Lijun Guan, Wei Zhang, P. Zhang, Yuqing Yang, Weiping Cui, Y. Li, Kun Meng, Liang Xiao
Tight sandstone reservoirs characterization and evaluation is very difficult based on conventional well log data owing to the extremely low porosity and permeability, and strong heterogeneity. The main accumulation spaces of conventional reservoirs are intergranular pores, and the pore size is the main controlling factor of permeability. However, besides intergranular pores, fractures play much greater important role in accumulating hydrocarbon, improving the pore connectivity and pore structure in tight sandstone reservoirs. Hence, it should be accurately predicted the pore structure dredged by fractures to improve the characterization of tight sandstone reservoirs. Generally, nuclear magnetic resonance (NMR) logging is an effective method to evaluate formation pore structure. However, it cannot be well used in fractured reservoirs because the NMR T2 spectra has no any response for fractures with width <2mm. The borehole electrical image log is usable in characterizing fractured reservoirs. The pore spectrum, which is extracted from the borehole electrical image log, can be used to qualitatively reflect the pore size. Hence, it will play an important role in fractured reservoirs pore structure characterization. In this study, based on the comprehensive analysis of the pore spectra, the corresponding mercury injection capillary pressure (MICP) data and pore-throat radius distributions acquired from core samples, a relationship that connects the 1/POR and capillary pressure (Pc) is proposed. Established a model based on formation classification to transform porosity spectrum into pseudo capillary pressure curve. In addition, a Swanson parameter-based permeability prediction model is also developed to extract fractured formation permeability. Meanwhile, to verify the superiority and otherness of borehole electrical image and NMR log, the model that evaluated reservoirs pore structure from NMR log is also established. Based on the application of the proposed method and models in actual formations, the evaluated pore structure parameters and permeabilities from two types of well log data are compared. The results illustrates that in formations with relative good pore structure, the predicted pore structure parameters and permeabilities from these two types of well log data agree well with the drill stem testing data and core-derived result. However, in low permeability sandstones with relatively poor pore structure, the porosity spectra can be well used to evaluate the pore structure, whereas the characterized pore structure from NMR log is overestimated. With the comprehensive research of reservoirs pore structure and permeability, the fractured tight sandstone formations with development value are precisely identified. This proposed method has greatest advantages that the pore structure of fractured reservoirs can be characterized, and the contribution of fractures to the pore connectivity and permeability can be quantified. it is usable in tight
{"title":"Comparisons of Evaluating Fractured Tight Sandstone Reservoirs Pore Structures Based on Borehole Electrical Image and Nuclear Magnetic Resonance NMR Logs","authors":"Lijun Guan, Wei Zhang, P. Zhang, Yuqing Yang, Weiping Cui, Y. Li, Kun Meng, Liang Xiao","doi":"10.2118/204875-ms","DOIUrl":"https://doi.org/10.2118/204875-ms","url":null,"abstract":"\u0000 Tight sandstone reservoirs characterization and evaluation is very difficult based on conventional well log data owing to the extremely low porosity and permeability, and strong heterogeneity. The main accumulation spaces of conventional reservoirs are intergranular pores, and the pore size is the main controlling factor of permeability. However, besides intergranular pores, fractures play much greater important role in accumulating hydrocarbon, improving the pore connectivity and pore structure in tight sandstone reservoirs. Hence, it should be accurately predicted the pore structure dredged by fractures to improve the characterization of tight sandstone reservoirs. Generally, nuclear magnetic resonance (NMR) logging is an effective method to evaluate formation pore structure. However, it cannot be well used in fractured reservoirs because the NMR T2 spectra has no any response for fractures with width <2mm. The borehole electrical image log is usable in characterizing fractured reservoirs. The pore spectrum, which is extracted from the borehole electrical image log, can be used to qualitatively reflect the pore size. Hence, it will play an important role in fractured reservoirs pore structure characterization. In this study, based on the comprehensive analysis of the pore spectra, the corresponding mercury injection capillary pressure (MICP) data and pore-throat radius distributions acquired from core samples, a relationship that connects the 1/POR and capillary pressure (Pc) is proposed. Established a model based on formation classification to transform porosity spectrum into pseudo capillary pressure curve. In addition, a Swanson parameter-based permeability prediction model is also developed to extract fractured formation permeability. Meanwhile, to verify the superiority and otherness of borehole electrical image and NMR log, the model that evaluated reservoirs pore structure from NMR log is also established. Based on the application of the proposed method and models in actual formations, the evaluated pore structure parameters and permeabilities from two types of well log data are compared. The results illustrates that in formations with relative good pore structure, the predicted pore structure parameters and permeabilities from these two types of well log data agree well with the drill stem testing data and core-derived result. However, in low permeability sandstones with relatively poor pore structure, the porosity spectra can be well used to evaluate the pore structure, whereas the characterized pore structure from NMR log is overestimated. With the comprehensive research of reservoirs pore structure and permeability, the fractured tight sandstone formations with development value are precisely identified. This proposed method has greatest advantages that the pore structure of fractured reservoirs can be characterized, and the contribution of fractures to the pore connectivity and permeability can be quantified. it is usable in tight","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78826393","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abdulmalek Shamsan, Alejandro De la Cruz, W. Jimenez
This study describes the approach used for enhancing the well integrity that was compromised with gas flow through a casing-casing annulus (CCA). Extremely tight injectivity at a CCA demands a solid free solution which not only can be injected but also resist high differential pressures to provide a long-term barrier in CCA. In this paper a successful leak remediation using an epoxy resin system helped the operator save a well and restart its production. Several pressure tests were conducted for identifying an extremely tight casing leak which was causing formation gas travelling to surface through the annulus. This issue required the customer to look for an efficient remedial solution to seal off the gas leakage and regain productivity. Due to the extremely low injectivity, a conventional cement squeeze or any solid laden particle-based squeeze approach was prone to fail. Alternatively, a tailored solid free epoxy resin system was placed in the annulus using an unconventional placement technique resulted in barrier enhancement and helped the operator place the well back into production. For a mature well flowing through 7 × 9 5/8‑in. and 9 5/8 × 13 3/8‑in., a tailored epoxy-based resin system formulation was placed in the well bore with modified surface operations procedures which helped in eliminating current annular pressure to regain well integrity and production. Remedial operations were performed from the surface by squeezing to seal off the gas coming from the annulus. A Tailored design derived from rigorous lab testing and perfect field execution resulted in CCA pressure remediation in a single attempt of the treatment injection, proving that the concept of using a solids-free resin to enhance existing deteriorated barriers is a reliable method. This epoxy resin system helped the operator to regain the well integrity and production in the shortest time without expensive well intervention operations. Epoxy resin based systems have been identified as a novel solution to remediate barrier integrity for well construction and workover operations, hence such case histories with enhanced operations procedures are helpful in increasing awareness of the benefits that can be attained in challenging high-pressure, low-injectivity environments, and can improve well economics.
{"title":"Successful Barrier Enhancement Application of Epoxy Based Resin for Multiple Casing to Casing Annuli Having Tight Injectivity - Case Study from Saudi Arabian Peninsula","authors":"Abdulmalek Shamsan, Alejandro De la Cruz, W. Jimenez","doi":"10.2118/204780-ms","DOIUrl":"https://doi.org/10.2118/204780-ms","url":null,"abstract":"\u0000 This study describes the approach used for enhancing the well integrity that was compromised with gas flow through a casing-casing annulus (CCA). Extremely tight injectivity at a CCA demands a solid free solution which not only can be injected but also resist high differential pressures to provide a long-term barrier in CCA. In this paper a successful leak remediation using an epoxy resin system helped the operator save a well and restart its production. Several pressure tests were conducted for identifying an extremely tight casing leak which was causing formation gas travelling to surface through the annulus. This issue required the customer to look for an efficient remedial solution to seal off the gas leakage and regain productivity. Due to the extremely low injectivity, a conventional cement squeeze or any solid laden particle-based squeeze approach was prone to fail. Alternatively, a tailored solid free epoxy resin system was placed in the annulus using an unconventional placement technique resulted in barrier enhancement and helped the operator place the well back into production. For a mature well flowing through 7 × 9 5/8‑in. and 9 5/8 × 13 3/8‑in., a tailored epoxy-based resin system formulation was placed in the well bore with modified surface operations procedures which helped in eliminating current annular pressure to regain well integrity and production. Remedial operations were performed from the surface by squeezing to seal off the gas coming from the annulus. A Tailored design derived from rigorous lab testing and perfect field execution resulted in CCA pressure remediation in a single attempt of the treatment injection, proving that the concept of using a solids-free resin to enhance existing deteriorated barriers is a reliable method. This epoxy resin system helped the operator to regain the well integrity and production in the shortest time without expensive well intervention operations. Epoxy resin based systems have been identified as a novel solution to remediate barrier integrity for well construction and workover operations, hence such case histories with enhanced operations procedures are helpful in increasing awareness of the benefits that can be attained in challenging high-pressure, low-injectivity environments, and can improve well economics.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85068563","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The difficulty of hydraulic fracturing in organic-rich shale caused by the increased ductility has not been well interpreted quantitatively, although it is well perceived that the increased shale ductility can impede the propagation of hydraulic fractures and enhance the healing of created fractures upon injection shutdown. This study aims to quantitatively study the impacts of increased ductility on the stimulated reservoir volume (SRV) using an advanced XFEM-based simulator. To achieve this goal, a modified cohesive zone model has been integrated into an in-house fully coupled poroelastic XFEM framework. The study continues by extending the functionality of the numerical framework to simulating multiple interacting fractures. The utilization of the object-oriented programming paradigm in the development of the framework makes it an easy extension to include the multi-fracture network by creating more instances of crack segments. A main hydraulic fracture with an arbitrary number of intersected branches can thus be modeled. A series of parametric studies will be conducted to investigate the impacts of increased ductility on the induced SRV by varying four involved material parameters individually. The modified cohesive zone model, which is essentially a traction-separation law (TSL), is characterized by four parameters: the initial tensile strength Tini, ultimate tensile strength Tkrg, the critical separation Dc, and the final crack separation Dmax. It can flexibly model different crack opening scenarios and simulate more realistically the increased shale ductility. The fully coupled poroelastic XFEM framework has been comprehensively verified against the latest semi-analytical solutions on the four well-known propagation regimes. The numerical results show that the shape of TSL does affect the main hydraulic fracture growth as well as the evolvement of the fracture network, given the same cohesive crack energy and tensile strength. It infers that ductility is not only controlled by cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed cohesive zone model. The magnitude of the initial tensile strength, controlling when the cohesive crack starts propagating, is found to have the greatest impacts on the fracture length, and SRV, among all four TSL parameters. The novelty of this study is two-fold. First, the newly modified cohesive zone model can more realistically represent the increased shale ductility. Second, the advanced XFEM framework that enables the simulation of a fracture network can study the impacts of increased ductility on the whole SRV but not a single crack.
{"title":"The Impacts of Increased Ductility in Organic-Rich Shale on Fracture Network Growth by Hydraulic Fracturing","authors":"Chang Huang, Shengli Chen","doi":"10.2118/204858-ms","DOIUrl":"https://doi.org/10.2118/204858-ms","url":null,"abstract":"\u0000 The difficulty of hydraulic fracturing in organic-rich shale caused by the increased ductility has not been well interpreted quantitatively, although it is well perceived that the increased shale ductility can impede the propagation of hydraulic fractures and enhance the healing of created fractures upon injection shutdown. This study aims to quantitatively study the impacts of increased ductility on the stimulated reservoir volume (SRV) using an advanced XFEM-based simulator.\u0000 To achieve this goal, a modified cohesive zone model has been integrated into an in-house fully coupled poroelastic XFEM framework. The study continues by extending the functionality of the numerical framework to simulating multiple interacting fractures. The utilization of the object-oriented programming paradigm in the development of the framework makes it an easy extension to include the multi-fracture network by creating more instances of crack segments. A main hydraulic fracture with an arbitrary number of intersected branches can thus be modeled. A series of parametric studies will be conducted to investigate the impacts of increased ductility on the induced SRV by varying four involved material parameters individually.\u0000 The modified cohesive zone model, which is essentially a traction-separation law (TSL), is characterized by four parameters: the initial tensile strength Tini, ultimate tensile strength Tkrg, the critical separation Dc, and the final crack separation Dmax. It can flexibly model different crack opening scenarios and simulate more realistically the increased shale ductility. The fully coupled poroelastic XFEM framework has been comprehensively verified against the latest semi-analytical solutions on the four well-known propagation regimes. The numerical results show that the shape of TSL does affect the main hydraulic fracture growth as well as the evolvement of the fracture network, given the same cohesive crack energy and tensile strength. It infers that ductility is not only controlled by cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed cohesive zone model. The magnitude of the initial tensile strength, controlling when the cohesive crack starts propagating, is found to have the greatest impacts on the fracture length, and SRV, among all four TSL parameters.\u0000 The novelty of this study is two-fold. First, the newly modified cohesive zone model can more realistically represent the increased shale ductility. Second, the advanced XFEM framework that enables the simulation of a fracture network can study the impacts of increased ductility on the whole SRV but not a single crack.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82051686","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Bipin Jain, Abhijeet Tambe, Dylan Waugh, M. Munozrivera, Rianne Campbell
Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further. A new generation of cement system was used to overcome the remedial challenge presented in these injector wells. This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.
{"title":"Successful Remediation of Sustained Casing Pressures in Gas Cap Injector Wells with the Use of Flexible and Self Healing System","authors":"Bipin Jain, Abhijeet Tambe, Dylan Waugh, M. Munozrivera, Rianne Campbell","doi":"10.2118/204568-ms","DOIUrl":"https://doi.org/10.2118/204568-ms","url":null,"abstract":"\u0000 Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further.\u0000 A new generation of cement system was used to overcome the remedial challenge presented in these injector wells.\u0000 This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81826870","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper, the multi-porosity multi-permeability porothermoelastic theory is used to derive the analytical solution to calculate the pressure- and temperature-dependent fracturing fluid loss. A triple-porosity triple-permeability source rock formation is selected as an example to illustrate the model. The effects of fracturing fluid temperature and natural fractures on the fluid loss rate are systematically illustrated. The model successfully accounts for the varying leak-off rates in the multi-permeability channels through the hydraulic fracture faces. Furthermore, thermal diffusion near the hydraulic fracture faces contributes to a variation of pore pressure whose gradient at hydraulic fracture faces directly controls the fracturing fluid leak-off rate. The model shows that thermal effects bring almost 27% variation in the leak-off rate. Comparison study indicates that the single porosity model without considering multi-permeability systems or thermal effects significantly underestimates the rate of fracturing fluid loss and predicts nearly 84% and 87% lower leak-off rate, compared to the dual-porosity dual-permeability and triple-porosity triple-permeability models, respectively. Two case studies using published laboratory measurements on naturally fractured Blue Ohio sandstone samples are conducted to show the performances of the model. It is shown that the model presented in this paper well captures the total leak-off volume during the pressure-dependent fluid loss measured from laboratory tests. Matching the analytical solution to the laboratory data also allows rocks’ double permeabilities to be estimated.
{"title":"Simulation of Pressure- and Temperature-Dependent Fracturing Fluid Loss in Multi-Porosity Multi-Permeability Formations","authors":"Chao Liu, Dung T. Phan, Y. Abousleiman","doi":"10.2118/204581-ms","DOIUrl":"https://doi.org/10.2118/204581-ms","url":null,"abstract":"\u0000 In this paper, the multi-porosity multi-permeability porothermoelastic theory is used to derive the analytical solution to calculate the pressure- and temperature-dependent fracturing fluid loss. A triple-porosity triple-permeability source rock formation is selected as an example to illustrate the model. The effects of fracturing fluid temperature and natural fractures on the fluid loss rate are systematically illustrated. The model successfully accounts for the varying leak-off rates in the multi-permeability channels through the hydraulic fracture faces. Furthermore, thermal diffusion near the hydraulic fracture faces contributes to a variation of pore pressure whose gradient at hydraulic fracture faces directly controls the fracturing fluid leak-off rate. The model shows that thermal effects bring almost 27% variation in the leak-off rate. Comparison study indicates that the single porosity model without considering multi-permeability systems or thermal effects significantly underestimates the rate of fracturing fluid loss and predicts nearly 84% and 87% lower leak-off rate, compared to the dual-porosity dual-permeability and triple-porosity triple-permeability models, respectively. Two case studies using published laboratory measurements on naturally fractured Blue Ohio sandstone samples are conducted to show the performances of the model. It is shown that the model presented in this paper well captures the total leak-off volume during the pressure-dependent fluid loss measured from laboratory tests. Matching the analytical solution to the laboratory data also allows rocks’ double permeabilities to be estimated.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79848116","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
N. Aljabri, Hussain Shatteb, Mustafa Saffar, A. Abdelfattah
Nanoencapsulation and targeted chemical delivery techniques have transformed many fields such as pharmaceutical drug delivery for medical treatment and diagnosis, and can similarly transform several upstream oil and gas operations. This paper describes the dual nanoencapsulation of superparamagnetic iron oxide nanoparticles (SPOINs) and petroleum sulfonate surfactants to produce hybrid nanosurfactant (MLHNS) in high-salinity water (56,000 ppm) using an inexpensive, scalable, and straightforward synthesis protocol. This novel magnetically labelled nanofluid (NF) is designed to: 1) enhance the residual oil mobilization via altering the rocks wettability and reducing the interfacial tension, and 2) enable in-situ monitoring of injected fluids when combined with EM surveys. NFs encapsulating a petroleum sulfonate surfactant and three different concentrations of 5-nm SPOINs were prepared using a two-step nanoencapsulation method. Both colloidal and chemical stability of the prepared formulations were tested at 90 °C for over a year. Results showed that all the formulations exhibited remarkable long-term colloidal and chemical stability under these close-to-reservoir conditions. Transition electron microscopy (TEM) images confirmed the encapsulation of SPIONs. The SPOINs-NFs have successfully reduced the interfacial tension (IFT) between crude oil and water by more than three orders of magnitude (from ~ 25 mN/m down to ~ 0.01 mN/m). These IFT and stability results demonstrate a strong synergy between SPIONs and the petroleum sulfonate surfactant. It is worth mentioning that this novel encapsulation platform enables the encapsulation of a wide range of nanoparticles (NPs) to generate a library of multi-function NFs to support several upstream applications.
{"title":"Magnetically Labelled Hybrid Nanosurfactant MLHNS for Upstream Oil and Gas Operations","authors":"N. Aljabri, Hussain Shatteb, Mustafa Saffar, A. Abdelfattah","doi":"10.2118/204843-ms","DOIUrl":"https://doi.org/10.2118/204843-ms","url":null,"abstract":"\u0000 Nanoencapsulation and targeted chemical delivery techniques have transformed many fields such as pharmaceutical drug delivery for medical treatment and diagnosis, and can similarly transform several upstream oil and gas operations. This paper describes the dual nanoencapsulation of superparamagnetic iron oxide nanoparticles (SPOINs) and petroleum sulfonate surfactants to produce hybrid nanosurfactant (MLHNS) in high-salinity water (56,000 ppm) using an inexpensive, scalable, and straightforward synthesis protocol. This novel magnetically labelled nanofluid (NF) is designed to: 1) enhance the residual oil mobilization via altering the rocks wettability and reducing the interfacial tension, and 2) enable in-situ monitoring of injected fluids when combined with EM surveys.\u0000 NFs encapsulating a petroleum sulfonate surfactant and three different concentrations of 5-nm SPOINs were prepared using a two-step nanoencapsulation method. Both colloidal and chemical stability of the prepared formulations were tested at 90 °C for over a year. Results showed that all the formulations exhibited remarkable long-term colloidal and chemical stability under these close-to-reservoir conditions. Transition electron microscopy (TEM) images confirmed the encapsulation of SPIONs. The SPOINs-NFs have successfully reduced the interfacial tension (IFT) between crude oil and water by more than three orders of magnitude (from ~ 25 mN/m down to ~ 0.01 mN/m). These IFT and stability results demonstrate a strong synergy between SPIONs and the petroleum sulfonate surfactant. It is worth mentioning that this novel encapsulation platform enables the encapsulation of a wide range of nanoparticles (NPs) to generate a library of multi-function NFs to support several upstream applications.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80383091","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Fiber optics has many applications in the oil and gas industry. In recent years, fiber optics has found usefulness in leak detection. The leaks can be efficiently identified using fiber-optic distributed temperature sensing measurement, thereby mitigating the health, safety, and environmental (HSE) risk associated with well integrity. Further, a production log can be used to gain more insight and finalize a way ahead to resolve well integrity issues. An innovative solution-driven approach was defined, with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the well completion, and a fiber-optic cable was run to identify possible areas of the leak path. After the fiber-optic data acquisition, a production log was recorded across selective depths to provide an insight on leak paths. After identifying leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of the fiber-optic acquisition and production log. Results are presented for a well where multiple leaks were successfully identified using the novel operational approach. Further, operational time was reduced from 3 days (conventional slickline memory or e-line logging performed during daylight operation) to 1 day (a combination of fiber-optic distributed temperature sensing and production log in a single run). The diagnosis of production system issues was completed in one shut-in and one flowing condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (to simulate the leak while the conventional production logging tool is moved to different depths in the well). Additional insight on leak quantification was confirmed from the production log data, where one leak was noted at the tubing collar while the other leak was noted a few meters above the tubing collar. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing. The novel operational approach affirms fiber-optic distributed temperature measurement's versatility in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing measurement.
{"title":"Well Integrity Leak Diagnostic Using Fiber-Optic Distributed Temperature Sensing and Production Logging","authors":"Joerg Abeling, U. Bartels, Kamaljeet Singh, Shaktim Dutta, Gaurav Agrawal, Apoorva Kumar","doi":"10.2118/204557-ms","DOIUrl":"https://doi.org/10.2118/204557-ms","url":null,"abstract":"\u0000 Fiber optics has many applications in the oil and gas industry. In recent years, fiber optics has found usefulness in leak detection. The leaks can be efficiently identified using fiber-optic distributed temperature sensing measurement, thereby mitigating the health, safety, and environmental (HSE) risk associated with well integrity. Further, a production log can be used to gain more insight and finalize a way ahead to resolve well integrity issues.\u0000 An innovative solution-driven approach was defined, with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the well completion, and a fiber-optic cable was run to identify possible areas of the leak path. After the fiber-optic data acquisition, a production log was recorded across selective depths to provide an insight on leak paths. After identifying leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of the fiber-optic acquisition and production log.\u0000 Results are presented for a well where multiple leaks were successfully identified using the novel operational approach. Further, operational time was reduced from 3 days (conventional slickline memory or e-line logging performed during daylight operation) to 1 day (a combination of fiber-optic distributed temperature sensing and production log in a single run). The diagnosis of production system issues was completed in one shut-in and one flowing condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (to simulate the leak while the conventional production logging tool is moved to different depths in the well). Additional insight on leak quantification was confirmed from the production log data, where one leak was noted at the tubing collar while the other leak was noted a few meters above the tubing collar. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing.\u0000 The novel operational approach affirms fiber-optic distributed temperature measurement's versatility in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing measurement.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75072341","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Huijuan Guo, Huaidong Luo, G. Zhan, Baodong Wang, Shuo Zhu
With highly deviated wells and horizontal wells are widely used in the oil industry. The large slope well sections and long horizontal well sections will lead to a sharp increase of the drill string torque and friction, which may reduce the drilling efficiency, and even lead to accidents. Therefore, real-time and accurate analysis of drill string’s torque and friction is an urgent problem facing by the modern drilling technology. The paper established a real-time friction prediction model that combines machine learning methods with drill string mechanical mechanism analysis model. Based on 84000 sets of field monitoring data obtained on-site, a regular data training set for weight on bit (WOB) and torque prediction was constructed with 23 types of time-series related parameters and 10 types of timing independent parameters. Relationships between time-series related parameters and timing independent parameters with the weight on bit and torque were trained to utilize long and short-term memory (LSTM) neural network and muti-layer back propagation (BP) network respectively. The new developed LSTM-BP neural network achieves high-precision prediction results of WOB and torque with a relative error of less than 14%. Based on derived WOB and torque prediction results, a theoretical mechanical analysis model of the entire drill string was adopted in this paper to develop the quantitative relation between WOB and torque with the friction coefficient of the drill string and oil casing. Suitable friction coefficients along the drill string can be finally obtained by solving the equilibrium function between predicted WOB, torque and measured hook load, rotary-table torque via an iteration algorithm. A case study was performed finally using the proposed intelligent analysis method to calculate the friction coefficients. This proposed methodology can be referenced to decrease the sticking risks and improve the drilling efficiency, which can finally increase the extension limit of horizontal wells in complex strata.
{"title":"A Real-Time Friction Prediction Model for in Service Drill String Based on Machine Learning Methods Coupling with Mechanical Mechanism Analysis","authors":"Huijuan Guo, Huaidong Luo, G. Zhan, Baodong Wang, Shuo Zhu","doi":"10.2118/204738-ms","DOIUrl":"https://doi.org/10.2118/204738-ms","url":null,"abstract":"\u0000 With highly deviated wells and horizontal wells are widely used in the oil industry. The large slope well sections and long horizontal well sections will lead to a sharp increase of the drill string torque and friction, which may reduce the drilling efficiency, and even lead to accidents. Therefore, real-time and accurate analysis of drill string’s torque and friction is an urgent problem facing by the modern drilling technology. The paper established a real-time friction prediction model that combines machine learning methods with drill string mechanical mechanism analysis model. Based on 84000 sets of field monitoring data obtained on-site, a regular data training set for weight on bit (WOB) and torque prediction was constructed with 23 types of time-series related parameters and 10 types of timing independent parameters. Relationships between time-series related parameters and timing independent parameters with the weight on bit and torque were trained to utilize long and short-term memory (LSTM) neural network and muti-layer back propagation (BP) network respectively. The new developed LSTM-BP neural network achieves high-precision prediction results of WOB and torque with a relative error of less than 14%. Based on derived WOB and torque prediction results, a theoretical mechanical analysis model of the entire drill string was adopted in this paper to develop the quantitative relation between WOB and torque with the friction coefficient of the drill string and oil casing. Suitable friction coefficients along the drill string can be finally obtained by solving the equilibrium function between predicted WOB, torque and measured hook load, rotary-table torque via an iteration algorithm. A case study was performed finally using the proposed intelligent analysis method to calculate the friction coefficients. This proposed methodology can be referenced to decrease the sticking risks and improve the drilling efficiency, which can finally increase the extension limit of horizontal wells in complex strata.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79888981","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Q. Looni, Malik. M Humood, A. Mousa, Mahdi Al Tarooti
Inflow Control Devices (ICD) (Fig. 1) is a part of the well completion to help optimizing the production by equalizing the reservoir inflow. Multiple ICD can be installed in the completion at a long section, as each ICD going to partially choke the flow. Completing wells with ICD is one of the most common techniques that is used to maintain uniform production across multi-layer reservoirs. One of the challenges in such completions is to achieve a uniform matrix acid stimulation across these screens due to well deviation and length of the screens. In most cases an effective diversion method is required during acid treatment to ensure all the screens are treated uniformly for maintaining homogeneous production across the reservoir. Over the time, wells with ICD screens show decline in production due to plugged screens which necessitates immediate action. In most cases remedy is to acid treat all ICD screens on individual basis using straddle packer System and real-time telemetry coil system due to requirements of diversion method, criticality of the packer setting depth and downhole pressure monitoring. Multistage acid stimulation for ICD screens is achieved using straddle packer's system with real-time telemetry coiled tubing (CT). The real-time telemetry coil system ensures depth accuracy – as each ICD port length is not more than couple of inches – and monitoring of pressures and straddle packer system's integrity during multistage acid stimulation across the horizontal screens. This operation involves challenges of properly setting the packer to selectively treat each ICD screen by mechanically diverting the acid treatment while maintaining seal integrity in each stage and re-using it multiple times. After drifting and wellbore conditioning run, the multi-set straddle packer system is deployed on real-time telemetry coil (fiber-optic enabled) for multistage acid treatment. Starting from total depth, the real-time CCL readings are utilized successfully to identify the first screens joint allowing the packer system to be stationed across the required screen. The packer elements are then energized to divert the acid treatment fluid into the targeted screen Thru the coil and exiting from per adjusted nozzles between the Packers; this diversion is confirmed by monitoring bottom hole pressure inside and outside the coil tubing string. Upon completion of the acid treatment of the ICD screens the tension-compression sub of telemetry coil system confirmed the elements is de-energized to make safe to move the packer without damaging the elements. The treatment is then successfully repeated across the remaining ICD screens with positive indication of diversion across each ICD screen. This study illustrates how the combination of the straddle packer System and downhole real-time telemetry system was utilized to successfully acid stimulate up to 38 stages and monitor the behavior of straddle packer continuously during diversion of multistage acid trea
{"title":"Multistage Acid Stimulation for ICD Screens Completion Using Straddle Packer and Real-Time Telemetry Coil Tubing","authors":"Q. Looni, Malik. M Humood, A. Mousa, Mahdi Al Tarooti","doi":"10.2118/204830-ms","DOIUrl":"https://doi.org/10.2118/204830-ms","url":null,"abstract":"\u0000 Inflow Control Devices (ICD) (Fig. 1) is a part of the well completion to help optimizing the production by equalizing the reservoir inflow. Multiple ICD can be installed in the completion at a long section, as each ICD going to partially choke the flow.\u0000 Completing wells with ICD is one of the most common techniques that is used to maintain uniform production across multi-layer reservoirs. One of the challenges in such completions is to achieve a uniform matrix acid stimulation across these screens due to well deviation and length of the screens. In most cases an effective diversion method is required during acid treatment to ensure all the screens are treated uniformly for maintaining homogeneous production across the reservoir.\u0000 Over the time, wells with ICD screens show decline in production due to plugged screens which necessitates immediate action. In most cases remedy is to acid treat all ICD screens on individual basis using straddle packer System and real-time telemetry coil system due to requirements of diversion method, criticality of the packer setting depth and downhole pressure monitoring. Multistage acid stimulation for ICD screens is achieved using straddle packer's system with real-time telemetry coiled tubing (CT). The real-time telemetry coil system ensures depth accuracy – as each ICD port length is not more than couple of inches – and monitoring of pressures and straddle packer system's integrity during multistage acid stimulation across the horizontal screens.\u0000 This operation involves challenges of properly setting the packer to selectively treat each ICD screen by mechanically diverting the acid treatment while maintaining seal integrity in each stage and re-using it multiple times. After drifting and wellbore conditioning run, the multi-set straddle packer system is deployed on real-time telemetry coil (fiber-optic enabled) for multistage acid treatment. Starting from total depth, the real-time CCL readings are utilized successfully to identify the first screens joint allowing the packer system to be stationed across the required screen. The packer elements are then energized to divert the acid treatment fluid into the targeted screen Thru the coil and exiting from per adjusted nozzles between the Packers; this diversion is confirmed by monitoring bottom hole pressure inside and outside the coil tubing string. Upon completion of the acid treatment of the ICD screens the tension-compression sub of telemetry coil system confirmed the elements is de-energized to make safe to move the packer without damaging the elements. The treatment is then successfully repeated across the remaining ICD screens with positive indication of diversion across each ICD screen.\u0000 This study illustrates how the combination of the straddle packer System and downhole real-time telemetry system was utilized to successfully acid stimulate up to 38 stages and monitor the behavior of straddle packer continuously during diversion of multistage acid trea","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81605177","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ayman Almohsin, Jin-Chao Hung, M. Alabdrabalnabi, M. Sherief
Minimizing unwanted water production from oil wells is highly required in the petroleum industry. This would lead to improved economic life of mature wells that involve new and innovative technologies. Nanosilica-based sealing fluid has been developed to address problems associated with unwanted water production. The objective of this work is to evaluate a newly developed novel water shutoff system based on nanosilica over a wide range of parameters. This modified nanosilica has a smooth, spherical shape, and are present in a narrow particle size distribution. Therefore, it can be used for water management in different water production mechanisms including high permeability streak, wormhole, and fractured reservoirs. A systematic evaluation of novel nanosilica/activator for water shutoff purposes requires the examination of the chemical properties before, during, and after gelation at given reservoir conditions. These properties are solution initial viscosity, gelation time, injectivity, and strength of the formed gel against applied external forces in different flooding systems. This paper details a promising method to control undesired water production using eco-friendly, cost-effective nanosilica. Experimental results revealed that nanosilica initially exhibited a low viscosity and hence providing a significant advantage in terms of mixing and pumping requirements. Nanosilica gelation time, which is a critical factor in placement of injected-chemical treatment, can be tailored by adjusting the activator concentration to match field requirements at the desired temperature. In addition, core flood tests were conducted in carbonate core plugs, Berea sandstone rock, and artificially fractured (metal tube) to investigate the performance of the chemical treatment. Flow tests clearly indicated that the water production significantly dropped in all tested types of rocks. The environmental scanning electron microscope (SEM) results showed the presence of SiO-rich compounds suggesting that the tested nanosilica product filled the porous media; therefore, it blocked the whole core plug. A novel cost-effective sealant that uses nanotechnology to block the near wellbore region has been developed. The performance and methods controlling its propagation rate into a porous medium will be presented. Based on the outcomes, it must be emphasized that these trivial particles have a promising application in the oil reservoir for water shutoff purposes.
{"title":"A Nano Method for a Big Challenge: Nanosilica-Based Sealing System for Water Shutoff","authors":"Ayman Almohsin, Jin-Chao Hung, M. Alabdrabalnabi, M. Sherief","doi":"10.2118/204840-ms","DOIUrl":"https://doi.org/10.2118/204840-ms","url":null,"abstract":"\u0000 Minimizing unwanted water production from oil wells is highly required in the petroleum industry. This would lead to improved economic life of mature wells that involve new and innovative technologies. Nanosilica-based sealing fluid has been developed to address problems associated with unwanted water production. The objective of this work is to evaluate a newly developed novel water shutoff system based on nanosilica over a wide range of parameters. This modified nanosilica has a smooth, spherical shape, and are present in a narrow particle size distribution. Therefore, it can be used for water management in different water production mechanisms including high permeability streak, wormhole, and fractured reservoirs. A systematic evaluation of novel nanosilica/activator for water shutoff purposes requires the examination of the chemical properties before, during, and after gelation at given reservoir conditions. These properties are solution initial viscosity, gelation time, injectivity, and strength of the formed gel against applied external forces in different flooding systems.\u0000 This paper details a promising method to control undesired water production using eco-friendly, cost-effective nanosilica. Experimental results revealed that nanosilica initially exhibited a low viscosity and hence providing a significant advantage in terms of mixing and pumping requirements. Nanosilica gelation time, which is a critical factor in placement of injected-chemical treatment, can be tailored by adjusting the activator concentration to match field requirements at the desired temperature. In addition, core flood tests were conducted in carbonate core plugs, Berea sandstone rock, and artificially fractured (metal tube) to investigate the performance of the chemical treatment. Flow tests clearly indicated that the water production significantly dropped in all tested types of rocks. The environmental scanning electron microscope (SEM) results showed the presence of SiO-rich compounds suggesting that the tested nanosilica product filled the porous media; therefore, it blocked the whole core plug. A novel cost-effective sealant that uses nanotechnology to block the near wellbore region has been developed. The performance and methods controlling its propagation rate into a porous medium will be presented. Based on the outcomes, it must be emphasized that these trivial particles have a promising application in the oil reservoir for water shutoff purposes.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81764978","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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：