In this paper, we introduce pumpdown diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing, and fracturing (frac) plug integrity can be assessed for every fracturing stage, potentially leading to improvements in stimulation, completion, cementing, and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pumpdown and perforating operation and correlating the results among multiple fracturing stages and wells in a field or play. A special requirement is that the ball check is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited hydrochloric (HCl) acid coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity. Reviews of pumpdown diagnostics field cases from several unconventional plays provide the following insights. Pumpdown diagnostics are time efficient and economical, requiring approximately 15 minutes per fracturing stage. Evaluating communication to the previous fracturing stage can serve as a key performance indicator for treatment control or cement sheath integrity. Pumpdown diagnostic results can be more reliable than cement bond log evaluation, and stage isolation characteristics can be strongly affected by cluster spacing.
{"title":"Pumpdown Diagnostics for Plug-and-Perf Treatments","authors":"D. Cramer, Jon Snyder, Junjing Zhang","doi":"10.2118/201376-pa","DOIUrl":"https://doi.org/10.2118/201376-pa","url":null,"abstract":"\u0000 In this paper, we introduce pumpdown diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing, and fracturing (frac) plug integrity can be assessed for every fracturing stage, potentially leading to improvements in stimulation, completion, cementing, and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pumpdown and perforating operation and correlating the results among multiple fracturing stages and wells in a field or play. A special requirement is that the ball check is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited hydrochloric (HCl) acid coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity.\u0000 Reviews of pumpdown diagnostics field cases from several unconventional plays provide the following insights. Pumpdown diagnostics are time efficient and economical, requiring approximately 15 minutes per fracturing stage. Evaluating communication to the previous fracturing stage can serve as a key performance indicator for treatment control or cement sheath integrity. Pumpdown diagnostic results can be more reliable than cement bond log evaluation, and stage isolation characteristics can be strongly affected by cluster spacing.","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":"44801141","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}
S. Livescu, D. McDuff, B. Comeaux, Amit Singh, B. Lindsey
Acid tunneling is an acid-jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in openhole wells compared with conventional coiled-tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time. The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric acid (HCl) through conventional CT and a bottomhole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel-initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling-length efficiency. Full-scale water- and acid-jetting tests were performed on Indiana limestone cores with 2- to 4-md permeability and 12 to 14% porosity, sourced from the same supplier. Many field-realistic combinations of nozzle sizes, jetting speeds, and casing pressures were included in the testing program. The cores were 3.75 in. in diameter × 6 in. in length for the water tests and 12 in. in diameter × 18 in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle standoff. Six acid tests were performed at the ambient temperature of 46°F and two at 97°F. The results from the acid tests show that the acid-tunneling efficiency, defined as the tunnel length divided by the acid volume, can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid-tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid-tunneling operations performed to date worldwide. Although the tunnel lengths and acid volumes for the actual tunnels constructed during the previous acid-tunneling operations were recorded by the service company performing those operations, little downhole temperature and formation characterization data were provided by the operators to the service company. Thus, the downhole-temperature and formation-characterization effects on the acid-tunneling efficiency for the previous field operations are unknown. In this paper, we describe the full-scale water- and acid-jetting tests on
{"title":"Acid Tunneling in Carbonate Rocks: A Full-Scale Experimental Study","authors":"S. Livescu, D. McDuff, B. Comeaux, Amit Singh, B. Lindsey","doi":"10.2118/196150-pa","DOIUrl":"https://doi.org/10.2118/196150-pa","url":null,"abstract":"\u0000 Acid tunneling is an acid-jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in openhole wells compared with conventional coiled-tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time.\u0000 The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric acid (HCl) through conventional CT and a bottomhole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel-initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling-length efficiency.\u0000 Full-scale water- and acid-jetting tests were performed on Indiana limestone cores with 2- to 4-md permeability and 12 to 14% porosity, sourced from the same supplier. Many field-realistic combinations of nozzle sizes, jetting speeds, and casing pressures were included in the testing program. The cores were 3.75 in. in diameter × 6 in. in length for the water tests and 12 in. in diameter × 18 in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle standoff. Six acid tests were performed at the ambient temperature of 46°F and two at 97°F. The results from the acid tests show that the acid-tunneling efficiency, defined as the tunnel length divided by the acid volume, can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid-tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid-tunneling operations performed to date worldwide. Although the tunnel lengths and acid volumes for the actual tunnels constructed during the previous acid-tunneling operations were recorded by the service company performing those operations, little downhole temperature and formation characterization data were provided by the operators to the service company. Thus, the downhole-temperature and formation-characterization effects on the acid-tunneling efficiency for the previous field operations are unknown.\u0000 In this paper, we describe the full-scale water- and acid-jetting tests on ","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/10.2118/196150-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48120935","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}
Knowledge of fracture-entry pressures or formation-face pressures (FFPs) during acid-fracturing treatments in real-time mode can help in evaluating the effectiveness of the treatment and improve the decision-making process during execution. In this paper, methods and tools used to generate FFPs in real-time mode with the help of bottomhole-pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole-gauge pressures, to calculate fracture-inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on-the-fly” evaluation and the decision-making process. Several acid-fracture treatments were analyzed using the tool and led to important conclusions related to fracture-propagation modes, acid-exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.
{"title":"Real-Time Analysis of Formation-Face Pressures in Acid-Fracturing Treatments","authors":"V. Pandey, R. Burton, K. Capps","doi":"10.2118/194351-pa","DOIUrl":"https://doi.org/10.2118/194351-pa","url":null,"abstract":"Knowledge of fracture-entry pressures or formation-face pressures (FFPs) during acid-fracturing treatments in real-time mode can help in evaluating the effectiveness of the treatment and improve the decision-making process during execution. In this paper, methods and tools used to generate FFPs in real-time mode with the help of bottomhole-pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole-gauge pressures, to calculate fracture-inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on-the-fly” evaluation and the decision-making process. Several acid-fracture treatments were analyzed using the tool and led to important conclusions related to fracture-propagation modes, acid-exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.","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/10.2118/194351-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44525883","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 paper shows the applicability and the value of real options analysis (ROA) in valuing a marginal undeveloped discovery in the UK Continental Shelf (UKCS) under multiple project uncertainties, namely geology, costs, and oil prices. Marginal fields can prove uneconomic when developed under prevailing circumstances such as technical (reservoir size, infrastructure distance and remoteness, crude-oil type) or commercial issues (oil prices, high cost of development, lack of third-party-access arrangements), among others. As such, using traditional discounted-cash-flow (DCF) methodologies such as the net present value (NPV) might not adequately value the embedded options that these uncertainties create, leading to a rejection of the investment decision. Hence, we assess if the valuation differs if valued by the traditional DCF approach compared with ROA. We develop a valuation model for the traditional DCF and real options and specifically model the flexibility in the options to delay, abandon, or expand the field anytime during the relinquishment requirement period considering these multiple uncertainties. The binomial lattice and later the Black and Scholes models are used to model the options because of the flexibility they provide in incorporating early exercise. The results indicate that the DCF values lag those of the option values for the deferral and expansion options. In contrast, the abandonment option exhibited only a marginal change with respect to the DCF value. A significant implication of this finding is that management decision making will be better off considering these embedded options in their field-development and capital-investment choices.
{"title":"On the Valuation of Natural Resources: Real Options Analysis of Marginal Oilfield-Development Projects Under Multiple Uncertainties","authors":"T. Acheampong","doi":"10.2118/204232-pa","DOIUrl":"https://doi.org/10.2118/204232-pa","url":null,"abstract":"\u0000 This paper shows the applicability and the value of real options analysis (ROA) in valuing a marginal undeveloped discovery in the UK Continental Shelf (UKCS) under multiple project uncertainties, namely geology, costs, and oil prices. Marginal fields can prove uneconomic when developed under prevailing circumstances such as technical (reservoir size, infrastructure distance and remoteness, crude-oil type) or commercial issues (oil prices, high cost of development, lack of third-party-access arrangements), among others. As such, using traditional discounted-cash-flow (DCF) methodologies such as the net present value (NPV) might not adequately value the embedded options that these uncertainties create, leading to a rejection of the investment decision. Hence, we assess if the valuation differs if valued by the traditional DCF approach compared with ROA. We develop a valuation model for the traditional DCF and real options and specifically model the flexibility in the options to delay, abandon, or expand the field anytime during the relinquishment requirement period considering these multiple uncertainties. The binomial lattice and later the Black and Scholes models are used to model the options because of the flexibility they provide in incorporating early exercise. The results indicate that the DCF values lag those of the option values for the deferral and expansion options. In contrast, the abandonment option exhibited only a marginal change with respect to the DCF value. A significant implication of this finding is that management decision making will be better off considering these embedded options in their field-development and capital-investment choices.","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/10.2118/204232-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42511405","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}
Several experimental studies have been conducted to investigate the effect of liquid viscosity on slug frequency in horizontal, vertical, and inclined two-phase flows. Analyses of these studies reveal that the slug frequency is positively related to superficial liquid velocity and liquid viscosity; the superficial gas velocity has a dual minor effect on slug frequency, with an initial increase for low superficial gas velocity and then a decrease for high superficial gas velocity; and the slug frequency increases with increasing flow deviation from horizontal. Also, the analyses reveal that for inclined viscous flow, the slug frequency and slug length follow the same inverse relationship shown in horizontal and vertical slug flows. In the literature, several models have been developed for predicting slug frequency in viscous horizontal flows, whereas only a few models exist for viscous vertical and inclined flows. In this study, we aim to develop models for prediction of slug frequency in two-phase flow of medium liquid viscosity (30 ≤ μL ≤ 250 mPa·s). Dimensional analysis of four published experimental data sets (218 data points) indicates that slug frequency is related to two dimensionless numbers; namely, a modified Froude number and inverse viscosity number. As a result, three slug frequency closure models are proposed for vertical, horizontal, and inclined flows, using a combination of these two numbers. The proposed models are tested against the four data sets, and very good results are obtained, with correlation coefficients ranging from 0.96 to 0.97.
{"title":"Prediction of Slug Frequency for Medium Liquid Viscosity Two-Phase Flow in Vertical, Horizontal, and Inclined Pipes","authors":"G. Abdul-Majeed, Mahshid Firouzi, G. Soto‐Cortes","doi":"10.2118/202473-pa","DOIUrl":"https://doi.org/10.2118/202473-pa","url":null,"abstract":"\u0000 Several experimental studies have been conducted to investigate the effect of liquid viscosity on slug frequency in horizontal, vertical, and inclined two-phase flows. Analyses of these studies reveal that the slug frequency is positively related to superficial liquid velocity and liquid viscosity; the superficial gas velocity has a dual minor effect on slug frequency, with an initial increase for low superficial gas velocity and then a decrease for high superficial gas velocity; and the slug frequency increases with increasing flow deviation from horizontal. Also, the analyses reveal that for inclined viscous flow, the slug frequency and slug length follow the same inverse relationship shown in horizontal and vertical slug flows. In the literature, several models have been developed for predicting slug frequency in viscous horizontal flows, whereas only a few models exist for viscous vertical and inclined flows. In this study, we aim to develop models for prediction of slug frequency in two-phase flow of medium liquid viscosity (30 ≤ μL ≤ 250 mPa·s). Dimensional analysis of four published experimental data sets (218 data points) indicates that slug frequency is related to two dimensionless numbers; namely, a modified Froude number and inverse viscosity number. As a result, three slug frequency closure models are proposed for vertical, horizontal, and inclined flows, using a combination of these two numbers. The proposed models are tested against the four data sets, and very good results are obtained, with correlation coefficients ranging from 0.96 to 0.97.","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/10.2118/202473-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47802821","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}
Shear slip of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear slip by injection have not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford Shale sample having a single fracture (tensile fracture) was used to perform a laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, shear slip was induced on the fracture at near critical stress state by injecting pressurized brine water [7% potassium chloride (KCl)]. Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate), and AE signals (hits, events) were all recorded. The data were then used to characterize the fully coupled seismo-hydromechanical response of the shale fracture during shearing. Results show that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic-slip interval corresponding to a rapid fracture slip and a large stress drop. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Before this seismic interval, an aseismic-slip interval was evident during the tests, where the fracture slip, associated stress relaxation, and permeability increase were limited. The test results and analyses demonstrate the role of shear slip in permeability enhancement and induced seismicity by hydraulic stimulation for unconventional shale reservoirs.
{"title":"Investigation of Microseismicity and Permeability Evolution in Shale Fractures during Stimulation","authors":"Z. Ye, A. Ghassemi","doi":"10.2118/201115-pa","DOIUrl":"https://doi.org/10.2118/201115-pa","url":null,"abstract":"\u0000 Shear slip of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear slip by injection have not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford Shale sample having a single fracture (tensile fracture) was used to perform a laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, shear slip was induced on the fracture at near critical stress state by injecting pressurized brine water [7% potassium chloride (KCl)]. Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate), and AE signals (hits, events) were all recorded. The data were then used to characterize the fully coupled seismo-hydromechanical response of the shale fracture during shearing. Results show that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic-slip interval corresponding to a rapid fracture slip and a large stress drop. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Before this seismic interval, an aseismic-slip interval was evident during the tests, where the fracture slip, associated stress relaxation, and permeability increase were limited. The test results and analyses demonstrate the role of shear slip in permeability enhancement and induced seismicity by hydraulic stimulation for unconventional shale 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":"https://sci-hub-pdf.com/10.2118/201115-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49605757","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}
Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.
{"title":"Completion Effects on Diagnosing Multistage Facture Treatments with Distributed Temperature Sensing","authors":"Shohei Sakaida, D. Zhu, A. Hill","doi":"10.2118/201604-pa","DOIUrl":"https://doi.org/10.2118/201604-pa","url":null,"abstract":"\u0000 Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior.\u0000 This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation.\u0000 A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval.\u0000 This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.","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":"43906246","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 out-of-sequence (OOS) pinpoint fracturing, Stage 1 is fractured, followed by Stage 3, after which Stage 2 (center fracture) is placed between Stages 1 and 3 (outside fractures). The center fracture can exploit the reduced stress anisotropy to activate planes of weakness (e.g., fissures) and create branch fractures that can connect hydraulic fractures to stress-relief fractures, ultimately enhancing fracture connectivity and complexity. It has been trialed in western Siberia (2014) and western Canada (2017 to 2019) with overall operational and production performance success. Previous fracture-modeling works calibrated by OOS fracturing trials have either used shear-decoupled planar-fracture models (in which slippage along the shear planes restricts the displacement to a limited area because of displacement damping)—which are unable to reproduce out-of-plane fracture complexity, and to dynamically track the change in stress anisotropy and orientation—or discrete-fracture-network (DFN) models, which often exaggerate the fracture-network connectivity, and reproduce unrealistically high fracture-network-extension pressures in the stimulated reservoir volume (SRV). This work attempts to resolve the issues in planar-fracture and DFN models by more realistically addressing the dominant mechanisms of OOS fracturing, dynamic changes in the stress anisotropy and orientation, activation of pre-existing planes of weaknesses, and poroelasticity using an iteratively coupled flow–geomechanical model that uses the dual-lattice implementation of the synthetic-rock-mass (SRM) model with a robust, fully coupled, iterative flow/stress solution to capture the following: Nonlinear deformations caused by induced tensile- and shear-fracture-complexity propagation Induced stress shadowing in and around the SRV Sliding of opened, pre-existing joints, fractures, and fissures using the smooth-joint model (SJM) Propagation of the hydraulic fracture as an aggregate of intact matrix fracturing and opening and slip of pre-existing fluid-filled planes of weakness (e.g., joints, fractures, fissures) Permeability enhancement in the main tensile and complex fractures following the updated deformation aperture from the coupled solution The results (fracture geometries and treatment pressures) of the three models (planar-fracture, DFN, and SRM with lattice models) are compared after using each model for treatment-pressure history matching of an OOS-fracturing trial. The calibrated, coupled SRM with lattice model more reasonably reproduces the measured fracture-extension pressures and end-of-job pressures from OOS pinpoint fracturing treatments, and it reveals the following: The dynamic change in the stress-field orientation and magnitude during OOS fracturing leads to a reduction in stress anisotropy and complex out-of-plane fracturing in the SRV for center fractures. Center fractures tend to be narrower and shorter if sufficient out-of-zone growth is attained in the absence
{"title":"A Coupled Flow–Geomechanical Modeling of Out-of-Sequence Fracturing Using a Dual-Lattice Implementation of Synthetic-Rock-Mass Approach","authors":"B. Jamaloei","doi":"10.2118/203844-pa","DOIUrl":"https://doi.org/10.2118/203844-pa","url":null,"abstract":"\u0000 In out-of-sequence (OOS) pinpoint fracturing, Stage 1 is fractured, followed by Stage 3, after which Stage 2 (center fracture) is placed between Stages 1 and 3 (outside fractures). The center fracture can exploit the reduced stress anisotropy to activate planes of weakness (e.g., fissures) and create branch fractures that can connect hydraulic fractures to stress-relief fractures, ultimately enhancing fracture connectivity and complexity. It has been trialed in western Siberia (2014) and western Canada (2017 to 2019) with overall operational and production performance success.\u0000 Previous fracture-modeling works calibrated by OOS fracturing trials have either used shear-decoupled planar-fracture models (in which slippage along the shear planes restricts the displacement to a limited area because of displacement damping)—which are unable to reproduce out-of-plane fracture complexity, and to dynamically track the change in stress anisotropy and orientation—or discrete-fracture-network (DFN) models, which often exaggerate the fracture-network connectivity, and reproduce unrealistically high fracture-network-extension pressures in the stimulated reservoir volume (SRV). This work attempts to resolve the issues in planar-fracture and DFN models by more realistically addressing the dominant mechanisms of OOS fracturing, dynamic changes in the stress anisotropy and orientation, activation of pre-existing planes of weaknesses, and poroelasticity using an iteratively coupled flow–geomechanical model that uses the dual-lattice implementation of the synthetic-rock-mass (SRM) model with a robust, fully coupled, iterative flow/stress solution to capture the following:\u0000 Nonlinear deformations caused by induced tensile- and shear-fracture-complexity propagation Induced stress shadowing in and around the SRV Sliding of opened, pre-existing joints, fractures, and fissures using the smooth-joint model (SJM) Propagation of the hydraulic fracture as an aggregate of intact matrix fracturing and opening and slip of pre-existing fluid-filled planes of weakness (e.g., joints, fractures, fissures) Permeability enhancement in the main tensile and complex fractures following the updated deformation aperture from the coupled solution\u0000 The results (fracture geometries and treatment pressures) of the three models (planar-fracture, DFN, and SRM with lattice models) are compared after using each model for treatment-pressure history matching of an OOS-fracturing trial. The calibrated, coupled SRM with lattice model more reasonably reproduces the measured fracture-extension pressures and end-of-job pressures from OOS pinpoint fracturing treatments, and it reveals the following:\u0000 The dynamic change in the stress-field orientation and magnitude during OOS fracturing leads to a reduction in stress anisotropy and complex out-of-plane fracturing in the SRV for center fractures. Center fractures tend to be narrower and shorter if sufficient out-of-zone growth is attained in the absence ","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/203844-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49149950","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}
Michael C. Romer, M. Spiecker, T. Hall, R. Dieudonne, François Porel, Laurent Jerzak, D OrtizSantos, King George, Kartikkumar Jaysingbhai Gohil, W. Tapie, Michael Peters, Brandon Alexander Curkan
What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.
{"title":"Development and Testing of a Wireline-Deployed Positive-Displacement Pump for Late-Life Wells","authors":"Michael C. Romer, M. Spiecker, T. Hall, R. Dieudonne, François Porel, Laurent Jerzak, D OrtizSantos, King George, Kartikkumar Jaysingbhai Gohil, W. Tapie, Michael Peters, Brandon Alexander Curkan","doi":"10.2118/201163-pa","DOIUrl":"https://doi.org/10.2118/201163-pa","url":null,"abstract":"\u0000 What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges.\u0000 Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD).\u0000 The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids.\u0000 The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids.\u0000 The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201163-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49221490","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}
M. Tabatabaei, A. D. Taleghani, Yuzhe Cai, L. Santos, N. Alem
Proppant bed can play a critical role in enhancing oil and gas production in stimulated wells. In the last 2 decades, there have been consistent efforts to improve shape characteristics and mechanical strength properties to guarantee high permeability in the resultant propped fracture. However, engineering the surface properties of proppants, such as tuning their wettability, has not received considerable attention. Considering that water-wet proppants can not only limit production because of reduced hydrocarbon relative permeability but also facilitate fines migration through the proppant bed, a methodology is presented here to alter the wettability of proppants using graphite nanoplatelets (GNPs). The idea benefits from the intrinsic hydrophobicity of graphitic surfaces, their relatively low cost, and their planar geometry for coating proppants. Conductivity tests are conducted according to ISO 13503-5:2006 (2006) and API RP 19D (2008) to examine how the coating process changes the relative permeability to water and oil. According to the simulation results, the newly developed graphite-coated proppants speed up the water cleanup and increase long-term oil production in an oil-wet reservoir.
在增产井中，支撑剂床在提高油气产量方面发挥着至关重要的作用。在过去的20年里，人们一直在努力改善形状特征和机械强度特性，以确保支撑裂缝的高渗透性。然而，对支撑剂的表面性质进行工程设计，例如调整其润湿性，并没有得到相当大的关注。考虑到水润湿支撑剂不仅会因为碳氢化合物相对渗透率降低而限制产量，还会促进细粒通过支撑剂床的迁移，本文提出了一种使用石墨纳米片（GNP）改变支撑剂润湿性的方法。这一想法得益于石墨表面固有的疏水性、相对较低的成本以及用于涂覆支撑剂的平面几何形状。根据ISO 13503-5:2006（2006）和API RP 19D（2008）进行电导率测试，以检查涂层工艺如何改变对水和油的相对渗透率。根据模拟结果，在油湿油藏中，新开发的石墨涂层支撑剂加快了水的净化，提高了长期产油量。
{"title":"Surface Modification of Proppant Using Hydrophobic Coating To Enhance Long-Term Production","authors":"M. Tabatabaei, A. D. Taleghani, Yuzhe Cai, L. Santos, N. Alem","doi":"10.2118/196067-pa","DOIUrl":"https://doi.org/10.2118/196067-pa","url":null,"abstract":"\u0000 Proppant bed can play a critical role in enhancing oil and gas production in stimulated wells. In the last 2 decades, there have been consistent efforts to improve shape characteristics and mechanical strength properties to guarantee high permeability in the resultant propped fracture. However, engineering the surface properties of proppants, such as tuning their wettability, has not received considerable attention. Considering that water-wet proppants can not only limit production because of reduced hydrocarbon relative permeability but also facilitate fines migration through the proppant bed, a methodology is presented here to alter the wettability of proppants using graphite nanoplatelets (GNPs). The idea benefits from the intrinsic hydrophobicity of graphitic surfaces, their relatively low cost, and their planar geometry for coating proppants. Conductivity tests are conducted according to ISO 13503-5:2006 (2006) and API RP 19D (2008) to examine how the coating process changes the relative permeability to water and oil. According to the simulation results, the newly developed graphite-coated proppants speed up the water cleanup and increase long-term oil production in an oil-wet reservoir.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/196067-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44977585","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}
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