log-log plots of the reciprocal rate and reciprocal rate derivative data. The slopes of the straight lines of the various flow regimes are used to determine reservoir and fracture parameters such as fracture conductivity, reservoir permeability, Skin Factor, drainage area, and shape Factor. A 0.65 slope straight-line equation describing the transition between the pseudo-radial and the pseudosteady state periods in rectangular systems is presented. This straight line can be used to either determine the formation permeability in the absence of the pseudo-radial flow, or calculate the drainage area. Moreover, the intersection points of the various straight lines can be used to verify the accuracy of the results obtained from the different flow regimes. A systematic step-by-step procedure showing the methodology of the proposed technique is illustrated using two simulated cases.
Kui Zhao - One of the best experts on this subject based on the ideXlab platform.
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A new production prediction model for multistage fractured horizontal well in tight oil reservoirs
Advances in Geo-Energy Research, 2020Co-Authors: Kui ZhaoAbstract:To better evaluate the production performance of tight oil reservoirs, it is urgent to solve the multistage fractured horizontal well production enigma. It is paramount to develop new models to analyze the well performance for tight oil reservoirs. In this paper, a new production prediction model of multistage fractured horizontal well in tight oil reservoir was established. In this model, unsteady transfer flow between fracture and matrix was considered. This model was solved by using Laplace transform method, line source function and Stehfest method comprehensively. The production prediction type curves including pressure transient analysis curves and rate transient analysis curves were then obtained. According to these type curves, eight flow regimes were obtained as early wellbore storage period, Skin Factor period, bi-linear flow regime, linear flow regime, first radial flow regime, transition flow regime, transfer flow regime and later radial flow regime. In the end, a field case history matching result was given and four key parameters’ effect on tight formation well production was analyzed. This research is of both theoretical significance and practical value for tight oil development. Cited as : Zhao, K., Du, P. A new production prediction model for multistage fractured horizontal well in tight oil reservoirs. Advances in Geo-Energy Research, 2020, 4(2): 152-161, doi: 10.26804/ager.2020.02.04
