Day 2 Wed, April 27, 2022最新文献

{"title":"Biogas Produced from Local Waste Reduces the Carbon Intensity of Steam Flooded Oil Production","authors":"Steve Wirtel, P.E., J. Zuback","doi":"10.2118/209247-ms","DOIUrl":"https://doi.org/10.2118/209247-ms","url":null,"abstract":"\u0000 Kore has developed technology that can convert California forestry waste that is an extreme fire hazard and other organic wastes into renewable energy co-products: an energy dense \"biogas\" and a stable, elemental \"biocarbon\" solid. This biogas has a heat value that compares favorably to and can replace or augment natural gas used to produce power, heat, and/or steam. Alternatively the gas can serve as feedstock to produce renewable hydrogen or renewable natural gas. The biocarbon is stable – it will not revert to CO2 or CH4. Burying or blending the carbon into soil can serve as a means of carbon sequestration such that the overall the process is carbon negative and the gas fuels produced have an ultra-low carbon intensity.\u0000 Steam generation traditionally relies on natural gas combustion as the source of heat. When steam is required for enhanced oil recovery, natural gas combustion increases the carbon intensity of the crude oil product, increasing the carbon intensity of fuels refined from California crude oil compared to crude oil imported into the state. By replacing some or all of the natural gas used to generate steam with Kore's carbon negative biogas, the life cycle carbon intensity of refined fuels produced from California heavy crude can be reduced, potentially to a comparable or lower carbon intensity than fuels refined from imported oil.\u0000 Three circumstances unique to California enable this approach to be timely and economically viable: 1) legislation requiring diversion of organic wastes from landfills, 2) the need to beneficially manage forest debris responsible for major fires in California, and 3) legislation enabling credits for decarbonizing transportation fuels (Low Carbon Fuel Standard) that offset the costs of thermal conversion of organic wastes to renewable energy fuels.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134034598","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Water Production from Unconventional Reservoirs: Example from NE Elm Coulee Field - Bakken Formation","authors":"Jan Branning, B. T. Hoffman","doi":"10.2118/209273-ms","DOIUrl":"https://doi.org/10.2118/209273-ms","url":null,"abstract":"\u0000 Production wells within the northeast (NE) Elm Coulee experience significantly higher water cuts than wells within Elm Coulee Proper. The increased water production has a negative economic impact on Bakken operators seeking to maximize profitability within the area. A reservoir engineering-based research project has been conducted to determine the source of the increased water production within the NE Elm Coulee, and to identify recommendations for operators to mitigate the water production related expenses in the area.\u0000 One option for the increased water production is from the water saturation within the matrix of the Middle Bakken Shale, and another possibility is from the Three Forks formation by vertical migration through natural fracture networks. Previous work has identified the presence of natural fracture systems within the Bakken that may be creating flow networks between stratigraphic layers. Numerous flow simulation models of the NE Elm Coulee were constructed to determine the source of the produced water. The reservoir models consist of three hydraulically fractured horizontal wells within the Middle Bakken Shale, and it incorporates the naturally fractured state of the Bakken through a discrete fracture network (DFN).\u0000 Various reservoir parameters were altered within the envelope of uncertainty to obtain a history match for the reservoir model to both scenarios, and the resulting parameters from the Middle Bakken saturation case are more realistic and produce better history matching results than the Three Forks water migration case. The Three Forks fracture model produces an unrealistically high volume of water, and the breakthrough pattern is not consistent with field measurements. Thus, the source of the increased water production appears to come from matrix water saturation within the Middle Bakken Shale.\u0000 Many relevant aspects of unconventional reservoir simulation are incorporated into the project; therefore, the methodology used in the research can help assist reservoir engineers that are modeling unconventional petroleum reservoir with stacked stratigraphic intervals. Modeling natural fractures and complex completion fracture networks using a DFN, pressure dependent permeability, and history matching in unconventional reservoirs are important topics that are discussed in the paper. Operators within the Bakken can use this information to better understand the geologic implications of producing in the area.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123988632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Numerical Model Study of Scale-Dependent Fluid Flow and Storage Systems in Unconventional Reservoirs","authors":"D. Reichhardt, B. T. Hoffman","doi":"10.2118/209298-ms","DOIUrl":"https://doi.org/10.2118/209298-ms","url":null,"abstract":"\u0000 Unconventional reservoirs hold vast amounts of untapped hydrocarbon resources; however, given current production capabilities and our understanding of unconventional reservoir production mechanisms only 5% to 10% of these hydrocarbons are typically recovered. The ability to recover additional hydrocarbons from unconventional reservoirs is dependent on an improved understanding of the production mechanisms which are a function of the complex lithology and reservoir fluid systems, and the interactions between these systems.\u0000 The lithology and fluid systems present in most unconventional reservoirs result in production from several scale-dependent fluid flow and storage systems, or depletion systems, that combine to contribute to the total production. These depletion systems can include matrix level features defined by pore size, natural fracture systems within the matrix, and hydraulic fractures in addition to the traditional depletion systems defined by stacked pay. The fluid phase behavior within these systems also has a scale dependence that must be taken into consideration. As a result, the individual systems tend to deplete at different rates.\u0000 The purpose of this work is to describe the production mechanisms in terms of the lithology and reservoir fluid interactions. By using numerical simulation to systematically isolate production from individual depletion systems, the role and significance of each system is quantified.\u0000 A numerical model was developed to simulate the contributions to total hydrocarbon production from multiple depletion systems. Fluid tracers were placed within each depletion system to isolate the individual system production.\u0000 The results show the stage of production when each depletion system is active and the associated hydrocarbon volumes. For example, the hydraulic fracture system provides most of the initial production, but contribution from the matrix and natural fractures quickly overtakes it. Composite production curves were developed by combining the simulated production contributions from each depletion system, highlighting the influence the different systems have on the total production.\u0000 This paper provides insights into the production contributions from multiple depletion systems found in many unconventional reservoirs. Understanding the roles that the different depletion systems play on production will lead to better well spacing, reserve estimates, and improved reservoir production practices including enhanced oil recovery methods that may be optimized to target the most promising aspects of the reservoir.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129315115","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental Investigation of Foam Flooding Performance in Bulk and Porous Media for Carbonates Under Harsh Conditions","authors":"Ding Xiong, Shehzad Ahmed, W. Alameri, E. Al-Shalabi","doi":"10.2118/209326-ms","DOIUrl":"https://doi.org/10.2118/209326-ms","url":null,"abstract":"\u0000 Foam injection has been promoted as a reliable method for improving the sweep efficiency in heterogeneous carbonate reservoirs by modifying the properties of the injected gas and hence, providing mobility control effect. However, the conditions of the Middle Eastern carbonate reservoirs are quite detrimental to foam performance, leading to unoptimized mobility control. This challenge has motivated the improvement and development of different foaming agent formulations that can withstand the harsh conditions in carbonate reservoirs of high temperature and high salinity. In this study, the effect of different amphoteric and switchable surfactants on bulk foam performance were investigated and later the optimum formulation was evaluated in carbonate porous media for EOR under high salinity and temperature conditions. For this purpose, the solutions containing different commercial amphoteric and amine-based switchable surfactants were prepared in high salinity brine (20 wt%) at high temperature conditions (80 °C). Initial screening was performed by conducting series of foamability and foam stability tests at high temperature. Foam generation and endurance were also investigated in the presence of crude oil. Foam performance was evaluated in carbonate core samples under different foam qualities and at reservoir conditions. After selecting the optimal foam quality for effective foam generation, the oil recovery experiment was then performed to recover the remaining oil after secondary N2-gas flood.\u0000 The results from bulk foam experiments demonstrated the superior properties of betaine-based surfactant (B-1235), in which the highest foam generation and foam stability performance were achieved. Foam endurance of B-1235 was also found comparable to the foam produced by switchable diamine (DTTM) surfactant; however, DTTM surfactant showed poorer foamability performance. In the presence of crude oil, B-1235 surfactant was able to maintain the foam properties, compared to other tested surfactants. The optimum concentrations for B-1235 in the absence and presence of crude oil were found to be 0.25 wt% and 0.5 wt%, respectively. The injection of foam stabilized by the B-1235 was able to pronouncedly increase the mobility reduction factor (MRF) at all the tested foam qualities under high-pressure and high-temperature conditions. Coreflood investigations indicated an optimal foam quality at 70% for all tested surfactant concentrations. The cumulative oil recovery after foam injection was found to be 67%, including 25% tertiary incremental oil recovery by foam flooding. The overall performance of the tested betaine-based surfactant is promising as an effective mobility control during foam EOR process and promotes further application in difficult Middle Eastern carbonate reservoir conditions.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"282 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127717063","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An Analysis of Grid Orientation Effect on Steamflood Simulations","authors":"Xin Li, C. Jensen, Bradley T. Mallison, W. Milliken","doi":"10.2118/209249-ms","DOIUrl":"https://doi.org/10.2118/209249-ms","url":null,"abstract":"\u0000 Grid orientation effect (GOE) is the appearance of preferential flow along grid coordinate directions in numerical reservoir simulation. GOE is most evident in simulations with strong adverse mobility ratios, such as immiscible gas injection and steamfloods. Motivated by previous work, an eleven-point finite difference formulation for multiphase flow is investigated and found to reduce errors for steamfloods using structured grids. The eleven-point formulation is implemented in a parallel, fully-implicit reservoir simulator with thermal, black-oil and compositional formulations, and the implementation supports both local grid refinement (LGR) and dual-porosity, dual-permeability (DPDK) modeling. Systematic tests are performed for compositional steamflood cases with different grid resolutions and grid coordinate angles between wells. A comparison of seven and eleven-point formulation results, using different grid scales and hybrid unstructured grids, demonstrate that the eleven-point scheme is effective in mitigating GOE and can leverage the benefits of structured LGR and DPDK options. Using grid-refinement as a means of reducing GOE is case dependent and is not always successful. Additional results suggest that using grid refinement with local application of the eleven-point scheme around only the injector does help mitigate GOE with increased computational efficiency, but GOE is not reduced as well as when the eleven-point scheme is used in the entire grid-system.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125551701","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir Simulation Framework to Evaluate the Potential Benefit of Radial Jet Drilling Technology Accounting for the Risk of Irreversible Radial Collapse","authors":"V. Torrealba, A. Rey, Geordie Chambers, Michael Goodman, Andrew Kubitza","doi":"10.2118/209279-ms","DOIUrl":"https://doi.org/10.2118/209279-ms","url":null,"abstract":"\u0000 This study presents a reservoir simulation framework to investigate the oil production uplift performance of Radial Jet Drilling (RJD) technology for a naturally fractured diatomite reservoir undergoing waterflooding. The findings from the study can help better design a field trial and plan Surveillance, Analysis and Optimization (SA&O) activities. The framework allows for the flexible definition of various parameters that control the topology of the RJD well (including number penetrated layers, number of radials per layer, and radial segment length) as well as the pressure drop along the radial segment (including the segment roughness and hydrodynamic diameter). The framework relies on advanced wellbore modeling capabilities that compute the pressure drops inside the well; this allows for the consideration of radial segment collapse whenever the radial segment pressure is below a radial collapse pressure.\u0000 The simulated behavior relied on a dual porosity dual permeability (DPDK) reservoir model that had been history-matched for primary depletion and waterflooding over a cumulative 72-year period. The RJD well oil production performance is evaluated over a 16-year period controlled with a bottomhole pressure constraint. The model is calibrated to representative type curves in the absence of radials (perforations only case) and in the presence of radials for a specified topology. Once the model has been calibrated, 162 simulation cases are considered to evaluate the sensitivity of the oil production uplift to various model parameters and operational conditions.\u0000 Radial segment length, radial collapse pressure and number of penetrated layers showed the greatest impact on oil production uplift. Increasing radial segment length and number of penetrated layers and decreasing the radial collapse pressure led to an increase in oil production uplift. We introduced a cumulative radial segment length metric that accounts for the impact of number of penetrated layers, number of radials per layer, and radial segment length. For a fixed cumulative radial segment length, configurations with a higher number of penetrated layers and a lower number of radials per layer led to a higher oil production uplift.\u0000 The simulation tool and framework developed can be used to assess the potential benefit of the RJD technology, including risks arising from radial segment collapse. For all radial collapse pressure scenarios, a gentle drawdown strategy proved to be the most consistent in terms of oil production uplift performance. Production performance monitoring (e.g., via dedicated test separators) can help identify major radial collapse events as evidenced by discontinuous trends in the oil production rate, gas/oil ratio, and/or water cut.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"2013 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128225452","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effective Well Rate Management Using a Streamline-Based Model in Belridge Diatomite Waterflood","authors":"Marilou Tanchuling Guerrero-Lee, Diego Manfre, M. Thiele","doi":"10.2118/209281-ms","DOIUrl":"https://doi.org/10.2118/209281-ms","url":null,"abstract":"\u0000 \u0000 \u0000 In the early 1980's, waterflooding began in Belridge Diatomite (BD), a thick, highly porous, and tight reservoir in California. Over the years, differing injection strategies lead to mixed results. Today, there are approximately 1,900+ injectors and 2,600+ producers in the Belridge Diatomite Waterflood (BDWF) and setting injection and production well rate targets to improve recovery is extremely challenging. Multiple teams using different methods for estimating rate targets in different parts of the field adds complexity to the overall field management strategy. The main objective of this work was to simplify field management by using a quantitative, streamline-based method to establish and quantify injector-producer relationships, reduce human bias, while improving the efficiency and flood performance in the West Grande (WG) area of the BDWF subject to key surface and subsurface constraints.\u0000 The pilot test targeted 52 injection strings and 142 producers in Southern WG with an approximate total water injection rate of 10,500 STB/Day and total water and oil production rates of 8,200 STB/D and 700 STB/D, respectively. An important and novel aspect of the work presented here involves constraining the injection well rate targets to surface elevation, injection string communication, 30-day average wellhead pressure, subsurface impairments, and surface injection capacity. On the production side, the constraints were surface elevation, pump runtime, and operational status. This work describes setting well rate targets using a streamline-based workflow while honoring minimum and maximum rates as deduced from the constraints above.\u0000 Injection and production rates in the WG pilot area were changed four times over nine months in the period May 2020-January 2021. Not withstanding uncertainties in production and watercut measurements and interference due to operational activities, the injection and production rate changes resulted in a reversal of the oil decline observed in the previous year. The improvement in the oil decline honored all key constraints and did not cause WG to experience changes to surface elevation, an important requirement in reservoir management of the highly compressible Diatomite reservoir.\u0000 Using streamlines to define well patterns based on historical production/injection rates, and considering all patterns simultaneously is a major departure from the one-at-a-time fixed pattern and reservoir team-specific strategy used in the past. Considering that the manual pattern-by-pattern review consumed well over 50% of the time spent by teams trying to improve flood performance, the approach described in the work also represents a significant improvement in productivity and a more agile reservoir management strategy. The ability to include key surface and subsurface constraints in the calculation of well target rates is a novel addition to streamline-based surveillance modeling and a key contribution of this work.\u0000","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133870071","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geomechanic Interferometry: Theory and Application to Time-Lapse InSAR Data for Separating Displacement Signal Between Overburden and Reservoir Sources","authors":"A. Shabelansky, K. Nihei, Zhishuai Zhang, D. Bevc, W. Milliken, G. Mali","doi":"10.2118/209257-ms","DOIUrl":"https://doi.org/10.2118/209257-ms","url":null,"abstract":"\u0000 Interferometric synthetic aperture radar (InSAR) data provides a measurement of the Earth's surface displacements to monitor reservoir stresses, fluid pressure and volume changes. However, the InSAR measurements may suffer from poor sensitivity and resolution. To improve the sensitivity of the InSAR data and localize the effects of the near-surface overburden, we employ a Green's function retrieval (GFR) approach that uses time-lapse InSAR data. In this work, we derive the equations and compute the sensitivity between InSAR displacements caused by the reservoir changes with respect to observation points (i.e., virtual sources) at the surface. We present this method with time-lapse InSAR data from an oil field in the San-Joaquin Valley to demonstrate improved resolution of the GFR-InSAR measurements for subsurface imaging and continuous reservoir monitoring with applications to development, production, and subsurface integrity.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"91 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126083365","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimal Design of Deviation-Correction Trajectory Considering Inter-Well Interference","authors":"Zijun Dou, Xing Qin, Yongsheng Liu, Jiansong Zhang, Qingsheng Meng","doi":"10.2118/209254-ms","DOIUrl":"https://doi.org/10.2118/209254-ms","url":null,"abstract":"\u0000 In the process of shale gas mining, if the actual well deviates from the planned trajectory, significant inter-well interference will occur. Therefore, in order to reduce production loss, operators want to get back on the planned trajectory economically. To obtain the best deviation-correction trajectory, an optimization model considering inter-well interference was established. Firstly, the function relation between production envelope and deviation distance is constructed to calculate the production loss. Then, based on the deviation-correction trajectory design, the deviation distance under different curvature trajectory is obtained. Finally, the production loss of different trajectory is obtained, and a new multi-objective optimization model for deviation-correction trajectory is established. Based on the field data of Fuling shale gas area in China, the established model is verified. The results show that the smaller the curvature value is, the greater the production loss occurs. When the curvature value exceeds 10.8°/30m, the production loss value remains minimal. With the same production loss, the longer the production time leads to the greater well profile energy. When the optimization objectives are considered comprehensively, a trajectory with lower well profile energy and higher production can be obtained. It is concluded that the established model can not only reduce the probability of drilling accidents but also achieve better shale gas production. This study fully considers various factors affecting horizontal well in shale gas area, which can provide theoretical guidance for the design of deviation-correction trajectory.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123411292","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"State of Art Toolless Production Log for Unconventional Wells Based on Stage Level Pressure Transient Analysis","authors":"M. Ibrahim, M. Sinkey, T. Johnston","doi":"10.2118/209259-ms","DOIUrl":"https://doi.org/10.2118/209259-ms","url":null,"abstract":"\u0000 Hydraulic fracturing has proven to be the only method for making unconventional wells economically productive. Understanding fracture growth is the main industry goal to help in planning well spacing and optimization of fracing operation costs. Traditional production logs used to check the production status at limited snapshot in time by measuring the contribution of each stage. This delays the optimization of fracturing design and production evaluation. Conventional production logging technology uses coiled tubing, fiber or tractor conveyed testing tools to measure key parameters like rate, pressure, temperature, and liquid/gas holdup along the horizontal lateral. From these measurements, the contribution of different lateral parts calculated. It is a mature technology for conventional wells and has been used in unconventional wells in recent years (Lopez, 2014; Nnebocha, 2013; Mccluskey, 2012). However, the cost and interpretation issues in these logs rarely make them economic diagnostics. This paper introduces an innovative production logging technology to gain better understanding of post-frac production performance and help to enhance the development of shale gas wells.\u0000 A new method uses real-time integration of rock mechanics during pumping stage and fluid flow in porous media during leakoff to characterize frac stage contribution. This method used to calculate each stage fracture surface area, fracture face skin, stage permeability, and detect stage interference. The stage-level solution used to predict stage-level production performance once well flowback.\u0000 Post-stage leakoff analysis used to calculate fracture efficiency of each stage and provide method of improving in real-time. The results from these analyses used in conjunction with full well rate transient analysis (RTA) and build-up analysis (PTA) to create reservoir simulation models with real fracture lengths for each stage. This new method will help in well spacing optimization by informing fracing operations of fracture interference with offset wells, both parent and child in real-time. The result can be validated with production logs, fiber optics, and tracer analysis.\u0000 Use of real-time toolless production log does not require running of any surveillance tool in well beside surface pressure gauge, therefore the cost is minimal compared to current industry methods. Also, the new method will lead to saving millions of dollars to operator if it uses in real time frac job to guide the next frac optimization.","PeriodicalId":224766,"journal":{"name":"Day 2 Wed, April 27, 2022","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129994446","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}