Shairizal B. Badzri, Swee Fung Lim, Nordiana Jamil, A. H. Hassan
HSSE digitalisation and big data analytics in Oil and Gas industry present a multitude of challenges which includes the inconsistency of work processes in data management, questionable data integrity, high operating cost in managing digital systems, lack of visibility and the mindset shift of users. These challenges have led to the digital transformation journey in PETRONAS. Since PETRONAS embarked on the digitalisation and analytic transformation, numerous value creations have been recorded namely improved HSSE performance, compliance to internal and HSSE regulatory requirements, cost value realization and supporting the United Nations Sustainable Development Goals (UN SDGs). The objective of this paper is to provide strategy guidance in HSSE system digitalisation and data analytics enhancement. The inclusion of digitalisation as one of the focus areas in PETRONAS HSSE Strategy and its supporting blocks in realising the bigger digitalisation agenda can be emulated and/or referenced by industry peers who face similar challenges and are keen to embark on the transformation journey.
{"title":"Myhsse – Analytic Transformation of Health, Safety, Security and Environment HSSE in Making Prescriptive Possible Towards Zero Incident; Geared by End Users’ Pain Points","authors":"Shairizal B. Badzri, Swee Fung Lim, Nordiana Jamil, A. H. Hassan","doi":"10.2523/iptc-22572-ms","DOIUrl":"https://doi.org/10.2523/iptc-22572-ms","url":null,"abstract":"\u0000 HSSE digitalisation and big data analytics in Oil and Gas industry present a multitude of challenges which includes the inconsistency of work processes in data management, questionable data integrity, high operating cost in managing digital systems, lack of visibility and the mindset shift of users. These challenges have led to the digital transformation journey in PETRONAS.\u0000 Since PETRONAS embarked on the digitalisation and analytic transformation, numerous value creations have been recorded namely improved HSSE performance, compliance to internal and HSSE regulatory requirements, cost value realization and supporting the United Nations Sustainable Development Goals (UN SDGs).\u0000 The objective of this paper is to provide strategy guidance in HSSE system digitalisation and data analytics enhancement. The inclusion of digitalisation as one of the focus areas in PETRONAS HSSE Strategy and its supporting blocks in realising the bigger digitalisation agenda can be emulated and/or referenced by industry peers who face similar challenges and are keen to embark on the transformation journey.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91271914","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}
T. Zharnikov, R. Ponomarenko, A. Nikitin, C. Ayadiuno
This paper presents the analysis of borehole acoustic logging response in anisotropic rocks under geomechanical stress. Several effects, which are relevant to the interpretation of sonic logs, are observed and discussed. First, it is shown that the crossover of flexural modes dispersion curves in stress-induced anisotropic formation do not necessarily occur. Second, it is demonstrated that the effects of the difference in orientation of principal stress and anisotropy axes directions, stress magnitudes, and degree of anisotropy on the flexural dispersions can compensate each other at least partially. Finally, the examples of measurable stress effects on the dispersion curves in anisotropic formations are presented. The implication of these observations for the formation stress evaluation from sonic logs in the case of anisotropic formation is that the stress estimation from sonic logs should focus not only on stress magnitudes, but also take into account formation anisotropy and stress orientation with respect to the borehole and anisotropy axes.
{"title":"Analysis of the Effect of Geomechanical Stress on the Acoustic Response of Anisotropic Rocks","authors":"T. Zharnikov, R. Ponomarenko, A. Nikitin, C. Ayadiuno","doi":"10.2523/iptc-22321-ea","DOIUrl":"https://doi.org/10.2523/iptc-22321-ea","url":null,"abstract":"\u0000 This paper presents the analysis of borehole acoustic logging response in anisotropic rocks under geomechanical stress. Several effects, which are relevant to the interpretation of sonic logs, are observed and discussed. First, it is shown that the crossover of flexural modes dispersion curves in stress-induced anisotropic formation do not necessarily occur. Second, it is demonstrated that the effects of the difference in orientation of principal stress and anisotropy axes directions, stress magnitudes, and degree of anisotropy on the flexural dispersions can compensate each other at least partially. Finally, the examples of measurable stress effects on the dispersion curves in anisotropic formations are presented. The implication of these observations for the formation stress evaluation from sonic logs in the case of anisotropic formation is that the stress estimation from sonic logs should focus not only on stress magnitudes, but also take into account formation anisotropy and stress orientation with respect to the borehole and anisotropy axes.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78328422","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}
Choong Heng Lim, T. Dharmadji, Azrin Kassim, Muhammad Usman Ul Haq Sethi, Muhammad Kamran Qureshi
Malaysia has introduced a shallow-water enhanced profitability term (EPT) production sharing contract (PSC) in the year 2021 to reward a PSC contractor with equitable returns reflecting the business risk and the opportunity to accelerate development and monetization. This study evaluates the attractiveness of the EPT against several fiscal terms adopted in southeast Asia, including Indonesia, Vietnam, Thailand, and Myanmar. This paper established an offshore shallow-water field development analogue project with a total production volume of 68 MMbbl, capital expenditure (Capex) of USD 530 million, predevelopment operating expenditure (Opex) of USD 36 million, variable Opex of USD 12.5/bbl, floating production storage and offloading (FPSO) rental of USD 61 million/year, and abandonment capital of USD 101 million. High, base, and low scenarios are considered for oil price per barrel as USD 70, 60, and 50, respectively, and production volume scenarios as 78, 68, and 58 MMbbl, respectively. These values with certain fiscal assumptions are input into a fiscal model engine for economic indicators [net present value (NPV), rate of return (ROR), and payback], revenue take, after-tax cashflow, and variables sensitivity calculations to evaluate base, optimistic, and pessimistic cases. In the base case, the attractiveness order of countries based on a higher-positive NPV at 10% and ROR are Malaysia EPT (NPV at 10% = USD 198 million, ROR = 30.4%), Indonesia PSC (2017) (NPV at 10% = USD 149 million, ROR = 28.3%), and Thailand Royalty and Tax (R/T; 1991) (NPV at 10% = USD 32 million, ROR = 14.5%). In the optimistic case, the NPVs at 10% are improved, ranging from Thailand (+271%), Myanmar (+247%), Malaysia (+151%), and Indonesia and Vietnam (+141%) as compared to the base case. In the pessimistic case, all the fiscal terms are unfeasible for ROR at 10%. Myanmar PSC (1993) yields above 10% ROR only when the production is at the base or high scenario with oil price at USD 70/bbl. Vietnam PSC (2013) is unfeasible for positive NPV at 10% even with high oil price under various taxes, including the windfall profit tax. Indonesia has a better NPV at 10% at a low oil price because of the progressive split that subsidizes the operator. Oil price and production volume are the top two sensitive variables except for Vietnam, where capital is the highest. The contractor take is higher in Malaysia, followed by Indonesia, Thailand, Myanmar, and Vietnam at base and high oil price. When the oil price is low, Indonesia generated a higher contractor take than Malaysia. Malaysia EPT is the only fiscal regime that can generate a contractor take that is higher than government take and stagnant around 55% against the 40% in Indonesia. In conclusion, Malaysia EPT provides a better investment return when the oil price is USD 60/bbl and above, while Indonesia gross split is more profitable when the oil price is low. This study provides insights on the potential investment returns
{"title":"Competitive Evaluation of Malaysia Enhanced Profitability Terms with Southeast Asia Fiscal Terms","authors":"Choong Heng Lim, T. Dharmadji, Azrin Kassim, Muhammad Usman Ul Haq Sethi, Muhammad Kamran Qureshi","doi":"10.2523/iptc-22162-ms","DOIUrl":"https://doi.org/10.2523/iptc-22162-ms","url":null,"abstract":"\u0000 Malaysia has introduced a shallow-water enhanced profitability term (EPT) production sharing contract (PSC) in the year 2021 to reward a PSC contractor with equitable returns reflecting the business risk and the opportunity to accelerate development and monetization. This study evaluates the attractiveness of the EPT against several fiscal terms adopted in southeast Asia, including Indonesia, Vietnam, Thailand, and Myanmar.\u0000 This paper established an offshore shallow-water field development analogue project with a total production volume of 68 MMbbl, capital expenditure (Capex) of USD 530 million, predevelopment operating expenditure (Opex) of USD 36 million, variable Opex of USD 12.5/bbl, floating production storage and offloading (FPSO) rental of USD 61 million/year, and abandonment capital of USD 101 million. High, base, and low scenarios are considered for oil price per barrel as USD 70, 60, and 50, respectively, and production volume scenarios as 78, 68, and 58 MMbbl, respectively. These values with certain fiscal assumptions are input into a fiscal model engine for economic indicators [net present value (NPV), rate of return (ROR), and payback], revenue take, after-tax cashflow, and variables sensitivity calculations to evaluate base, optimistic, and pessimistic cases.\u0000 In the base case, the attractiveness order of countries based on a higher-positive NPV at 10% and ROR are Malaysia EPT (NPV at 10% = USD 198 million, ROR = 30.4%), Indonesia PSC (2017) (NPV at 10% = USD 149 million, ROR = 28.3%), and Thailand Royalty and Tax (R/T; 1991) (NPV at 10% = USD 32 million, ROR = 14.5%).\u0000 In the optimistic case, the NPVs at 10% are improved, ranging from Thailand (+271%), Myanmar (+247%), Malaysia (+151%), and Indonesia and Vietnam (+141%) as compared to the base case. In the pessimistic case, all the fiscal terms are unfeasible for ROR at 10%. Myanmar PSC (1993) yields above 10% ROR only when the production is at the base or high scenario with oil price at USD 70/bbl. Vietnam PSC (2013) is unfeasible for positive NPV at 10% even with high oil price under various taxes, including the windfall profit tax. Indonesia has a better NPV at 10% at a low oil price because of the progressive split that subsidizes the operator. Oil price and production volume are the top two sensitive variables except for Vietnam, where capital is the highest. The contractor take is higher in Malaysia, followed by Indonesia, Thailand, Myanmar, and Vietnam at base and high oil price. When the oil price is low, Indonesia generated a higher contractor take than Malaysia. Malaysia EPT is the only fiscal regime that can generate a contractor take that is higher than government take and stagnant around 55% against the 40% in Indonesia. In conclusion, Malaysia EPT provides a better investment return when the oil price is USD 60/bbl and above, while Indonesia gross split is more profitable when the oil price is low.\u0000 This study provides insights on the potential investment returns ","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78515767","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 static Young's Modulus (Estatic) is an important parameter affecting the design of different aspects related to oil and gas producing wells. It is significantly changing based on the type of the formation, and hence, an accurate method of identifying Estatic is required. This study evaluates the performance of support vector regression (SVR) for prediction of the Estatic. The SVR model was learned to evaluate the Estatic from the well logs of the bulk formation density in addition to compressional and shear transit time. It was learned and tested on 592 training datasets of the inputs and their corresponding Estatic, these datasets were obtained from a sandstone formation in Well-A. The learned SVR model was then validated on 38 data points from Well-B, the performance of the optimized SVR on predicting the Estatic for the validation data was also compared with these of the early optimized artificial neural networks (ANN) and functional neural networks (FNN). As a result, all machine learning models showed high precision in predicting the Estatic for the validation data where Estatic was estimated with average absolute percentage errors of 3.80%, 2.54, and 2.03% and correlation coefficients of 0.991, 0.997, and 0.999 using the optimized ANN, FNN, and SVR models, respectively. This result shows the high accuracy of the SVR on predicting the Estatic.
{"title":"Estimation of the Static Young's Modulus for Sandstone Reservoirs Using Support Vector Regression","authors":"A. Mahmoud, S. Elkatatny, D. A. Al Shehri","doi":"10.2523/iptc-22071-ms","DOIUrl":"https://doi.org/10.2523/iptc-22071-ms","url":null,"abstract":"\u0000 The static Young's Modulus (Estatic) is an important parameter affecting the design of different aspects related to oil and gas producing wells. It is significantly changing based on the type of the formation, and hence, an accurate method of identifying Estatic is required. This study evaluates the performance of support vector regression (SVR) for prediction of the Estatic. The SVR model was learned to evaluate the Estatic from the well logs of the bulk formation density in addition to compressional and shear transit time. It was learned and tested on 592 training datasets of the inputs and their corresponding Estatic, these datasets were obtained from a sandstone formation in Well-A. The learned SVR model was then validated on 38 data points from Well-B, the performance of the optimized SVR on predicting the Estatic for the validation data was also compared with these of the early optimized artificial neural networks (ANN) and functional neural networks (FNN). As a result, all machine learning models showed high precision in predicting the Estatic for the validation data where Estatic was estimated with average absolute percentage errors of 3.80%, 2.54, and 2.03% and correlation coefficients of 0.991, 0.997, and 0.999 using the optimized ANN, FNN, and SVR models, respectively. This result shows the high accuracy of the SVR on predicting the Estatic.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76950180","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}
Maryvi Martinez Santiago, Shamma Al Shehhi, Sukilesh Anbalagan, A. Shbair, F. Noordin, Dicky Trisnadi, Mustapha Adli, Krisna Surya
ADNOC has development and implemented a robust automated sector performance review (SPR) process using state-of-the-art analytics and business process management tool (Khan et al., 2019). In this paper, we will present the achieved results and the defined opportunities by implementing SPR across some targeted reservoirs during the previous last 2 years. With the necessity of having analysis at sector level, the main objective of this work is to conduct an integrated reservoir dynamic synthesis, identify all challenges and opportunities to come up with robust and practical action plan aiming for best reservoir management and ultimately obtain best oil recovery by sector. Applying Integrated Reservoir Management (IRM) Workflow on Giant Onshore Field, It was decided to start the project on one major Reservoir A (divided by 3 sectors) as a project pilot. First data were collected from operations database, data management in spreadsheets, simulation output format, maps and images. All data were organized into the automated SPR workflow through a web based Business Process Management (BPM) that provided mechanism for the user to load, validate and approve technical data. Setting the workflow to focusing on analyzing the reservoir performance at sector level, the data is illustrated in an integrated visualization environment including panels for the reservoir KPI, production plan compliance status and reservoir pressure maintenance, diagnostic plots, production and injection summary, etc., opening the possibility for the user to identify new opportunities and areas that needs further investigations. Few key enhancements are listed and were suggested to the solution as a next phase. Following a methodical SPR automated workflow these conclusion are drawn: Technical data can be approved with appropriate notification for task execution. Data processing cycles, visualization and performance analysis dashboard time frame was reduced. It was identify the underperforming areas into the sectors. The Opportunity Management proactive system was used to identify reservoir profitable opportunities through a centralized platform. Action plans include well and surface intervention. 20% of the activities were successfully implemented and provided significant added values. Implementation of the automated SPR workflows as part of Digital technologies is renovating the traditional work process into very effective and advanced analytics and has achieved excellence in reservoir management and reserves recovery.
{"title":"Achieving Reservoir Performance Excellence By Implementing Automated Sector Performance: Onshore Field Case Study","authors":"Maryvi Martinez Santiago, Shamma Al Shehhi, Sukilesh Anbalagan, A. Shbair, F. Noordin, Dicky Trisnadi, Mustapha Adli, Krisna Surya","doi":"10.2523/iptc-21990-ea","DOIUrl":"https://doi.org/10.2523/iptc-21990-ea","url":null,"abstract":"\u0000 ADNOC has development and implemented a robust automated sector performance review (SPR) process using state-of-the-art analytics and business process management tool (Khan et al., 2019). In this paper, we will present the achieved results and the defined opportunities by implementing SPR across some targeted reservoirs during the previous last 2 years.\u0000 With the necessity of having analysis at sector level, the main objective of this work is to conduct an integrated reservoir dynamic synthesis, identify all challenges and opportunities to come up with robust and practical action plan aiming for best reservoir management and ultimately obtain best oil recovery by sector.\u0000 Applying Integrated Reservoir Management (IRM) Workflow on Giant Onshore Field, It was decided to start the project on one major Reservoir A (divided by 3 sectors) as a project pilot.\u0000 First data were collected from operations database, data management in spreadsheets, simulation output format, maps and images. All data were organized into the automated SPR workflow through a web based Business Process Management (BPM) that provided mechanism for the user to load, validate and approve technical data.\u0000 Setting the workflow to focusing on analyzing the reservoir performance at sector level, the data is illustrated in an integrated visualization environment including panels for the reservoir KPI, production plan compliance status and reservoir pressure maintenance, diagnostic plots, production and injection summary, etc., opening the possibility for the user to identify new opportunities and areas that needs further investigations.\u0000 Few key enhancements are listed and were suggested to the solution as a next phase.\u0000 Following a methodical SPR automated workflow these conclusion are drawn:\u0000 Technical data can be approved with appropriate notification for task execution. Data processing cycles, visualization and performance analysis dashboard time frame was reduced. It was identify the underperforming areas into the sectors. The Opportunity Management proactive system was used to identify reservoir profitable opportunities through a centralized platform. Action plans include well and surface intervention. 20% of the activities were successfully implemented and provided significant added values.\u0000 Implementation of the automated SPR workflows as part of Digital technologies is renovating the traditional work process into very effective and advanced analytics and has achieved excellence in reservoir management and reserves recovery.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"28 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77901304","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}
Designing an onshore pilot well to be drilled and functioning as water disposal well targeting one of three potential formations to test and evaluate their injectivity. Based on evaluation results, an alternative new and deeper formation will be selected to dispose the unwanted associated produced water, instead of the current shallow formation that is considered as a natural aquifer by authorities. The well is designed to reach the first target in a deviated angle after which evaluation of the barefoot injectivity testing will begin. The decision whether to continue drilling to a secondary target or complete the well depends heavily on the injectivity testing results. The deviated angle of drilling will be dropped to reach a vertical position for the secondary target upon which the last liner will be run and perforated, then the formation testing will be conducted. In case of encounterg failure in the second injectivity testing, drilling to the deepest target will continue and final barefoot testing will be performed. A final optimal design for the pilot disposal well is intended to meet the reservoir and geological team with minimal drilling risks. The distance between this well and the other deep offset wells was the main challenge where the planned total depth was never reached in the disposal location. Also, the design was tailored to accommodate the drilling sections with the separation and long intervals between the targets. Furthermore, the uncertainty of the deepest formation fluid in addition to the uncertainties of formations pressure and formations fracture pressure were a big dispute while preparing the drilling fluids programs particularly across the target in which a water based mud was used as drilling fluid not to damage the formations nor to jeopardize the results of the injectivity tests. The pilot disposal well is drilled successfully penetrating two targets without the need to drill to the third formation. Hence, the new formation that will be used to dispose of the produced but unwanted water is defined after the reservoir team have evaluated the two injectivity tests. The results of the injectivity evaluation also provided the required number of wells that can handle all the expected produced water, and provided the required upgrade for the surface facilities to accommodate the injection pressure. This unique challenging well design, combining slanted and vertical trajectories, can be utilized whenever the budget is limited to one well, while you have multiple different targets to explore. Moreover, a specialized environmental impact study, conducted by independent contractor, confirms that there was no harm from the injected water to the groundwater.
{"title":"Case Study: Single Well Design Targeting Three Water Bearing Formations","authors":"Hamad Al-Qattan, Emad Al-Jassam, Magdy Mansour, Mahmoud Morcey","doi":"10.2523/iptc-21971-ms","DOIUrl":"https://doi.org/10.2523/iptc-21971-ms","url":null,"abstract":"\u0000 Designing an onshore pilot well to be drilled and functioning as water disposal well targeting one of three potential formations to test and evaluate their injectivity. Based on evaluation results, an alternative new and deeper formation will be selected to dispose the unwanted associated produced water, instead of the current shallow formation that is considered as a natural aquifer by authorities.\u0000 The well is designed to reach the first target in a deviated angle after which evaluation of the barefoot injectivity testing will begin. The decision whether to continue drilling to a secondary target or complete the well depends heavily on the injectivity testing results.\u0000 The deviated angle of drilling will be dropped to reach a vertical position for the secondary target upon which the last liner will be run and perforated, then the formation testing will be conducted. In case of encounterg failure in the second injectivity testing, drilling to the deepest target will continue and final barefoot testing will be performed.\u0000 A final optimal design for the pilot disposal well is intended to meet the reservoir and geological team with minimal drilling risks. The distance between this well and the other deep offset wells was the main challenge where the planned total depth was never reached in the disposal location. Also, the design was tailored to accommodate the drilling sections with the separation and long intervals between the targets. Furthermore, the uncertainty of the deepest formation fluid in addition to the uncertainties of formations pressure and formations fracture pressure were a big dispute while preparing the drilling fluids programs particularly across the target in which a water based mud was used as drilling fluid not to damage the formations nor to jeopardize the results of the injectivity tests.\u0000 The pilot disposal well is drilled successfully penetrating two targets without the need to drill to the third formation. Hence, the new formation that will be used to dispose of the produced but unwanted water is defined after the reservoir team have evaluated the two injectivity tests. The results of the injectivity evaluation also provided the required number of wells that can handle all the expected produced water, and provided the required upgrade for the surface facilities to accommodate the injection pressure.\u0000 This unique challenging well design, combining slanted and vertical trajectories, can be utilized whenever the budget is limited to one well, while you have multiple different targets to explore.\u0000 Moreover, a specialized environmental impact study, conducted by independent contractor, confirms that there was no harm from the injected water to the groundwater.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84459232","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}
ERD wells are widely used by operators in the MENA region to maximize reservoir contact, lower cost per barrel accessed, and to be able to access far away drill targets from fewer drill centers (wellhead platforms, islands, drill pads). ERD wells and associated required technological well construction approaches by nature are typically non-standard. ERD well construction require very exact and detailed engineering analysis and methodologies to be applied in order to develop suitable and accurate drilling designs that closely matches to the actual conditions. During drilling of ERD wells, a ME operator observed that the static geothermal gradient and subsequent modelling of dynamic flow temperature did not match actual downhole temperatures, hence modifications were required to the temperature profile to match the simulation of OBM drilling fluid ECD (Equivalent Circulating Density) to actual ECD measurements from the ECD pressure sub in the BHA. This temperature effect arises from the several factors, mainly in the sub-surface environment. The resulting mud temperature is significantly higher than static temperature and this has a high impact on mud rheology, resulting pressure losses and hole cleaning. Failure to model correctly can result in mud losses or loss of horizontal section because the ECD gets above formation fracture gradient, to low flowrates for effective hole cleaning due to excessive standpipe pressures, and other problems. This paper presents how hydraulics were modelled to match actual data (rheology, ECD, SPP, BHA, Flowrate, ROP, RPM etc) in one of the longest ERD wells ever drilled. In response to the challenges faced by a ME operator to improve the quality of hydraulic modelling and drilling design, a global Oil and Gas service company and a ME operator jointly explored the approaches for simulating Effective Temperature Profile on the giant offshore oil field, calibrated and verified it along hole with application for providing accurate estimation of hydraulic parameters. The workflow starts from analysis of actual temperature readings in upper sections of the well then uses it for simulating of Effective Temperature Profile in the reservoir section. Then simulated Effective Temperature Profile is imported to the simulation tool for proper drilling design.
{"title":"Influence of Temperature Profile Modelling on the Accuracy of Hydraulic Parameters Estimation Effect of Temperature Profile Change Due to Continuous Drillstring Rotation","authors":"A. Zherelyev, J. B. Molster","doi":"10.2523/iptc-22030-ea","DOIUrl":"https://doi.org/10.2523/iptc-22030-ea","url":null,"abstract":"\u0000 ERD wells are widely used by operators in the MENA region to maximize reservoir contact, lower cost per barrel accessed, and to be able to access far away drill targets from fewer drill centers (wellhead platforms, islands, drill pads). ERD wells and associated required technological well construction approaches by nature are typically non-standard. ERD well construction require very exact and detailed engineering analysis and methodologies to be applied in order to develop suitable and accurate drilling designs that closely matches to the actual conditions. During drilling of ERD wells, a ME operator observed that the static geothermal gradient and subsequent modelling of dynamic flow temperature did not match actual downhole temperatures, hence modifications were required to the temperature profile to match the simulation of OBM drilling fluid ECD (Equivalent Circulating Density) to actual ECD measurements from the ECD pressure sub in the BHA. This temperature effect arises from the several factors, mainly in the sub-surface environment. The resulting mud temperature is significantly higher than static temperature and this has a high impact on mud rheology, resulting pressure losses and hole cleaning. Failure to model correctly can result in mud losses or loss of horizontal section because the ECD gets above formation fracture gradient, to low flowrates for effective hole cleaning due to excessive standpipe pressures, and other problems. This paper presents how hydraulics were modelled to match actual data (rheology, ECD, SPP, BHA, Flowrate, ROP, RPM etc) in one of the longest ERD wells ever drilled.\u0000 In response to the challenges faced by a ME operator to improve the quality of hydraulic modelling and drilling design, a global Oil and Gas service company and a ME operator jointly explored the approaches for simulating Effective Temperature Profile on the giant offshore oil field, calibrated and verified it along hole with application for providing accurate estimation of hydraulic parameters. The workflow starts from analysis of actual temperature readings in upper sections of the well then uses it for simulating of Effective Temperature Profile in the reservoir section. Then simulated Effective Temperature Profile is imported to the simulation tool for proper drilling design.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90309301","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 study area is situated within the eastern portion of the Nile Delta. As the Mediterranean Sea "dried up" during the Messinian extensive erosion process resulted in the formation of large canyons and valleys which cut into the underlying Qawasim and Sidi Salim Formations, but the number of such incised valleys may have been limited. The entrenched valleys became filled predominantly with sandstone as sea levels frequently rose and dropped in the late Miocene to early Pliocene. The marine influence on deposition during the late Messinian became strong toward the end of the Miocene when thick marine shale separated the sand bodies. Late Messinian reservoir within the study area exhibits a good quality reservoir for gas and condensate accumulation. The target reservoir section consists of structural and stratigraphic elements that control the gas presence and the GWC. Late Messinian reservoir has a lot of heterogeneity and ambiguity for the attributes and amplitude interpretation, so the DHI within the study area has pitfalls and uncertainty to determine the hydrocarbon prospects, which caused the drilling of several dry wells. For lithology and pore fluid prediction, several hypotheses and approaches had been proposed. Amplitude versus offset (AVO) modeling and analysis for the wells log and seismic angle gathers data results in non-unique output, whereas several AVO classes were found for the gas sand within the study area. The AVO analysis for gas sand of the late Messinian reservoir could be Class II and Class IIp, while the wet sand is Class I. Following the first discovery within the study area, Extended Elastic Impedance (EEI) inversion was carried out for the Late Messinian reservoir for better identification and delineation of the reservoir boundaries and to determine the pore fluid content. During this study, several iterations have been made to determine the most appropriate chi angles to illuminate the presence of both reservoir and borehole content. The EEI inversion results show a strong correlation between a certain chi angle and the presence of gas. Maps for the late Messinian reservoir have been produced to illuminate the gas sand presence, which matches the results of the drilled wells. The technique has been so successful, as there are unexplored EEI anomalies that have a gas signature within the fault downthrown area. These EEI anomalies had been tested with encouraging results of a gas-bearing sand reservoir, as the EEI anomaly had been predicted correctly. This paper discusses the methodology involved, the calibration, and the selection of the appropriate chi angles for the Late Messinian Reservoir within the study area.
{"title":"Extended Elastic Impedance and its Application in Prediction of Reservoir and Fluid Properties for Late Messinian Reservoir, Onshore Nile Delta Egypt","authors":"Mahmoud Eloribi, Hytham Raslan","doi":"10.2523/iptc-21923-ms","DOIUrl":"https://doi.org/10.2523/iptc-21923-ms","url":null,"abstract":"\u0000 The study area is situated within the eastern portion of the Nile Delta. As the Mediterranean Sea \"dried up\" during the Messinian extensive erosion process resulted in the formation of large canyons and valleys which cut into the underlying Qawasim and Sidi Salim Formations, but the number of such incised valleys may have been limited. The entrenched valleys became filled predominantly with sandstone as sea levels frequently rose and dropped in the late Miocene to early Pliocene. The marine influence on deposition during the late Messinian became strong toward the end of the Miocene when thick marine shale separated the sand bodies.\u0000 Late Messinian reservoir within the study area exhibits a good quality reservoir for gas and condensate accumulation. The target reservoir section consists of structural and stratigraphic elements that control the gas presence and the GWC.\u0000 Late Messinian reservoir has a lot of heterogeneity and ambiguity for the attributes and amplitude interpretation, so the DHI within the study area has pitfalls and uncertainty to determine the hydrocarbon prospects, which caused the drilling of several dry wells. For lithology and pore fluid prediction, several hypotheses and approaches had been proposed. Amplitude versus offset (AVO) modeling and analysis for the wells log and seismic angle gathers data results in non-unique output, whereas several AVO classes were found for the gas sand within the study area. The AVO analysis for gas sand of the late Messinian reservoir could be Class II and Class IIp, while the wet sand is Class I.\u0000 Following the first discovery within the study area, Extended Elastic Impedance (EEI) inversion was carried out for the Late Messinian reservoir for better identification and delineation of the reservoir boundaries and to determine the pore fluid content. During this study, several iterations have been made to determine the most appropriate chi angles to illuminate the presence of both reservoir and borehole content.\u0000 The EEI inversion results show a strong correlation between a certain chi angle and the presence of gas. Maps for the late Messinian reservoir have been produced to illuminate the gas sand presence, which matches the results of the drilled wells. The technique has been so successful, as there are unexplored EEI anomalies that have a gas signature within the fault downthrown area. These EEI anomalies had been tested with encouraging results of a gas-bearing sand reservoir, as the EEI anomaly had been predicted correctly.\u0000 This paper discusses the methodology involved, the calibration, and the selection of the appropriate chi angles for the Late Messinian Reservoir within the study area.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"64 5 Pt 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90418431","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}
S. Kalam, S. Abu-Khamsin, Mohammad Rasheed Khan, Asiya Abbasi, Abdul Asad, Rizwan Ahmed Khan
Artificial intelligence is a smart tool widely used in Petroleum engineering. Adaptive Neuro-Fuzzy Inference System (ANFIS) is an artificial intelligence technique that is a hybrid between Artificial Neural Networks (ANN) and fuzzy logic. In this paper, both ANN and ANFIS were applied to propose a new methodology based on intelligent algorithms to predict adsorption of methane gas in shale. Feed-Forward Neural Network and subtractive clustering were applied to correlate adsorption with several parameters. These include temperature, pressure, moisture content, and total organic content (TOC). A real data set collected from the literature, which includes about 350 data points, was used in the development of a new empirical correlation. The set was divided into a 70:30 ratio for training and testing, respectively. The average absolute percentage error, correlation coefficient, and mean squared error were considered in the error metrics to obtain the best possible model. The results show that methane adsorption can be efficiently correlated with the inputs using both machine learning tools. Using ANN, the correlation coefficient for both testing and training data was more than 99%. A detailed sensitivity analysis for the ANN model is also provided in this paper.
{"title":"Data Driven Intelligent Modeling to Estimate Adsorption of Methane Gas in Shales","authors":"S. Kalam, S. Abu-Khamsin, Mohammad Rasheed Khan, Asiya Abbasi, Abdul Asad, Rizwan Ahmed Khan","doi":"10.2523/iptc-22101-ms","DOIUrl":"https://doi.org/10.2523/iptc-22101-ms","url":null,"abstract":"\u0000 Artificial intelligence is a smart tool widely used in Petroleum engineering. Adaptive Neuro-Fuzzy Inference System (ANFIS) is an artificial intelligence technique that is a hybrid between Artificial Neural Networks (ANN) and fuzzy logic. In this paper, both ANN and ANFIS were applied to propose a new methodology based on intelligent algorithms to predict adsorption of methane gas in shale. Feed-Forward Neural Network and subtractive clustering were applied to correlate adsorption with several parameters. These include temperature, pressure, moisture content, and total organic content (TOC).\u0000 A real data set collected from the literature, which includes about 350 data points, was used in the development of a new empirical correlation. The set was divided into a 70:30 ratio for training and testing, respectively. The average absolute percentage error, correlation coefficient, and mean squared error were considered in the error metrics to obtain the best possible model.\u0000 The results show that methane adsorption can be efficiently correlated with the inputs using both machine learning tools. Using ANN, the correlation coefficient for both testing and training data was more than 99%. A detailed sensitivity analysis for the ANN model is also provided in this paper.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78393361","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}
Y. Samarkin, M. Aljawad, A. Amao, T. Sølling, K. Al-Ramadan, S. Abu-Khamsin, S. Patil, M. AlTammar, K. Alruwaili
Hydraulic fracturing operations involve generating conductive pathways in low permeability formations to maximize hydrocarbons production. One of the main challenges is maintaining fracture conductivity under high closure stresses, especially in soft formations. However, long–term fracture conductivity can be sustained through fracture surface hardness improvement. This research targets the strengthening of carbonate rocks via the transformation of calcite into the harder hydroxyapatite mineral. In this study, limestone, chalk, and dolomite rock specimens were treated with 1M solution of diammonium phosphate (DAP) for 3 days at room temperature conditions. Rock samples’ hardness was measured by indentation (Brinell hardness) technique before/after the treatment to assess the strengthening effect of DAP. The changes in the mineralogy in treated samples were studied by SEM-EDS technique. The formation of phosphate minerals was achieved in treated samples, and they were clearly seen in the SEM images. The results have shown that both limestone and chalk samples reacted strongly with DAP solution, which was expressed in terms of rich abundance in newly formed minerals inside rock specimens. The reaction between dolomite and DAP solution was observed to be weak which resulted in generation of isolated phosphate minerals. The formed minerals were identified as hydroxyapatite (5 hardness in the Mohs scale) after comparing their morphology with other phosphate minerals reported in the literature. Treatment of the rocks by DAP solution resulted in improvement of their strength. The Brinell hardness of the chalk specimen was increased by 30% after the treatment, whereas in the case of the limestone sample, a 13% increment in hardness was achieved. The proposed carbonate rock strengthening technique can be applied in hydraulic fracturing It is intended to solve common soft formations problems (e.g., asperities failure, proppant embedment) causing acid/propped fractures’ conductivity reduction.
{"title":"Hydraulic Fracture Conductivity Sustenance in Carbonate Formations Through Rock Strengthening by DAP Solution","authors":"Y. Samarkin, M. Aljawad, A. Amao, T. Sølling, K. Al-Ramadan, S. Abu-Khamsin, S. Patil, M. AlTammar, K. Alruwaili","doi":"10.2523/iptc-22496-ms","DOIUrl":"https://doi.org/10.2523/iptc-22496-ms","url":null,"abstract":"\u0000 Hydraulic fracturing operations involve generating conductive pathways in low permeability formations to maximize hydrocarbons production. One of the main challenges is maintaining fracture conductivity under high closure stresses, especially in soft formations. However, long–term fracture conductivity can be sustained through fracture surface hardness improvement. This research targets the strengthening of carbonate rocks via the transformation of calcite into the harder hydroxyapatite mineral.\u0000 In this study, limestone, chalk, and dolomite rock specimens were treated with 1M solution of diammonium phosphate (DAP) for 3 days at room temperature conditions. Rock samples’ hardness was measured by indentation (Brinell hardness) technique before/after the treatment to assess the strengthening effect of DAP. The changes in the mineralogy in treated samples were studied by SEM-EDS technique.\u0000 The formation of phosphate minerals was achieved in treated samples, and they were clearly seen in the SEM images. The results have shown that both limestone and chalk samples reacted strongly with DAP solution, which was expressed in terms of rich abundance in newly formed minerals inside rock specimens. The reaction between dolomite and DAP solution was observed to be weak which resulted in generation of isolated phosphate minerals. The formed minerals were identified as hydroxyapatite (5 hardness in the Mohs scale) after comparing their morphology with other phosphate minerals reported in the literature. Treatment of the rocks by DAP solution resulted in improvement of their strength. The Brinell hardness of the chalk specimen was increased by 30% after the treatment, whereas in the case of the limestone sample, a 13% increment in hardness was achieved.\u0000 The proposed carbonate rock strengthening technique can be applied in hydraulic fracturing It is intended to solve common soft formations problems (e.g., asperities failure, proppant embedment) causing acid/propped fractures’ conductivity reduction.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85530532","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}
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