The objective of the present work is to propose a methodology to predict pressure rise due to the thermal expansion of trapped liquids using computational fluid dynamics (CFD). The present study also provides a comparison between the various methods used for pressure buildup calculations that are widely used in oil and gas industries. A comparison of standard thermodynamic calculations with transient 3D CFD analysis reveals that transient CFD analyses can provide deeper insights on the temperature and velocity fields in trapped volumes. The application of the proposed method is not just restricted to a single component/equipment in the subsea field but can be applied to any trapped volume in subsea equipment. In the present study, the pressure buildup in a downhole (DH) port of a subsea Christmas tree (XT) is presented for demonstration purposes; the same methodology can be extended to other equipment or regions of interest. Because of a lack of literature on the topic of pressure rise due to thermal expansion of trapped fluids, engineers are forced to make several assumptions without knowing the effect of each term or parameter on the final pressure calculated. In this study, the percentage change/variation of the final pressure using the various forms of a standard analytical pressure rise equation is also discussed in detail.
{"title":"An Interim Report on Predicting Pressure Rise due to the Thermal Expansion of Trapped Liquids in Subsea Oil and Gas Equipment","authors":"Ramechecandane Somassoundirame, Eswari Nithiyananthan","doi":"10.2118/204473-pa","DOIUrl":"https://doi.org/10.2118/204473-pa","url":null,"abstract":"\u0000 The objective of the present work is to propose a methodology to predict pressure rise due to the thermal expansion of trapped liquids using computational fluid dynamics (CFD). The present study also provides a comparison between the various methods used for pressure buildup calculations that are widely used in oil and gas industries. A comparison of standard thermodynamic calculations with transient 3D CFD analysis reveals that transient CFD analyses can provide deeper insights on the temperature and velocity fields in trapped volumes. The application of the proposed method is not just restricted to a single component/equipment in the subsea field but can be applied to any trapped volume in subsea equipment. In the present study, the pressure buildup in a downhole (DH) port of a subsea Christmas tree (XT) is presented for demonstration purposes; the same methodology can be extended to other equipment or regions of interest. Because of a lack of literature on the topic of pressure rise due to thermal expansion of trapped fluids, engineers are forced to make several assumptions without knowing the effect of each term or parameter on the final pressure calculated. In this study, the percentage change/variation of the final pressure using the various forms of a standard analytical pressure rise equation is also discussed in detail.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47761809","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R2 of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.
{"title":"A Mathematical Model for Predicting Long-Term Productivity of Channel-Fractured Shale Gas/Oil Wells","authors":"Xu Yang, B. Guo, T. A. Timiyan","doi":"10.2118/204471-pa","DOIUrl":"https://doi.org/10.2118/204471-pa","url":null,"abstract":"\u0000 This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R2 of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47565487","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers. In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale. Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag. Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.
{"title":"Comprehensive Fall Velocity Study on Continuous Flow Plungers","authors":"O. Sayman, E. Pereyra, C. Sarica","doi":"10.2118/201139-ms","DOIUrl":"https://doi.org/10.2118/201139-ms","url":null,"abstract":"\u0000 The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers.\u0000 In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale.\u0000 Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag.\u0000 Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201139-ms","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44316411","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Kjølaas, T. E. Unander, M. Wolden, Heiner Schümann, P. R. Leinan, I. E. Smith, A. Shmueli
We present a unique set of two- and three-phase slug-flow experiments conducted in a 766-m-long, 8-in. pipe at 45-bara pressure, using Exxsol™ D60 fluid (ExxonMobil Chemical, Houston, Texas, USA) as the oil phase and nitrogen as the gas phase. The first one-half of the pipe was horizontal, while the second one-half was inclined by 0.5°. A total of 10 narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug-length development. The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down, and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low mixture velocities (<3 m/s), the slug-length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were more than 250 pipe diameters (50 m). At higher mixture velocities (>3 m/s), the slug-length distributions are in general narrower. The effect of the water cut (WC) on the slug-length distribution is significant but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug-flow experiments, the flow regime 57 m downstream of the start of the horizontal section was not slug flow.
{"title":"Large-Scale Experiments on Slug-Length Evolution in Long Pipes","authors":"J. Kjølaas, T. E. Unander, M. Wolden, Heiner Schümann, P. R. Leinan, I. E. Smith, A. Shmueli","doi":"10.2118/203827-PA","DOIUrl":"https://doi.org/10.2118/203827-PA","url":null,"abstract":"\u0000 We present a unique set of two- and three-phase slug-flow experiments conducted in a 766-m-long, 8-in. pipe at 45-bara pressure, using Exxsol™ D60 fluid (ExxonMobil Chemical, Houston, Texas, USA) as the oil phase and nitrogen as the gas phase. The first one-half of the pipe was horizontal, while the second one-half was inclined by 0.5°. A total of 10 narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug-length development.\u0000 The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down, and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low mixture velocities (<3 m/s), the slug-length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were more than 250 pipe diameters (50 m). At higher mixture velocities (>3 m/s), the slug-length distributions are in general narrower. The effect of the water cut (WC) on the slug-length distribution is significant but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug-flow experiments, the flow regime 57 m downstream of the start of the horizontal section was not slug flow.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46681087","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
N. Yoshida, Satoshi Teshima, Ryo Yamada, Umut Aybar, P. Ramondenc
The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed-temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. The subject well experienced unexpected contamination of oil-based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging-tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions. The following operational sequence was implemented: temperature-baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut-in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real-time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low-injection-rate limitation. Post-job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger-intake interval being the primary water-bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones. This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water-production diagnostics in some extreme conditions when production-logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activi
{"title":"Pushing the Limits of Damage Identification Through the Combined Use of Coiled Tubing, Distributed Sensing, and Advanced Simulations: A Success Story from Japan","authors":"N. Yoshida, Satoshi Teshima, Ryo Yamada, Umut Aybar, P. Ramondenc","doi":"10.2118/194284-pa","DOIUrl":"https://doi.org/10.2118/194284-pa","url":null,"abstract":"\u0000 The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed-temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan.\u0000 The subject well experienced unexpected contamination of oil-based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging-tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions.\u0000 The following operational sequence was implemented: temperature-baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut-in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real-time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low-injection-rate limitation. Post-job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger-intake interval being the primary water-bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones.\u0000 This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water-production diagnostics in some extreme conditions when production-logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activi","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/194284-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48308651","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Proper lateral and vertical well spacing is critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for stacked-bench plays such as the Permian Basin. Following the previous single-well study (Xiong et al. 2018), we performed a seven-well case study to optimize completion design and 3D well spacings, by integrating the latest complex-fracture-modeling and reservoir-simulation technologies. Those seven wells are located at the same section but also are vertically placed in four different zones in the Wolfcamp Formation in the southern Midland Basin. With the latest modeling technologies, we first built a 3D geological and geomechanical model, and full wellbore fracture-propagation model for these seven wells, and then calibrated the model with multistage-fracturing pumping history of each well. The resulting model was then converted to an unstructured-grid-based reservoir-simulation model, which was then calibrated with production history. On the basis of the local geomechanical characterization, as well as confidence in the capacity of the models from our previous study, we conducted experiments in fracturing modeling to study the impact of different completion design parameters on fracture propagation, including cluster spacing, fracturing-fluid viscosity, pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, and studied lateral and vertical well spacings. The results show the following. The resulting fracture length and height from multistage fracturing treatments are in log-normal distribution, which provides great insights on the probability of well interference/fracture hits and drained/undrained reservoir volumes. Both fracture hits/well interference and drainage volume depend on the well spacings and corresponding well completion designs The hydraulic-fracture length, height, and network complexity mainly depend on in-situ stress, cluster spacing, cluster number per stage, and fluid and proppant intensity. For the Wolfcamp Formation in the southern Midland Basin, tighter cluster spacing with fewer perforation clusters per stage and high fluid and proppant intensity, might create larger fracture surface area, which will increase the initial production rate and the ultimate recovery. Therefore, we can reasonably model complicated fracture propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion design. The application of those technologies could help operators save significant time and costs on well-completion and -spacing pilot projects and, thus, speed up field-development decisions. In addition, we will demonstrate a novel workflow to perform this job.
合理的横向和垂直井距对于有效开发非常规储层至关重要。许多研究都集中在横向井距上，但很少关注垂直井距，这对叠层梯段（如二叠纪盆地）来说是重要且具有挑战性的。继之前的单井研究（Xiong et al.2018）之后，我们进行了七井案例研究，通过整合最新的复杂裂缝建模和储层模拟技术，优化完井设计和三维井距。这七口井位于同一剖面，但也垂直分布在米德兰盆地南部Wolfcamp组的四个不同区域。利用最新的建模技术，我们首先为这七口井建立了三维地质和地质力学模型，以及全井筒裂缝扩展模型，然后根据每口井的多级压裂泵送历史对模型进行了校准。然后将生成的模型转换为基于非结构化网格的储层模拟模型，然后用生产历史对其进行校准。基于局部地质力学特征以及我们之前研究中对模型能力的信心，我们进行了压裂建模实验，以研究不同完井设计参数对裂缝扩展的影响，包括丛距、压裂液粘度、泵送速率以及流体和支撑剂强度。根据不同完井设计裂缝长度和高度的统计分布，我们对完井设计进行了优化，并研究了横向和垂直井距。结果显示如下。多级压裂处理产生的裂缝长度和高度呈对数正态分布，这为油井干扰/裂缝命中概率和排水/未排水储层体积提供了很好的见解。裂缝命中/井干扰和排水量都取决于井间距和相应的完井设计。水力裂缝的长度、高度和网络复杂性主要取决于地应力、簇间距、每个阶段的簇数以及流体和支撑剂强度。对于米德兰盆地南部的Wolfcamp组，更紧密的簇间距、每个阶段更少的射孔簇以及高流体和支撑剂强度，可能会产生更大的裂缝表面积，这将提高初始生产率和最终采收率。因此，我们可以利用最新的建模技术对复杂的裂缝扩展和井动态进行合理建模，并优化横向和垂直井距以及相应的完井设计。这些技术的应用可以帮助运营商在完井和井距试点项目上节省大量时间和成本，从而加快油田开发决策。此外，我们将演示一种执行此工作的新颖工作流。
{"title":"Optimizing Fracturing Design and Well Spacing with Complex-Fracture and Reservoir Simulations: A Permian Basin Case Study","authors":"Hongjie Xiong, Songxia Liu, Feng Feng, Shuai Liu, Kaimin Yue","doi":"10.2118/194367-pa","DOIUrl":"https://doi.org/10.2118/194367-pa","url":null,"abstract":"\u0000 Proper lateral and vertical well spacing is critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for stacked-bench plays such as the Permian Basin. Following the previous single-well study (Xiong et al. 2018), we performed a seven-well case study to optimize completion design and 3D well spacings, by integrating the latest complex-fracture-modeling and reservoir-simulation technologies. Those seven wells are located at the same section but also are vertically placed in four different zones in the Wolfcamp Formation in the southern Midland Basin.\u0000 With the latest modeling technologies, we first built a 3D geological and geomechanical model, and full wellbore fracture-propagation model for these seven wells, and then calibrated the model with multistage-fracturing pumping history of each well. The resulting model was then converted to an unstructured-grid-based reservoir-simulation model, which was then calibrated with production history. On the basis of the local geomechanical characterization, as well as confidence in the capacity of the models from our previous study, we conducted experiments in fracturing modeling to study the impact of different completion design parameters on fracture propagation, including cluster spacing, fracturing-fluid viscosity, pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, and studied lateral and vertical well spacings.\u0000 The results show the following. The resulting fracture length and height from multistage fracturing treatments are in log-normal distribution, which provides great insights on the probability of well interference/fracture hits and drained/undrained reservoir volumes. Both fracture hits/well interference and drainage volume depend on the well spacings and corresponding well completion designs The hydraulic-fracture length, height, and network complexity mainly depend on in-situ stress, cluster spacing, cluster number per stage, and fluid and proppant intensity. For the Wolfcamp Formation in the southern Midland Basin, tighter cluster spacing with fewer perforation clusters per stage and high fluid and proppant intensity, might create larger fracture surface area, which will increase the initial production rate and the ultimate recovery.\u0000 Therefore, we can reasonably model complicated fracture propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion design. The application of those technologies could help operators save significant time and costs on well-completion and -spacing pilot projects and, thus, speed up field-development decisions. In addition, we will demonstrate a novel workflow to perform this job.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/194367-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42244761","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Luai Alhamad, Ahmed A. Alrashed, E. Munif, J. Miskimins
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations, and is the base acid that is commonly paired with hydrofluoric acid (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature (HT) can make HCl a poor choice. Alternatively, weaker and less-corrosive chemicals, such as organic acids, can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases that outline the use of organic acids for formation-damage removal and dissolution. Rotating-disk-apparatus (RDA) results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, coreflooding, inductively coupled plasma, X-ray diffraction, and scanning-electron-microscope (SEM) diffraction tests. Because of their retardation performance, organic acids have been used along with mineral acids, mainly a formic/HCl mixture, or as a standalone solution for HT applications. However, the main drawback of these acids is the solubility of reaction-product salts. This challenge has been a limiting factor of using citric acid with calcium-rich formations because of the low solubility of calcium citrate. However, the solubility of the salts associated with formic, acetic, and lactic acid can be increased when these acids are mixed with gluconic acid because of the ability of gluconate ion to chelate calcium-based precipitation. In terms of formation-failure response, organic acids are in lower risk of causing a failure compared with HCl, specifically at deep formation treatments. Organic acids have also been used in other applications. For instance, formic acid is used in HT operations as an intensifier to reduce the corrosion rate caused by HCl. Formic, acetic, and lactic acids can be used to dissolve drilling-mud filter cakes. Citric acid is commonly used as an iron-sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
{"title":"Organic Acids for Stimulation Purposes: A Review","authors":"Luai Alhamad, Ahmed A. Alrashed, E. Munif, J. Miskimins","doi":"10.2118/199291-PA","DOIUrl":"https://doi.org/10.2118/199291-PA","url":null,"abstract":"\u0000 Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations, and is the base acid that is commonly paired with hydrofluoric acid (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature (HT) can make HCl a poor choice. Alternatively, weaker and less-corrosive chemicals, such as organic acids, can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.\u0000 This review includes various laboratory evaluation tests and field cases that outline the use of organic acids for formation-damage removal and dissolution. Rotating-disk-apparatus (RDA) results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, coreflooding, inductively coupled plasma, X-ray diffraction, and scanning-electron-microscope (SEM) diffraction tests.\u0000 Because of their retardation performance, organic acids have been used along with mineral acids, mainly a formic/HCl mixture, or as a standalone solution for HT applications. However, the main drawback of these acids is the solubility of reaction-product salts. This challenge has been a limiting factor of using citric acid with calcium-rich formations because of the low solubility of calcium citrate. However, the solubility of the salts associated with formic, acetic, and lactic acid can be increased when these acids are mixed with gluconic acid because of the ability of gluconate ion to chelate calcium-based precipitation. In terms of formation-failure response, organic acids are in lower risk of causing a failure compared with HCl, specifically at deep formation treatments. Organic acids have also been used in other applications. For instance, formic acid is used in HT operations as an intensifier to reduce the corrosion rate caused by HCl. Formic, acetic, and lactic acids can be used to dissolve drilling-mud filter cakes. Citric acid is commonly used as an iron-sequestering agent.\u0000 This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199291-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41410351","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In coal-seam-gas (CSG) fields, where single wells tap multiple seams, it is likely that some of the individual seams hardly contribute to gas recovery. This study aims to examine the contribution of individual seams to the total gas and water production considering that each seam can have different properties and dimensions. A sensitivity analysis using reservoir simulation investigates the effects of individual seam properties on production profiles. A radial model simulates the production of a single CSG well consisting of a stack of two seams with a range of properties for permeability, thickness, seam extent, initial reservoir pressure, coal compressibility and porosity. The stress dependency of permeability obeys the Palmer and Mansoori (1998) model. A time coefficient (α) relates seam radius, viscosity, porosity, fracture compressibility, and permeability. It is used to aid interpretation of the sensitivity study. Finally, two hypothetical simulation scenarios with five seams of different thicknesses and depths obtained from producing wells are explored. The range in properties represents conditions found in the Walloon Coal Measures (WCM) of the Surat Basin, relevant to the Australian CSG industry. Each seam in the stack achieves its peak production rate at different times, and this can be estimated using α. Seams with lower α reach the peak gas rate earlier than those with higher α-coefficient. The distinct behavior of gas-production profiles depends on the combination of individual seam properties and multiseam interaction. At a αratio > 1 (i.e., αtop/αbottom > 1), the bottom seam peaks first but achieves lower gas recovery than the top seam. An increasing αratio is associated with the inhibition of less-permeable seams and reduced overall well productivity. For αratio < 1, the top seam experiences fast depletion and total gas-production rates decrease drastically. This outcome is confirmed by a more realistic scenario with a higher number of coal layers. Poor combination of seams leads to severe production inhibition of some coal reservoirs and possible wellbore crossflow. The contrast of the seam-lateral extent in the stack and fracture compressibility play an important role in well productivity in the commingled operation of a stack of coal seams. Unfortunately, the lateral extent of individual coal seams is difficult to estimate and poorly known and, therefore, represents a major uncertainty in gas-production prognosis. The αratio analysis is a useful tool to gain understanding of modeled well productivity from commingled CSG reservoirs.
{"title":"Modeling the Contribution of Individual Coal Seams on Commingled Gas Production","authors":"Vanessa Santiago, A. Ribeiro, S. Hurter","doi":"10.2118/198241-pa","DOIUrl":"https://doi.org/10.2118/198241-pa","url":null,"abstract":"\u0000 In coal-seam-gas (CSG) fields, where single wells tap multiple seams, it is likely that some of the individual seams hardly contribute to gas recovery. This study aims to examine the contribution of individual seams to the total gas and water production considering that each seam can have different properties and dimensions. A sensitivity analysis using reservoir simulation investigates the effects of individual seam properties on production profiles.\u0000 A radial model simulates the production of a single CSG well consisting of a stack of two seams with a range of properties for permeability, thickness, seam extent, initial reservoir pressure, coal compressibility and porosity. The stress dependency of permeability obeys the Palmer and Mansoori (1998) model. A time coefficient (α) relates seam radius, viscosity, porosity, fracture compressibility, and permeability. It is used to aid interpretation of the sensitivity study. Finally, two hypothetical simulation scenarios with five seams of different thicknesses and depths obtained from producing wells are explored. The range in properties represents conditions found in the Walloon Coal Measures (WCM) of the Surat Basin, relevant to the Australian CSG industry.\u0000 Each seam in the stack achieves its peak production rate at different times, and this can be estimated using α. Seams with lower α reach the peak gas rate earlier than those with higher α-coefficient. The distinct behavior of gas-production profiles depends on the combination of individual seam properties and multiseam interaction. At a αratio > 1 (i.e., αtop/αbottom > 1), the bottom seam peaks first but achieves lower gas recovery than the top seam. An increasing αratio is associated with the inhibition of less-permeable seams and reduced overall well productivity. For αratio < 1, the top seam experiences fast depletion and total gas-production rates decrease drastically. This outcome is confirmed by a more realistic scenario with a higher number of coal layers. Poor combination of seams leads to severe production inhibition of some coal reservoirs and possible wellbore crossflow. The contrast of the seam-lateral extent in the stack and fracture compressibility play an important role in well productivity in the commingled operation of a stack of coal seams. Unfortunately, the lateral extent of individual coal seams is difficult to estimate and poorly known and, therefore, represents a major uncertainty in gas-production prognosis. The αratio analysis is a useful tool to gain understanding of modeled well productivity from commingled CSG reservoirs.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41783236","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Tao Chen, Qiwei Wang, F. Chang, N. Aljeaban, K. Alnoaimi
Iron sulfide scale deposition can be a significant flow-assurance issue in sour-gas production systems. It can deposit along the water-flowing path from the near-wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production. The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour-gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies. In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well-completion and production stages, especially the sources of ferrous iron (Fe2+) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale-inhibitor deployment through continuous-injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research-and-development (R&D) efforts. We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.
{"title":"Recent Development and Remaining Challenges of Iron Sulfide Scale Mitigation in Sour-Gas Wells","authors":"Tao Chen, Qiwei Wang, F. Chang, N. Aljeaban, K. Alnoaimi","doi":"10.2118/199365-pa","DOIUrl":"https://doi.org/10.2118/199365-pa","url":null,"abstract":"\u0000 Iron sulfide scale deposition can be a significant flow-assurance issue in sour-gas production systems. It can deposit along the water-flowing path from the near-wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production.\u0000 The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour-gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies.\u0000 In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well-completion and production stages, especially the sources of ferrous iron (Fe2+) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale-inhibitor deployment through continuous-injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research-and-development (R&D) efforts.\u0000 We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199365-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45758446","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Xiaofan Hu, Guoqing Liu, Guofan Luo, C. Ehlig-Economides
Engineers commonly expect symmetric fracture wings in multiple-transverse-fracture horizontal wells. Microseismic surveys have shown that asymmetric hydraulic fractures grow away from the recent fractured wells and grow toward previously produced wells. This might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events, develops a simple model to simulate the fracture propagation, and discusses its effect on the well productivity. Motivated by the microseismic observations, we developed a simple 2D fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Fluid leakoff during fracture propagation is considered in the model. The effect of asymmetric fractures on production is evaluated with numerical simulations. The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is near where the stress field is different between its two sides. Numerical simulation is used to quantify the productivity reduction caused by asymmetric hydraulic fractures. Our results provide a reason for why asymmetric fractures occur and demonstrate that they do penalize well performance. Our model suggests the importance of fracturing under a balanced-stress distribution that benefits long-term production. Use of this model also suggested that an optimized hydraulic-fracturing-treatment design will improve the overall performance of multiple parallel wells, which minimizes or avoids asymmetric fracture wings. The fracture-propagation model and productivity model provide simple but profound guidelines for well-pad management, including well spacing, stage planning and spacing, and completion and production order.
{"title":"Model for Asymmetric Hydraulic Fractures with Nonuniform-Stress Distribution","authors":"Xiaofan Hu, Guoqing Liu, Guofan Luo, C. Ehlig-Economides","doi":"10.2118/195193-pa","DOIUrl":"https://doi.org/10.2118/195193-pa","url":null,"abstract":"\u0000 Engineers commonly expect symmetric fracture wings in multiple-transverse-fracture horizontal wells. Microseismic surveys have shown that asymmetric hydraulic fractures grow away from the recent fractured wells and grow toward previously produced wells. This might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events, develops a simple model to simulate the fracture propagation, and discusses its effect on the well productivity.\u0000 Motivated by the microseismic observations, we developed a simple 2D fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Fluid leakoff during fracture propagation is considered in the model. The effect of asymmetric fractures on production is evaluated with numerical simulations.\u0000 The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is near where the stress field is different between its two sides. Numerical simulation is used to quantify the productivity reduction caused by asymmetric hydraulic fractures. Our results provide a reason for why asymmetric fractures occur and demonstrate that they do penalize well performance. Our model suggests the importance of fracturing under a balanced-stress distribution that benefits long-term production. Use of this model also suggested that an optimized hydraulic-fracturing-treatment design will improve the overall performance of multiple parallel wells, which minimizes or avoids asymmetric fracture wings.\u0000 The fracture-propagation model and productivity model provide simple but profound guidelines for well-pad management, including well spacing, stage planning and spacing, and completion and production order.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/195193-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45945065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：