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In order to explore the effect of well spacing on the uranium leaching efficiency in acid in-situ leaching, taking the Bayan Ula mining area as an example, and using the finite element method to establish a numerical model for acid in-situ leaching uranium mining, and discuss the coverage and flow rate of the leaching solution. Through the comparison and analysis of 26 schemes, the influence of different well spacing on uranium leaching was discussed from three aspects; well site cost, uranium leaching cycle, and leaching dead angle. The results show that; 1) The fixed cost of the mining area varies with the well. 2) The characteristic flow velocity in the mining area decreases with the increase of the well spacing, and the relative uranium leaching period increases with the increase of the well spacing; 3) With the increase of the well spacing, the volume of the leaching dead angle increases approximately exponentially. Comprehensive consideration, under the simulation conditions in this paper, it is considered that 26 meters to 30 meters is the optimal well spacing for uranium leaching. The results can provide a reference for the reasonable layout of subsequent ground leaching process hoes in this mine area. [ABSTRACT FROM AUTHOR]

Appropriate well spacing is crucial for the efficient development of shale reservoirs, as it is closely related to the degree of resource utilization. Well spacing design is influenced by both fracturing processes and geological characteristics. While increasing well density can enhance reservoir recovery, it may lead to higher investment costs and significant well interference issues. In this study, we adopted an integrated geological–engineering approach, combining fracture propagation simulation, EDFM (Embedded Discrete Fracture Modeling), and numerical simulation methods to comprehensively analyze well interference under different well spacings in shale condensate reservoirs. Development well spacing was optimized using the degree of resource utilization and well interference rate as key indicators. There are three main research findings: (1) The geological engineering integration approach allows for differentiated well spacing according to specific research areas. Combining this integrated approach with EDFM and leveraging quantitative evaluation, we have developed an efficient and precise methodology for well spacing optimization. (2) When well spacing is less than the length of hydraulic fractures, inter-well fractures exhibit an entangled pattern, reducing the effectiveness of fracturing treatments and causing severe well interference. As well spacing increases, interference between fractures from different wells diminishes, but unstimulated volumes gradually emerge, leading to a decrease in reservoir recovery. (3) Considering both well interference and resource utilization, a well spacing of 400 m is recommended in the study area. At this spacing, interference between hydraulic fractures from different wells is minimal. After 10 years of production, the estimated reservoir recovery is 39.16%, with a production rate of 25.58% and a well interference rate of 13.58%. These research outcomes provide valuable insights for optimizing the well spacing of hydraulic fractured horizontal wells in shale condensate reservoirs.

Abstract The design of well spacing significantly influences the sustainability and economic benefit of geothermal energy extraction. However, most studies have predominantly employed heat production-related parameters as indicators of well spacing, and a comprehensive analysis of well spacing design based on an economic model is necessary for practical implementation. In this study, an economic indicator considering the benefits derived from heat production and operating costs is proposed and applied in the Caofeidian, a typical abandoned oilfield in the Bohai Bay Basin. It offers a refined portrayal of directional wells, moving beyond rudimentary representations, to capture their appropriate degree of complexity and behavior in drilling configurations. First, by integrating thermophysical information and site investigation data from previous oil investigations, a heterogeneous 3D model is constructed to forecast the 30-year temperature and pressure evolution. Then, a modified levelized cost of heat (LCOH-HT) is proposed to perform economic analysis in optimizing the well spacing, revealing an optimal range of 300–600 m for the different selected wells. In comparison with results derived solely from heat production considerations, drilling and pumping costs contribute to a 300 m reduction in the optimal well spacing based on the proposed approach, as a larger well spacing leads to increased hydraulic losses and drilling cost, necessitating greater pumping efforts and costs. This finding underscores the need to balance economic and thermal considerations. In addition, we found the difference in the optimal well spacing in space is also caused by the porosity variations. Porosity affects fluid temperature and pressure, leading to changes in the benefits and costs associated with pressure fluctuations. Notably, this novel economic analysis method is not limited to spacing optimization; it can also be used to optimize operating parameters, such as the flow rate, which could provide practical strategies for geothermal energy extraction.

The design of well spacing significantly influences the sustainability and economic benefit of geothermal energy extraction. However, most studies have predominantly employed heat production-related parameters as indicators of well spacing, and a comprehensive analysis of well spacing design based on an economic model is necessary for practical implementation. In this study, an economic indicator considering the benefits derived from heat production and operating costs is proposed and applied in the Caofeidian, a typical abandoned oilfield in the Bohai Bay Basin. It offers a refined portrayal of directional wells, moving beyond rudimentary representations, to capture their appropriate degree of complexity and behavior in drilling configurations. First, by integrating thermophysical information and site investigation data from previous oil investigations, a heterogeneous 3D model is constructed to forecast the 30-year temperature and pressure evolution. Then, a modified levelized cost of heat (LCOH-HT) is proposed to perform economic analysis in optimizing the well spacing, revealing an optimal range of 300–600 m for the different selected wells. In comparison with results derived solely from heat production considerations, drilling and pumping costs contribute to a 300 m reduction in the optimal well spacing based on the proposed approach, as a larger well spacing leads to increased hydraulic losses and drilling cost, necessitating greater pumping efforts and costs. This finding underscores the need to balance economic and thermal considerations. In addition, we found the difference in the optimal well spacing in space is also caused by the porosity variations. Porosity affects fluid temperature and pressure, leading to changes in the benefits and costs associated with pressure fluctuations. Notably, this novel economic analysis method is not limited to spacing optimization; it can also be used to optimize operating parameters, such as the flow rate, which could provide practical strategies for geothermal energy extraction. [ABSTRACT FROM AUTHOR]

Optimal spacing for vertical wells can be effectively predicted with several published methods, but methods suitable for assessing the proper horizontal well spacing are rare. This work proposes a method for calculating the optimal horizontal well spacing for an ultra-low permeability reservoir e the Yongjin reservoir in the Juggar Basin, northwestern China. The result shows that a spacing of 640m is the most economical for the development of the reservoir. To better develop the reservoir, simulation approaches are used and a new model is built based on the calculated well spacing. Since the reservoir has an ultralow permeability, gas injection is regarded as the preferred enhanced oil recovery (EOR) method. Injection of different gases including carbon dioxide, methane, nitrogen and mixed gas are modelled. The results show that carbon dioxide injection is the most efficient and economical for the development of the reservoir. However, if the reservoir produces enough methane, reinjecting methane is even better than injecting carbon dioxide. [ABSTRACT FROM AUTHOR]

Design and optimization of well spacing is a key indicator for evaluating the development effect of shale gas reservoirs. On the basis of theoretical understanding, and after the verification by analogy, numerical simulation, and economic evaluation, a complete workflow from inter-well interference simulation and dynamic data diagnosis to multi-well production simulation and well spacing optimization was formed. First, a pressure detection boundary propagation model is established to simulate the response degree of inter-well interference under different connected conditions. Second, inter-well interference is identified and diagnosed depending on the inter-well interference response behaviors and the interpretation of performance data from gas wells. Third, taking the geological interpretation and dynamic analysis results as basic parameters, a multi-well numerical model for volume fracturing in gas reservoirs is established to simulate the production performance of gas field, and then well spacing is optimized in combination with the net present value model. The application in the Ning 201 well block in the Changning National Shale Gas Demonstration Area has shown that a smaller well spacing can allow a premature inter-well interference and also the enhancement of recovery in the entire block. Given the current fracturing scale and parameter system, the well spacing of 300–400 m can be optimized to 260–320 m, that is, the number of wells per unit area increases by 20%–30%. As a result, the recovery percent of reserves in the block increase by about 10%. The net present value of the block rises, but the corresponding optimal well spacing does not change, with the production period.

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The features of bad flow unit continuity and multiple layers emphesize the importance of a well pattern design for the development of a fluvial-delta reservoir. It is proposed a method to predict well pattern connectivity (WPC) based on the exploration and evaluation of wells. Moreover, the method helps evaluate the risk of well placement. This study initially establishes the parameters for characterizing the lateral and vertical flow unit distributions. Then, extensive statistics on the mature oil-field sands of synthetic geological models are obtained to generate the prediction model of WPC which will reveal the correlation among WPC, flow unit distribution, and well spacing (WS). Finally, a case study is conducted to validate the proposed method for predicting WPC. The procedure of the method is comprised of two steps. The first step is to calculate the parameters which characterize the vertical sand body distribution of the target formation by using the well drilling and logging information. The second step is to integrate the calculated parameters and designed WS into the proposed formula to forecast WPC. The new method of WPC prediction has the advantage of integrating the static and dynamic information of similar mature oil fields with each other. By utilizing the model, making an important decision on well pattern design and a reservoir production forecast in the newly discovered continental fluvial-delta reservoir would be reasonable.

At present, investigation of the effects of natural fractures on optimal well spacing of shale gas reservoirs from an economic perspective has been lacking. Traditional frameworks of fracture characterization, such as local grid refinement, make it unfeasible and inaccurate to study these effects of high-density natural fractures with complex geometries on well spacing. In this study, the non-intrusive EDFM (embedded discrete fracture model) method was presented to characterize fractures fast and accurately. The non-intrusiveness of EDFM removed the necessity of accessing the codes behind reservoir simulators, which meant it could simply create associated keywords that would correspondingly modify these fracture properties in separate files without information regarding the source codes. By implementing this powerful technology, a field-scale shale gas reservoir model was set up, including two-phase flow. The effective properties of hydraulic fractures were determined from the history matching process, and the results were entered into the well spacing optimization workflow. Different scenarios of natural fracture (NF) distributions and well spacing were designed, and the final economic analysis for each case was explored based on simulated productions. As a result, one of the findings of this study was that optimal well spacing tended to increase if more natural fractures were presented in the reservoir.

This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve).

Abstract: Reasonable well spacing has been studied and assessed to increase the reserves and improve the recovery factor of the Sulige gas field, where the reserves controlled by single well are small. An evaluation methodology for optimizing well spacing in a tight sandstone gas field was established from five aspects including geologic model, drainage radius, interference testing, numerical simulation and economic benefits. The well spacing has been optimized using this method. Through geological modeling, the rational inter-well distance is estimated to be less than 600 m and rational well array distance should be less than 1 000 m. Results of drainage areas estimation reveal that the rational inter-well distance should be ranged from 400 m to 600 m. Analysis of interference well test shows that the low limit for inter-well distance is 400 m and the favorable well array distance is 600 m. Numerical simulation and economic evaluation shows that an inter-well distance of 500 m and well array distance of 700 m are favorable. It is concluded from the above five aspects that, in current economic and technological conditions, the well pattern with inter-well distance at 500 m and well array distance at 700 m is rational in the Sulige gas field, and it can improve the recovery factor to 45%. [Copyright &y& Elsevier]

Abstract: To optimize well spacing and injection rate in horizontal well flood pattern, formulae of the reasonable injection rate and well spacing are derived under fraction and no-fraction conditions respectively using filtration theory. The formulae take into account the fluid flow in low-permeability and thin reservoirs, and assume that horizontal well injection is rigid water driving. According to these formulae, the influencing factors of pressure loss on the horizontal section are diameter of casing pipe, production rate, and length of horizontal section. For a well with fixed casing diameter and horizontal section length, the influencing factors of pressure loss on horizontal section is only production or injection rate; for a reservoir, the influencing factors of maximal well space are length of horizontal section, oil production rate and water injection rate. The research results are applied in the Hade 4 thin layer sandstone reservoir of Tarim Oilfield. The designed flood pattern decreases injection pressure, augments injection, and keeps field pressure. [Copyright &y& Elsevier]

At present, investigation of the effects of natural fractures on optimal well spacing of shale gas reservoirs from an economic perspective has been lacking. Traditional frameworks of fracture characterization, such as local grid refinement, make it unfeasible and inaccurate to study these effects of high-density natural fractures with complex geometries on well spacing. In this study, the non-intrusive EDFM (embedded discrete fracture model) method was presented to characterize fractures fast and accurately. The non-intrusiveness of EDFM removed the necessity of accessing the codes behind reservoir simulators, which meant it could simply create associated keywords that would correspondingly modify these fracture properties in separate files without information regarding the source codes. By implementing this powerful technology, a field-scale shale gas reservoir model was set up, including two-phase flow. The effective properties of hydraulic fractures were determined from the history matching process, and the results were entered into the well spacing optimization workflow. Different scenarios of natural fracture (NF) distributions and well spacing were designed, and the final economic analysis for each case was explored based on simulated productions. As a result, one of the findings of this study was that optimal well spacing tended to increase if more natural fractures were presented in the reservoir. [ABSTRACT FROM AUTHOR]

This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve). [ABSTRACT FROM AUTHOR]