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Christopher R Clarkson - One of the best experts on this subject based on the ideXlab platform.
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semi analytical model for matching flowback and early time production of multi fractured horizontal tight oil wells
SPE AAPG SEG Unconventional Resources Technology Conference, 2016Co-Authors: Christopher R Clarkson, Farhad Qanbari, J D WilliamskovacsAbstract:Abstract Analysis of multi-fractured horizontal well (MFHW) production data completed in low-permeability (tight) oil reservoirs has traditionally focused on long-term (online) production after the initial flowback period. Recent studies, however, have demonstrated that important information about hydraulic fractures can be ascertained from flowback data and simulation studies are now being designed to model flowback along with the online production. In this work, a new semi-analytical model is developed specifically for modeling water and hydrocarbon production during flowback and early-time production for tight oil wells. Two flow regions are assumed: a primary hydraulic fracture (PHF) and an enhanced fracture region (EFR) adjacent to the hydraulic fracture, where reservoir permeability has been enhanced due to stimulation. Alternatively, a non-stimulated matrix region (NSR), where reservoir permeability is not enhanced due to stimulation, may be placed adjacent to the PHF. A coupled PHF-EFR model is created by assigning the average Pressure in the PHF as the inner boundary condition of the EFR, and wellbore Flowing Pressure as the inner boundary-condition for PHF. If the initial fracture Pressure is greater than reservoir Pressure, the coupled model forecasts initial production to be single-phase flow of fracturing fluid, followed by two-phase flow of fracturing fluid and formation oil from the EFR to the PHF after breakthrough to the fracture. Transient flow of fluids through the PHF and EFR is modeled with the dynamic drainage area approach. Equations of coupled flow/material balance are solved iteratively at each timestep. Stress-dependent properties of fractures and matrix are handled in the solution. The robustness of this innovative approach is tested through comparison with more rigorous numerical simulation, and its practicality demonstrated with a field example. The new technique should serve as a useful tool for petroleum engineers responsible for forecasting tight oil wells exhibiting these complexities.
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production data analysis of unconventional gas wells review of theory and best practices
International Journal of Coal Geology, 2013Co-Authors: Christopher R ClarksonAbstract:Abstract Unconventional gas reservoirs, including coalbed methane (CBM), tight gas (TG) and shale gas (SG), have become a significant source of hydrocarbon supply in North America, and interest in these resource plays has been generated globally. Despite a growing exploitation history, there is still much to be learned about fluid storage and transport properties of these reservoirs. A key task of petroleum engineers and geoscientists is to use historical production (reservoir fluid production rate histories, and cumulative production) for the purposes of 1) reservoir and well stimulation characterization and 2) production forecasting for reserve estimation and development planning. Both of these subtasks fall within the domain of quantitative production data analysis (PDA). PDA can be performed analytically, where physical models are applied to historical production and Flowing Pressure data to first extract information about the reservoir (i.e. hydrocarbon-in-place, permeability-thickness product) and stimulation (i.e. skin or hydraulic fracture properties) and then generate a forecast using a model that has been “calibrated” to the dynamic data (i.e. rates and Pressures). Analytical production data analysis methods, often referred to as rate-transient analysis (RTA), utilize concepts analogous to Pressure-transient analysis (PTA) for their implementation, and hence have a firm grounding in the physics of fluid storage and flow. Empirical methods, such as decline curve analysis, rely on empirical curve fits to historical production data, and projections to the future. These methods do not rigorously account for dynamic changes in well operating conditions (i.e. Flowing Pressures), or reservoir or fluid property changes. Quantitative PDA is now routinely applied for conventional reservoirs, where the physics of fluid storage and flow are relatively well-understood. RTA has evolved extensively over the past four decades, and empirical methods are now applied with constraints and “rules of thumb” developed by researchers with some confidence. For unconventional reservoirs, these techniques continue to evolve according to our improved understanding of the physics of fluid storage and flow. In this article, the latest techniques for quantitative PDA including type-curve analysis, straight-line (flow-regime) analysis, analytical and numerical simulation and empirical methods are briefly reviewed, specifically addressing their adaptation for CBM and SG reservoirs. Simulated and field examples are provided to demonstrate application. It is hoped that this article will serve as practical guide to production analysis for unconventional reservoirs as well as reveal the latest advances in these techniques.
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analysis of production data in shale gas reservoirs rigorous corrections for fluid and flow properties
Journal of Natural Gas Science and Engineering, 2012Co-Authors: Morteza Nobakht, Christopher R ClarksonAbstract:Abstract Analysis of long-term linear flow periods associated with shale gas production has received much attention in recent literature as a means of obtaining information about stimulation efficiency. However, the most popular methods for analysis (ex. square-root-of-time plot) can lead to incorrect characterization. Nobakht and Clarkson (2011a) demonstrated that the square-root-of-time plot may not be a straight line for constant gas rate production linear flow and the non-linear shape may lead to incorrect flow regime identification. The square-root-of-time plot is however a straight line for constant Flowing Pressure ( Nobakht and Clarkson, 2011b ). Ibrahim and Wattenbarger, 2005 , Ibrahim and Wattenbarger, 2006 and Nobakht and Clarkson (2011b) showed that using the slope of square-root-of-time plot, for constant Flowing Pressure constraint, leads to an overestimation of fracture half-length. Additional important considerations for shale gas analysis are non-Darcy flow and non-static reservoir properties. Clarkson et al. (2011) demonstrated that ignoring gas-slippage effects, thought to be important in ultra-low permeability reservoirs, can cause errors in reservoir characterization. They incorporated slippage into pseudo-variables for production data analysis, as has been done with non-static permeability ( Thompson et al., 2010 ). Finally, Nobakht et al. (2011) extended the methodology proposed by Nobakht and Clarkson (2011b) to properly analyze linear flow in the presence of slippage and desorption. The purpose of the current work is to evaluate the current methods for analyzing linear flow in shale gas reservoirs, and establish which method is the most accurate for reservoir characterization. First, recent studies addressing linear flow under constant Flowing Pressure and constant gas rate production are briefly reviewed. Then, a comparison among the above-mentioned methods for calculating fracture half-length or contacted matrix surface area is made. It is shown that Nobakht et al. (2011) method yields the fracture half-lengths that best match the expected values for constant Flowing Pressure. Finally, we present a method for analyzing linear flow for real production data, where neither Flowing Pressure nor gas rate is constant. The method is validated using three numerically-simulated cases. It is found that this method works well for the three cases provided.
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a new analytical method for analyzing linear flow in tight shale gas reservoirs constant Flowing Pressure boundary condition
Spe Reservoir Evaluation & Engineering, 2012Co-Authors: Morteza Nobakht, Christopher R ClarksonAbstract:Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-oftime plot, a plot of rate-normalized Pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability. In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-Flowing-Pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial Pressure, Flowing Pressure, and formation compressibility. An analytical method is presented to correct the slope of the squareroot-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant Flowing Pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.
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integration of microseismic and other post fracture surveillance with production analysis a tight gas study
Journal of Natural Gas Science and Engineering, 2011Co-Authors: Christopher R Clarkson, Joshua BeierleAbstract:Abstract Quantitative production analysis of tight gas reservoirs has historically been a challenge due to complex reservoir characteristics (ex. lateral and vertical heterogeneity, stress-sensitivity of permeability and porosity), induced hydraulic fracture properties in vertical wells (ex. multi-phase flow, conductivity changes, complex fracture geometries), operational complexities (ex. variable back-Pressure, liquid-loading) and data quality (infrequent rate or Flowing Pressure reporting). All of these challenges conspire to make extraction of reservoir ( kh and OGIP ) and hydraulic fracture properties ( x f and fracture conductivity) soley from production/Flowing Pressure data difficult, often resulting in non-unique answers. In recent history, there has been the added complication that tight gas (and most recently shale gas) reservoirs are now being exploited with horizontal wells, often stimulated using multiple hydraulic fracture stages, which imparts greater complexity on the analysis. Flow regime identification, which is critical to the correct analysis, is more complicated than ever owing to the number of possible flow regimes encountered in such wells. A case study is presented in which it is demonstrated that modern post-fracture surveillance data, such as microseismic and post-frac production logging, aids in both model identification and model calibration, which is critical to the analysis of hydraulically-fractured horizontal wells completed in tight gas formations. A workflow is presented in which offset vertical wells (to the horizontal wells) are first analyzed to obtain estimates of kh and hydraulic fracture properties, followed by commingled stage and single-stage production analysis of the multi- (transverse) hydraulic fracture horizontal wells. Microseismic data is incorporated into the analysis of the horizontal wells to 1) understand the orientation and degree of complexity of the induced hydraulic fractures and 2) constrain interpretations of effective hydraulic fracture lengths from production data analysis. It is also demonstrated that once the commingled stage analysis of the horizontal wells is completed, the total interpreted effective hydraulic fracture half-length may be allocated amongst the stages using a combination of production logs and tracer logs. The primary contribution of the current work is the presentation of workflows, emphasizing the integration of various data sources, to improve production analysis of multi-frac’d horizontal wells completed in tight gas formations. In addition to the workflows, it is shown that a combination of advanced production analysis approaches, including methods analogous to classic Pressure transient analysis, production type-curve matching and simulation, may be necessary to arrive at a unique analysis.
Morteza Nobakht - One of the best experts on this subject based on the ideXlab platform.
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analysis of production data in shale gas reservoirs rigorous corrections for fluid and flow properties
Journal of Natural Gas Science and Engineering, 2012Co-Authors: Morteza Nobakht, Christopher R ClarksonAbstract:Abstract Analysis of long-term linear flow periods associated with shale gas production has received much attention in recent literature as a means of obtaining information about stimulation efficiency. However, the most popular methods for analysis (ex. square-root-of-time plot) can lead to incorrect characterization. Nobakht and Clarkson (2011a) demonstrated that the square-root-of-time plot may not be a straight line for constant gas rate production linear flow and the non-linear shape may lead to incorrect flow regime identification. The square-root-of-time plot is however a straight line for constant Flowing Pressure ( Nobakht and Clarkson, 2011b ). Ibrahim and Wattenbarger, 2005 , Ibrahim and Wattenbarger, 2006 and Nobakht and Clarkson (2011b) showed that using the slope of square-root-of-time plot, for constant Flowing Pressure constraint, leads to an overestimation of fracture half-length. Additional important considerations for shale gas analysis are non-Darcy flow and non-static reservoir properties. Clarkson et al. (2011) demonstrated that ignoring gas-slippage effects, thought to be important in ultra-low permeability reservoirs, can cause errors in reservoir characterization. They incorporated slippage into pseudo-variables for production data analysis, as has been done with non-static permeability ( Thompson et al., 2010 ). Finally, Nobakht et al. (2011) extended the methodology proposed by Nobakht and Clarkson (2011b) to properly analyze linear flow in the presence of slippage and desorption. The purpose of the current work is to evaluate the current methods for analyzing linear flow in shale gas reservoirs, and establish which method is the most accurate for reservoir characterization. First, recent studies addressing linear flow under constant Flowing Pressure and constant gas rate production are briefly reviewed. Then, a comparison among the above-mentioned methods for calculating fracture half-length or contacted matrix surface area is made. It is shown that Nobakht et al. (2011) method yields the fracture half-lengths that best match the expected values for constant Flowing Pressure. Finally, we present a method for analyzing linear flow for real production data, where neither Flowing Pressure nor gas rate is constant. The method is validated using three numerically-simulated cases. It is found that this method works well for the three cases provided.
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a new analytical method for analyzing linear flow in tight shale gas reservoirs constant Flowing Pressure boundary condition
Spe Reservoir Evaluation & Engineering, 2012Co-Authors: Morteza Nobakht, Christopher R ClarksonAbstract:Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-oftime plot, a plot of rate-normalized Pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability. In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-Flowing-Pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial Pressure, Flowing Pressure, and formation compressibility. An analytical method is presented to correct the slope of the squareroot-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant Flowing Pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.
Liu Kouqi - One of the best experts on this subject based on the ideXlab platform.
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Research of water control technology for horizontal wells in water-driven reservoirs
Advances in Geo-Energy Research, 2018Co-Authors: Shang Baobing, Han Xiaodong, Li Shuai, Liu KouqiAbstract:Horizontal wells are widely applied in the Bohai offshore oil fields due to their large oil drainage areas and high yields. However, water coning is a significant problem existing in water-driven reservoirs. To control water coning, this paper introduces a stinger completion method which can be applied in the horizontal wells. Based on the principle of mirror reflection and mass conservation law, a mathematical model coupling fluid flow both in the reservoir and in the horizontal wellbore has been developed. Using the new proposed model, the well production profile and bottom hole Flowing Pressure distribution along the horizontal well, considering the influence of Flowing in the wellbore, are calculated successfully. Moreover, the influence of the stinger completion on the inflow profile is investigated. According to the results of the sensitivity analysis, a 160 m’ 2-7/8 tubing is designed to be built in the horizontal section. The field-test results show that the stinger completion could be used to improve the wellbore inflow profile and decrease the possibility of water-cut thus increasing the effective enhanced oil recovery (EOR).Cited as: Shang, B., Han, X., Li, S., Liu, K. Research of water control technology for horizontal wells in water-driven reservoirs. Advances in Geo-Energy Research, 2018, 2(2): 210-217, doi: 10.26804/ager.2018.02.08
Bin Yuan - One of the best experts on this subject based on the ideXlab platform.
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a new analytical multi linear solution for gas flow toward fractured horizontal wells with different fracture intensity
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Bin Yuan, Rouzbeh Ghanbarnezhad Moghanloo, Zhenhua Rui, Wendong Wang, Yangyang ShangAbstract:Abstract This paper presents a new analytical solution to study the interplay between Flowing Pressure and production rate for horizontal wells completed within stimulated reservoir volumes (SRV) in tight gas reservoirs. Field practice has shown that all fracturing stages are not effective in production; this has been explained through varying fracture intensity inside and outside of SRVs along the well (fully fractured zone, partially activated zone and non-activated zone). Despite the existing solutions, the novelty of this model is in integrated approach to consider fracturing stages with different fracture intensity, consistent with observations in the field. In addition, the presented model considers wellbore storage effects, stress-dependent and non-Darcy flows considering threshold Pressure gradient. Implementing the Laplace transform technique, our multi-linear analytical solution is obtained from the diffusivity equation. We validate the analytic solution with field data; our results are consistent with the field observation. A sensitivity analysis is conducted to study impacts of fracture intensity, threshold Pressure gradient, compaction, and size of the stimulated reservoir volume (SRV) on appearance of different flow patterns and ultimate well productivity. Our results suggest a relation between SRV aspect ratio and occurrence of various flow patterns when fracture intensity is changing along the well. In practice, this septa-linear flow model is simple, practical and time-efficient for the transient Pressure analysis and production prediction. Furthermore, this work is one step forward to make the analytic solutions more realistic by incorporating different fracture intensity of each fracturing stage.
Mohsen Masihi - One of the best experts on this subject based on the ideXlab platform.
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new technique for calculation of well deliverability in gas condensate reservoirs
Journal of Natural Gas Science and Engineering, 2010Co-Authors: Sadeghi A Boogar, Mohsen MasihiAbstract:Abstract Well deliverability is an important issue in forecasting the performance of many gas condensate reservoirs. Condensate accumulations near the wellbore may cause a significant reduction in the well productivity, even in the case of very lean fluids. Generally, the well deliverability is affected by two Pressure-drop sources due to depletion and condensate buildup. Recently rapid spreadsheet tools have been developed to evaluate the well performance using material balance equation for depletion and two-phase pseudo Pressure integral for well inflow performance. Most of them account for the effects of negative inertia and positive coupling in the calculation of gas relative permeabilities. This paper introduces a new method for calculation of well productivity in gas condensate reservoirs. This method uses the concept of two-phase pseudo Pressure integral without any need to estimate the radius of two-phase region. In this approach the average reservoir Pressure is calculated by using a general material balance equation. The only data required for implementing this method is PVT data, relative permeability curves and a table of well Flowing Pressure versus time. The new technique can be encoded on a spreadsheet in order to forecast the gas condensate well performance very rapidly. To validate the proposed approach we have used several single-well fine grid compositional simulations of a hypothetical reservoir model over a typical range of gas condensate reservoir parameters. We have shown that there is a reasonable agreement between the result of fine grid simulation and the prediction from the proposed approach.