P. Wilson, D. Povey, R. Davies, Pattarapong Prasongtham, Siriporn Shibano, T. Ampaiwan, I. N. Nuada, Farid Saifuddin
We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.
{"title":"3D Fault Seal Analysis of the Jasmine Field, Gulf of Thailand: Capillary Pressure Estimation and Calibration Using Fluid Contact Data","authors":"P. Wilson, D. Povey, R. Davies, Pattarapong Prasongtham, Siriporn Shibano, T. Ampaiwan, I. N. Nuada, Farid Saifuddin","doi":"10.2523/iptc-22831-ms","DOIUrl":"https://doi.org/10.2523/iptc-22831-ms","url":null,"abstract":"\u0000 We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127929262","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}
Saba El Sharif, Mustafa Talaq, S. Less, Sébastien Duval
The objective of this paper is to introduce a capacitance-based fixture to assess and monitor crude oil and water emulsion separation kinetics in Gas Oil Separation Plants (GOSPs). The technology provides an online phase separation assessment through dielectric response analysis. The principle of operation of this technology is based on measuring the changes in the capacitance of water/crude oil system versus time as the separation process develops. Free water, emulsion and dry crude oil have different electrical properties, and provide a unique signature to describe the physical composition of the system they form. The evolution of electrical properties of crude oil emulsions at different temperatures, and with or without the addition of chemical demulsifiers is reported. The monitoring tool consists of a cylindrical fixture where the emulsion electrical properties are monitored during the phase separation. The fixture is connected to an Inductance Capacitance Resistance meter (LCR) to measure the change in electrical impedance of the emulsion. The fixture has a cylindrical geometry and its design was adapted to discretize the phase distribution of complex fluid mixtures. The fixture electrical properties were estimated based on its shape and material of construction, and verified by measuring the electrical impedance of fluids of known dielectric properties. The technology was tested under different conditions of temperature and concentration of demulsifier and was able to measure accurately the sample water cut and to monitor water separation kinetics in real time. The results are driving the development of an online emulsion stability assessment tool to characterize emulsion separation kinetics at process conditions. In addition, this tool will improve the accuracy of emulsion separation measurements in crude oil processing facilities by avoiding emulsion alteration due to degassing, shearing and aging inherent to bottle test procedure.
{"title":"A Novel Capacitance-Based Emulsion Monitoring Technology","authors":"Saba El Sharif, Mustafa Talaq, S. Less, Sébastien Duval","doi":"10.2523/iptc-22916-ms","DOIUrl":"https://doi.org/10.2523/iptc-22916-ms","url":null,"abstract":"\u0000 The objective of this paper is to introduce a capacitance-based fixture to assess and monitor crude oil and water emulsion separation kinetics in Gas Oil Separation Plants (GOSPs). The technology provides an online phase separation assessment through dielectric response analysis.\u0000 The principle of operation of this technology is based on measuring the changes in the capacitance of water/crude oil system versus time as the separation process develops. Free water, emulsion and dry crude oil have different electrical properties, and provide a unique signature to describe the physical composition of the system they form. The evolution of electrical properties of crude oil emulsions at different temperatures, and with or without the addition of chemical demulsifiers is reported.\u0000 The monitoring tool consists of a cylindrical fixture where the emulsion electrical properties are monitored during the phase separation. The fixture is connected to an Inductance Capacitance Resistance meter (LCR) to measure the change in electrical impedance of the emulsion. The fixture has a cylindrical geometry and its design was adapted to discretize the phase distribution of complex fluid mixtures. The fixture electrical properties were estimated based on its shape and material of construction, and verified by measuring the electrical impedance of fluids of known dielectric properties. The technology was tested under different conditions of temperature and concentration of demulsifier and was able to measure accurately the sample water cut and to monitor water separation kinetics in real time.\u0000 The results are driving the development of an online emulsion stability assessment tool to characterize emulsion separation kinetics at process conditions. In addition, this tool will improve the accuracy of emulsion separation measurements in crude oil processing facilities by avoiding emulsion alteration due to degassing, shearing and aging inherent to bottle test procedure.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129571173","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. Ketmalee, Thanachai Singhapetcharat, M. Pancharoen, Pacharaporn Navasumrit, Kittiphop Chayraksa, Naruttee Kovitkanit
Field A is an onshore oil field in Thailand. This area contains biodegraded medium-heavy crude reservoir; 19°API oil gravity and 144 cp viscosity. Therefore, the field suffers from a low recovery factor due to high crude viscosity. On one hand, bacteria have exerted an adverse effect on production, on the other hand, it means that the condition of the reservoir is suitable for implementing Microbial Enhanced Oil Recovery (MEOR). The MEOR is a technology that utilizes microorganisms (mainly bacteria), to enhance oil production, especially for medium-heavy oil. By feeding nutrients to bacteria, several metabolites were produced that would be useful for oil recovery. This technique is well known for its low investment cost, hence, high return. The technical screening confirmed that the reservoir and fluid properties are suitable for MEOR. Consequently, sixteen core samples and three water samples were collected for indigenous bacteria analysis. Although the laboratory indicated there are countless bacterial strains in the reservoir, the nitrate-reducing biosurfactant-producing bacteria group was identified. This bacteria group belongs to the Bacillus genus which produced biosurfactant and reduced crude viscosity by long-chain hydrocarbon degradation. Therefore, the treatment design aimed to promote the growth of favorable bacteria and inhibit undesirable ones. Consequently, a combination of KNO3 and KH2PO4 solutions and a specialized injection scheme was tailored for this campaign. The pilot consisted of two candidates those were well W1 (76% water cut), and well W2 (100% water cut). The campaign was categorized into three phases, namely, 1.) baseline phase, 2.) injection and soaking phase, and 3.) production phase. Firstly, the baseline production trends of candidates were established. Secondly, KNO3 and KH2PO4 solutions were injected for one month then the wells were shut-in for another month. Lastly, the pilot wells were allowed to produce for six months to evaluate the results. The dead oil viscosity of well W1 was reduced from 144 cp to 72 cp which led to a 6.44 MSTB EUR gain or 1.3% RF improvement. On the other hand, the productivity of well W2, the well with 100% water cut, was not improved. This was expected due to insufficient in-situ oil saturation for a bacteria carbon source. Considering the operational aspect, there was no corrosion issue or artificial lift gas-lock problem during the pilot.
{"title":"Like Cures Like Microbial Enhanced Oil Recovery in Biodegraded Crude","authors":"T. Ketmalee, Thanachai Singhapetcharat, M. Pancharoen, Pacharaporn Navasumrit, Kittiphop Chayraksa, Naruttee Kovitkanit","doi":"10.2523/iptc-22733-ms","DOIUrl":"https://doi.org/10.2523/iptc-22733-ms","url":null,"abstract":"\u0000 Field A is an onshore oil field in Thailand. This area contains biodegraded medium-heavy crude reservoir; 19°API oil gravity and 144 cp viscosity. Therefore, the field suffers from a low recovery factor due to high crude viscosity.\u0000 On one hand, bacteria have exerted an adverse effect on production, on the other hand, it means that the condition of the reservoir is suitable for implementing Microbial Enhanced Oil Recovery (MEOR). The MEOR is a technology that utilizes microorganisms (mainly bacteria), to enhance oil production, especially for medium-heavy oil. By feeding nutrients to bacteria, several metabolites were produced that would be useful for oil recovery. This technique is well known for its low investment cost, hence, high return.\u0000 The technical screening confirmed that the reservoir and fluid properties are suitable for MEOR. Consequently, sixteen core samples and three water samples were collected for indigenous bacteria analysis. Although the laboratory indicated there are countless bacterial strains in the reservoir, the nitrate-reducing biosurfactant-producing bacteria group was identified. This bacteria group belongs to the Bacillus genus which produced biosurfactant and reduced crude viscosity by long-chain hydrocarbon degradation.\u0000 Therefore, the treatment design aimed to promote the growth of favorable bacteria and inhibit undesirable ones. Consequently, a combination of KNO3 and KH2PO4 solutions and a specialized injection scheme was tailored for this campaign.\u0000 The pilot consisted of two candidates those were well W1 (76% water cut), and well W2 (100% water cut). The campaign was categorized into three phases, namely, 1.) baseline phase, 2.) injection and soaking phase, and 3.) production phase. Firstly, the baseline production trends of candidates were established. Secondly, KNO3 and KH2PO4 solutions were injected for one month then the wells were shut-in for another month. Lastly, the pilot wells were allowed to produce for six months to evaluate the results.\u0000 The dead oil viscosity of well W1 was reduced from 144 cp to 72 cp which led to a 6.44 MSTB EUR gain or 1.3% RF improvement. On the other hand, the productivity of well W2, the well with 100% water cut, was not improved. This was expected due to insufficient in-situ oil saturation for a bacteria carbon source. Considering the operational aspect, there was no corrosion issue or artificial lift gas-lock problem during the pilot.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124826095","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}
Ataur R. Malik, Mauricio A. Espinosa Galvis, A. Ghamdi, D. Ahmed
An intensive well integrity (WI) examination was carried out utilizing distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) tools through coiled tubing (CT) with real-time telemetry system in a horizontal gas well completed with open hole (OH) multi-stage fracturing (MSF) completion. During well completion, an unexpected leak in the lower completion led the OH packers not to effectively set. The WI examination was needed to locate the leak and effectively salvage the well. With DAS and DTS systems connected to the optical-fiber cable through the CT pressure bulk head at surface, CT conveying a bottom hole assembly consisting of conventional noise logging tool, temperature and pressure sensors, gamma ray and casing collar locator was run in the wellbore to the toe depth. The DAS and DTS data were recorded under shut-in, flowing and injection conditions keeping the CT stationed near to the toe depth. After recording DAS and DTS data in each shut-in, flowing and injection modes, noise logging was also performed by moving the CT across the entire horizontal section. The DAS optical interrogator unit connected, at surface, to optical-fiber cable deployed in the well successfully measured the Rayleigh backscattered light to provide a local measurement of the dynamic strain, which was converted into seismic wave fronts. The purpose of running noise logging tool was to validate acoustic wave fronts and interpretation obtained from the DAS and DTS. This comprehensive investigation involving DAS and DTS allowed to detect acoustic events simultaneously at multiple points along the entire wellbore through its capacity of providing the fluid movement visualization and detection: into or out of reservoir and evaluation of flow behind pipe and OH packers. DAS and DTS have also proved to be quick and operationally efficient techniques that can be done with minimum number of trips to surface and without complex bottom hole assembly. DAS system provided an opportunity for seismic data acquisition, where it significantly improved the efficiency of wellbore integrity diagnostic operations. A full well profile was recorded for each scenario in only minutes, rather than hours for a conventional tool survey. This paper elaborates facts on DAS data acquisition and how first time DAS data acquisition led to create a difference as comparison to the use of conventional CT.
{"title":"Completion Integrity Evaluation by Distributed Acoustic and Temperature Sensing Data Acquisition Through Coiled Tubing Real-Time Telemetry System","authors":"Ataur R. Malik, Mauricio A. Espinosa Galvis, A. Ghamdi, D. Ahmed","doi":"10.2523/iptc-22914-ms","DOIUrl":"https://doi.org/10.2523/iptc-22914-ms","url":null,"abstract":"\u0000 An intensive well integrity (WI) examination was carried out utilizing distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) tools through coiled tubing (CT) with real-time telemetry system in a horizontal gas well completed with open hole (OH) multi-stage fracturing (MSF) completion. During well completion, an unexpected leak in the lower completion led the OH packers not to effectively set. The WI examination was needed to locate the leak and effectively salvage the well.\u0000 With DAS and DTS systems connected to the optical-fiber cable through the CT pressure bulk head at surface, CT conveying a bottom hole assembly consisting of conventional noise logging tool, temperature and pressure sensors, gamma ray and casing collar locator was run in the wellbore to the toe depth. The DAS and DTS data were recorded under shut-in, flowing and injection conditions keeping the CT stationed near to the toe depth. After recording DAS and DTS data in each shut-in, flowing and injection modes, noise logging was also performed by moving the CT across the entire horizontal section.\u0000 The DAS optical interrogator unit connected, at surface, to optical-fiber cable deployed in the well successfully measured the Rayleigh backscattered light to provide a local measurement of the dynamic strain, which was converted into seismic wave fronts. The purpose of running noise logging tool was to validate acoustic wave fronts and interpretation obtained from the DAS and DTS. This comprehensive investigation involving DAS and DTS allowed to detect acoustic events simultaneously at multiple points along the entire wellbore through its capacity of providing the fluid movement visualization and detection: into or out of reservoir and evaluation of flow behind pipe and OH packers. DAS and DTS have also proved to be quick and operationally efficient techniques that can be done with minimum number of trips to surface and without complex bottom hole assembly.\u0000 DAS system provided an opportunity for seismic data acquisition, where it significantly improved the efficiency of wellbore integrity diagnostic operations. A full well profile was recorded for each scenario in only minutes, rather than hours for a conventional tool survey. This paper elaborates facts on DAS data acquisition and how first time DAS data acquisition led to create a difference as comparison to the use of conventional CT.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121244119","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}
Slimline ESP technology advancement has been exceptionally fast in recent years. The development of high-speed and bottom intake slim ESP technology along with deep-set slim ESP packers has accelerated the deployment of slim equipment to overcome one of ESPs challenges, namely, the requirement of high production rate from wells that have smaller casing diameters. The journey to address this requirement started with the development of deep-set slim ESP packers and slimline ESP packer penetrators that were not available for small casing sizes. Likewise, in terms of the ESP system, the slimline technology had been developed only by a few ESP suppliers. In order to have a broader baseline, some additional suppliers were motivated to develop this technology based on current and future needs, as well as potential field implementations to test their product. This paper is focused on describing four main slimline technologies with the objective of stablishing their suitability, capabilities and limitations. From these 4 suppliers, there is a good selection in terms of rate capabilities depending on the application. Likewise, there are some differences in terms of wider field implementation record which depends on the technology development stage for each one of them. Additionally, two suppliers of deep-set slim ESP packers and slimline packer penetrators will be discussed. This paper describes four slimline technologies, detailing the challenges and solutions they offer in order to achieve the high desired production rates from wells with small casing diameter.
{"title":"Advancements in Slim Deep-Set ESP Packers and High Rate Slim ESP Technology","authors":"Ahmed Alghamdi, Leigber Rivera, Jaime Pena Leon","doi":"10.2523/iptc-22785-ea","DOIUrl":"https://doi.org/10.2523/iptc-22785-ea","url":null,"abstract":"\u0000 Slimline ESP technology advancement has been exceptionally fast in recent years. The development of high-speed and bottom intake slim ESP technology along with deep-set slim ESP packers has accelerated the deployment of slim equipment to overcome one of ESPs challenges, namely, the requirement of high production rate from wells that have smaller casing diameters.\u0000 The journey to address this requirement started with the development of deep-set slim ESP packers and slimline ESP packer penetrators that were not available for small casing sizes. Likewise, in terms of the ESP system, the slimline technology had been developed only by a few ESP suppliers. In order to have a broader baseline, some additional suppliers were motivated to develop this technology based on current and future needs, as well as potential field implementations to test their product.\u0000 This paper is focused on describing four main slimline technologies with the objective of stablishing their suitability, capabilities and limitations. From these 4 suppliers, there is a good selection in terms of rate capabilities depending on the application. Likewise, there are some differences in terms of wider field implementation record which depends on the technology development stage for each one of them. Additionally, two suppliers of deep-set slim ESP packers and slimline packer penetrators will be discussed.\u0000 This paper describes four slimline technologies, detailing the challenges and solutions they offer in order to achieve the high desired production rates from wells with small casing diameter.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124227367","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}
Grisel Jiménez Soto, A. H. Abdul Latiff, Wael Ben Habel, M. Poppelreiter
A crucial role that significantly affects carbonate field development for hydrocarbon and carbon sequestration (CCS) projects is reducing uncertainty in rock type prediction. The carbonate reservoirs in Central Luconia Province, Malaysia, are significant economic worldwide reservoirs and are currently considered excellent candidates for Carbon Storage containers. The nature of these carbonate rock properties is visible and notably distinguishable at the core scale. To characterize significant petrophysical and geological factors of the distribution of the rock properties in the E11 carbonate build-up, this work proposes a sequence of processes (workflow) for obtaining spatial information about the organization using Kohonen Self-organizing maps. This work highlights the significant geological and petrophysical constraints on the distribution of rock properties in the E11 field. Using self-organizing maps, the predicted rock types were propagated among wells with no core available. Using this workflow, multiscale data is categorized according to "patterns". The phases include Phase 1: Detailed core description, Phase 2: Microscope sections description, Phase 3: Well logs analysis, Phase 4: Well logs analysis, and Phase 4: Self-organizing maps using IPSOM module in Techlog software. Considering the stratigraphic organization, juxtaposition, and proportions, the anticipated rock type closely resembles the rock types identified by core description manually. The results allow a comprehensive understanding of flow behavior in carbonate tight and reservoir rock types.
{"title":"Integrated Multiscale Carbonate Rock Types Prediction Using Multiscale Data and Kohonen Self-Organising Maps in E11 Field, Central Luconia Province, Malaysia","authors":"Grisel Jiménez Soto, A. H. Abdul Latiff, Wael Ben Habel, M. Poppelreiter","doi":"10.2523/iptc-22886-ea","DOIUrl":"https://doi.org/10.2523/iptc-22886-ea","url":null,"abstract":"\u0000 A crucial role that significantly affects carbonate field development for hydrocarbon and carbon sequestration (CCS) projects is reducing uncertainty in rock type prediction. The carbonate reservoirs in Central Luconia Province, Malaysia, are significant economic worldwide reservoirs and are currently considered excellent candidates for Carbon Storage containers. The nature of these carbonate rock properties is visible and notably distinguishable at the core scale.\u0000 To characterize significant petrophysical and geological factors of the distribution of the rock properties in the E11 carbonate build-up, this work proposes a sequence of processes (workflow) for obtaining spatial information about the organization using Kohonen Self-organizing maps.\u0000 This work highlights the significant geological and petrophysical constraints on the distribution of rock properties in the E11 field. Using self-organizing maps, the predicted rock types were propagated among wells with no core available.\u0000 Using this workflow, multiscale data is categorized according to \"patterns\". The phases include Phase 1: Detailed core description, Phase 2: Microscope sections description, Phase 3: Well logs analysis, Phase 4: Well logs analysis, and Phase 4: Self-organizing maps using IPSOM module in Techlog software. Considering the stratigraphic organization, juxtaposition, and proportions, the anticipated rock type closely resembles the rock types identified by core description manually.\u0000 The results allow a comprehensive understanding of flow behavior in carbonate tight and reservoir rock types.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"119 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116886045","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}
Accurate knowledge of circulating pressure and temperature is essential for making critical decisions while drilling operation. Through implementation of miniaturized semiconductor technology, we obtained near real-time dynamic pressure and temperature profile of the wellbore, making previously simulated critical operational data such as equivalent circulation density (ECD) and wellbore thermal distribution now measurable using drilling microchip. The application of drilling microchips to collect distributed pressure and temperature data while drilling is investigated, where each microchip measures both pressure and temperature simultaneously. This study also presents a revised method to calibrate measurements of drilling microchip with depth. Four field trials were attempted in a slightly inclined well using water-based or oil-based muds, where 10 drilling microchips were deployed in each trial. The recovered data from the drilling microchips are first downloaded and compiled. An in-house software is developed to process and convert time-scale of each drilling microchip to depth considering slippage of drilling microchips in drill string and annulus. An iterative algorithm is designed to calibrate the predicted arrival time with the actual arrival time of each tracer, which ultimately yields the true velocity of tracers in flow conduits. The maximum measured pressure is used as an indicator to locate each tracer at the bottom hole. It is realized that a plateau of pressure versus time can signify a trapped tracer in the flow path if the pump rate was maintained constant. The results of field trials show that some of the tracers were trapped for few minutes in the lower section of annular space or before the bit nozzle. The results of temperature profiles conclude a unique pattern for almost all of the deployed drilling microchips. However, the results of pressure profiles can be classified in two different groups as drilling microchips could have moved in different batches while pumping. The calculated temperature gradients show a heating zone near the bottom hole and continuous cooling of drilling fluid as tracers move toward the surface. The average pressure gradient is in the range of 0.52 – 0.61 psi/ft among different trials. It is shown that the velocity of tracers in each interval strongly depends on the flow regime. To our best knowledge, a combined measurement of circulating temperature and pressure using drilling microchips for the first-time is successfully conducted in these field trials. The results can be used for calculation of ECD and temperature profiles, which provide near real-time downhole data for monitoring and diagnostic applications. The measured pressure data also provide new insights about tracking of drilling microchips in the wellbore.
{"title":"Analysis of Circulating Pressure and Temperature using Drilling Microchips","authors":"Bodong Li, G. Zhan, Mike Okot, V. Dokhani","doi":"10.2523/iptc-22805-ms","DOIUrl":"https://doi.org/10.2523/iptc-22805-ms","url":null,"abstract":"\u0000 Accurate knowledge of circulating pressure and temperature is essential for making critical decisions while drilling operation. Through implementation of miniaturized semiconductor technology, we obtained near real-time dynamic pressure and temperature profile of the wellbore, making previously simulated critical operational data such as equivalent circulation density (ECD) and wellbore thermal distribution now measurable using drilling microchip. The application of drilling microchips to collect distributed pressure and temperature data while drilling is investigated, where each microchip measures both pressure and temperature simultaneously. This study also presents a revised method to calibrate measurements of drilling microchip with depth.\u0000 Four field trials were attempted in a slightly inclined well using water-based or oil-based muds, where 10 drilling microchips were deployed in each trial. The recovered data from the drilling microchips are first downloaded and compiled. An in-house software is developed to process and convert time-scale of each drilling microchip to depth considering slippage of drilling microchips in drill string and annulus. An iterative algorithm is designed to calibrate the predicted arrival time with the actual arrival time of each tracer, which ultimately yields the true velocity of tracers in flow conduits. The maximum measured pressure is used as an indicator to locate each tracer at the bottom hole. It is realized that a plateau of pressure versus time can signify a trapped tracer in the flow path if the pump rate was maintained constant.\u0000 The results of field trials show that some of the tracers were trapped for few minutes in the lower section of annular space or before the bit nozzle. The results of temperature profiles conclude a unique pattern for almost all of the deployed drilling microchips. However, the results of pressure profiles can be classified in two different groups as drilling microchips could have moved in different batches while pumping. The calculated temperature gradients show a heating zone near the bottom hole and continuous cooling of drilling fluid as tracers move toward the surface. The average pressure gradient is in the range of 0.52 – 0.61 psi/ft among different trials. It is shown that the velocity of tracers in each interval strongly depends on the flow regime.\u0000 To our best knowledge, a combined measurement of circulating temperature and pressure using drilling microchips for the first-time is successfully conducted in these field trials. The results can be used for calculation of ECD and temperature profiles, which provide near real-time downhole data for monitoring and diagnostic applications. The measured pressure data also provide new insights about tracking of drilling microchips in the wellbore.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133038003","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}
This research describes the characterization of fractures in the Mesozoic sandstones Phra Wihan Formation exposed at the southern part of Uttaradit province, Northern Thailand. Fracture characterization of outcrop analog is important to determine potential of subsurface reservoir. The methodology using field study and petrography analysis to determine the relationship of fractures and other structures such as bedding plane and fold geometry. In addition, microstructure analysis can be analoged to the potential of reservoir. The Phra Wihan Formation composed of thick quartz arenite sandstone laminated with mudstones. The structural architectures in study area are remarked by two open fracture sets with orthogonal relationship dominated in the fold limb. The first Set I, subdivided into Set Ia and Set Ib, developed in WNW-ESE direction perpendicular to the fold axial plane and parallel to the major compression stress. The second Set II, subdivided into Set IIa and Set IIb, developed in NNE-SSW direction parallel to the fold axial plane. These fractures imply to be associated with folding stage related to WNW-ESE compression stress during India-Eurasia collision.
{"title":"Fracture Characterisation and Basement Reservoir Potential of Phra Wihan Formation in Southern Part of Uttaradit Province, Northern Thailand","authors":"Watcharapong Piewmoh, P. Kanjanapayont","doi":"10.2523/iptc-22845-ms","DOIUrl":"https://doi.org/10.2523/iptc-22845-ms","url":null,"abstract":"\u0000 This research describes the characterization of fractures in the Mesozoic sandstones Phra Wihan Formation exposed at the southern part of Uttaradit province, Northern Thailand. Fracture characterization of outcrop analog is important to determine potential of subsurface reservoir. The methodology using field study and petrography analysis to determine the relationship of fractures and other structures such as bedding plane and fold geometry. In addition, microstructure analysis can be analoged to the potential of reservoir. The Phra Wihan Formation composed of thick quartz arenite sandstone laminated with mudstones. The structural architectures in study area are remarked by two open fracture sets with orthogonal relationship dominated in the fold limb. The first Set I, subdivided into Set Ia and Set Ib, developed in WNW-ESE direction perpendicular to the fold axial plane and parallel to the major compression stress. The second Set II, subdivided into Set IIa and Set IIb, developed in NNE-SSW direction parallel to the fold axial plane. These fractures imply to be associated with folding stage related to WNW-ESE compression stress during India-Eurasia collision.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134561472","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 objective of the study is to investigate feasible jacket and foundation design configurations, safe and reliable methodology and technics of transportation and installation of a new reusable wellhead platform jacket to serve phased development at the initial stage. The jacket is also designed to be able to retrieve, relocate and reuse at a new location for a future development. Development costs of utilizing of the newly built and reused wellhead platform jacket are determined. Various concepts of engineering design and construction and relocation-ability screening were conducted, and a most suitable concept was selected. Preliminary foundation and jacket sizing based on existing soil data, site conditions, water depth and project requirements with considerations of construction and relocation-ability of both newly used and to be reused stages was verified. Further detailed analysis to determine foundation and jacket sizes, overall structural integrity of the selected designs of both stages were further refined and confirmed. Further assessment of construction-ability and operation risks of both stages was conducted. Corresponding costs of both stages based on engineering designs and construction methodology were estimated. It is found that the selected reusable concept for wellhead platform jacket is technically feasible. The suction pile foundation is proven and of ease of installing and retrieving. Due to heavy structural weight corresponding to the design water depth, from transportation and installation approach, the newly built structure is designed in two parts 1) base frame with suction caissons foundation 2) top part jacket. Both parts will be connected by grouting method. When reuse, the entire structure will be retrieved, lifted above the seabed, wet towed and installed on to a new location in the field by a heavy lift vessel. It is recommended that the following activities to be carried out in the next engineering phase: Revisit all analysis when the actual soil data at the new determined location is available since it is the most critical input for engineering design and corresponding jacket weight that defines the heavy lift vessel requirement. Find opportunity of obtaining other alternative heavy lift vessels if they have reasonably competitive day rate or opportunity to combine the work with another project or campaign to optimize mobilization cost. Further analyses project schedule, competitiveness, possibility of multiple times of re-use the jacket and geo-politic risks into EPCI bidding campaign. This implementation would be considered as PTTEP's first reusable offshore platform jacket design concept for such the water depth. Retrievable suction caisson base frame foundation, connecting jacket by grouting method at the initial stage and retrieving, wet towing entire structure altogether and installing on to the new location at a future stage is technically feasible. It could reduce CAPEX and improve economic of mar
{"title":"Reusable Wellhead Platform Jacket Conceptual Study","authors":"Sarayut Uiyyasathian, Noppadol Anujareearpa","doi":"10.2523/iptc-22958-ea","DOIUrl":"https://doi.org/10.2523/iptc-22958-ea","url":null,"abstract":"\u0000 The objective of the study is to investigate feasible jacket and foundation design configurations, safe and reliable methodology and technics of transportation and installation of a new reusable wellhead platform jacket to serve phased development at the initial stage. The jacket is also designed to be able to retrieve, relocate and reuse at a new location for a future development. Development costs of utilizing of the newly built and reused wellhead platform jacket are determined.\u0000 Various concepts of engineering design and construction and relocation-ability screening were conducted, and a most suitable concept was selected. Preliminary foundation and jacket sizing based on existing soil data, site conditions, water depth and project requirements with considerations of construction and relocation-ability of both newly used and to be reused stages was verified.\u0000 Further detailed analysis to determine foundation and jacket sizes, overall structural integrity of the selected designs of both stages were further refined and confirmed. Further assessment of construction-ability and operation risks of both stages was conducted. Corresponding costs of both stages based on engineering designs and construction methodology were estimated.\u0000 It is found that the selected reusable concept for wellhead platform jacket is technically feasible. The suction pile foundation is proven and of ease of installing and retrieving. Due to heavy structural weight corresponding to the design water depth, from transportation and installation approach, the newly built structure is designed in two parts 1) base frame with suction caissons foundation 2) top part jacket. Both parts will be connected by grouting method.\u0000 When reuse, the entire structure will be retrieved, lifted above the seabed, wet towed and installed on to a new location in the field by a heavy lift vessel.\u0000 It is recommended that the following activities to be carried out in the next engineering phase:\u0000 Revisit all analysis when the actual soil data at the new determined location is available since it is the most critical input for engineering design and corresponding jacket weight that defines the heavy lift vessel requirement. Find opportunity of obtaining other alternative heavy lift vessels if they have reasonably competitive day rate or opportunity to combine the work with another project or campaign to optimize mobilization cost. Further analyses project schedule, competitiveness, possibility of multiple times of re-use the jacket and geo-politic risks into EPCI bidding campaign.\u0000 This implementation would be considered as PTTEP's first reusable offshore platform jacket design concept for such the water depth. Retrievable suction caisson base frame foundation, connecting jacket by grouting method at the initial stage and retrieving, wet towing entire structure altogether and installing on to the new location at a future stage is technically feasible. It could reduce CAPEX and improve economic of mar","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"275 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133267777","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}
Reservoir pressure and pore pressure coefficient are the key parameters for evaluating the preservation conditions of low permeability reservoirs and selecting different development processed and measures, as well as important input parameters for predicting ground stress. Due to the influence of unique geological characteristics such as ancient structure, current structure and rapid change of burial depth, the pore pressure in reservoir of the Upper Wuerhe Formation in the 53 east block of Junggar Basin has a large lateral change and is influenced by many factors. The conventional pore pressure prediction methods based on longitudinal wave velocity (such as Eaton method) have poor accuracy. Therefore, according to the geological characteristics of the reservoir in this area, based on the simultaneous inversion of P-wave and S-wave data before seismic stack, combined with the changes in formation lithology and the impact of denudation on pore pressure and pore pressure coefficient, this paper takes P-wave, S-wave, lithology, and denudation into account to predict pore pressure and pressure coefficient. The research results show that: ① the introduction of seismic inversion data improves the prediction accuracy and detail richness on the plane; ② the introduction of the lithology change factor improves the stability of the prediction of pressure coefficient in vertical direction; ③ for the area suffering from strong denudation, the introduction of denudation intensity help better predict the pressure coefficient of low pressure wells near the denudated area. The pressure data from more than 10 actual wells proves that the relative error of the prediction results of this method is less than 5%. It is concluded that the established prediction method has small error and high accuracy, and can be used to provide higher quality data support for the subsequent selection of good reservoirs, well location deployment, horizontal stress parameter prediction.
{"title":"The Accurate Pore Pressure Prediction with Coupled Geomechanical and Thermodynamics Model","authors":"Shuwu Yuan, Wei Zhou, Ting Li, Hui Wang, Xuehong Peng, Long Xiao, Xudong Luo, Z. Zhai, Haifan Ding, Chaobin Tian, Yantao Deng, Xingning Huang","doi":"10.2523/iptc-22807-ea","DOIUrl":"https://doi.org/10.2523/iptc-22807-ea","url":null,"abstract":"\u0000 Reservoir pressure and pore pressure coefficient are the key parameters for evaluating the preservation conditions of low permeability reservoirs and selecting different development processed and measures, as well as important input parameters for predicting ground stress. Due to the influence of unique geological characteristics such as ancient structure, current structure and rapid change of burial depth, the pore pressure in reservoir of the Upper Wuerhe Formation in the 53 east block of Junggar Basin has a large lateral change and is influenced by many factors. The conventional pore pressure prediction methods based on longitudinal wave velocity (such as Eaton method) have poor accuracy. Therefore, according to the geological characteristics of the reservoir in this area, based on the simultaneous inversion of P-wave and S-wave data before seismic stack, combined with the changes in formation lithology and the impact of denudation on pore pressure and pore pressure coefficient, this paper takes P-wave, S-wave, lithology, and denudation into account to predict pore pressure and pressure coefficient. The research results show that: ① the introduction of seismic inversion data improves the prediction accuracy and detail richness on the plane; ② the introduction of the lithology change factor improves the stability of the prediction of pressure coefficient in vertical direction; ③ for the area suffering from strong denudation, the introduction of denudation intensity help better predict the pressure coefficient of low pressure wells near the denudated area. The pressure data from more than 10 actual wells proves that the relative error of the prediction results of this method is less than 5%. It is concluded that the established prediction method has small error and high accuracy, and can be used to provide higher quality data support for the subsequent selection of good reservoirs, well location deployment, horizontal stress parameter prediction.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129051119","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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