CFRP is gaining interest in several industries such as aerospace, sports, and oil field. When this material is assembled, the adhesive is considered a preference over screws and fasteners as screws holes can lead to matrix delamination. Prior applying an adhesive, surface pre-treatment is done to enhance bonding. Due to the complexity of the composite material namely in complex geometry, one can consider finite element analysis as an optimum method to model the material behavior. Failure of crack growth under cyclic loading is typically modeled using the CZM. However, finding the constitutive behavior parameters is considered challenging. In this work, the maximum stress, which is difficult to calculate experimentally, is estimated using the virtual closure technique (VCCT) as it is considered less complicated and costy than the conventional methods. The VCCT is a finite element method that is employed to simulate monotonic crack growth. From this model, the maximum stress is recorded and used as the maximum traction stress in the cohesive zone model (CZM) to simulate fatigue crack growth. The bilinear traction separation law was employed to simulate the cohesive process zone. To calibrate the model results, an experiment is conducted on two samples those were treated by two different methods. One sample has a sandblasting surface pre-treatment and the other is pre-treated by peelply. Each pre-treatment enhances different material toughness and hence validity of the results if supported. Both samples were tested under both static and cyclic loadings. The maximum energy release rate and the crack length were selected as comparison parameters between the models results and the experimental observations. Overall, it was noticed that the results are considered having reasonable fit.
{"title":"Characterizing Cohesive Zone Parameters to Model Crack Growth in Composite Materials","authors":"H. Al-Dakheel, J. Albinmousa, Idris Temitope","doi":"10.2523/iptc-22236-ea","DOIUrl":"https://doi.org/10.2523/iptc-22236-ea","url":null,"abstract":"\u0000 CFRP is gaining interest in several industries such as aerospace, sports, and oil field. When this material is assembled, the adhesive is considered a preference over screws and fasteners as screws holes can lead to matrix delamination. Prior applying an adhesive, surface pre-treatment is done to enhance bonding. Due to the complexity of the composite material namely in complex geometry, one can consider finite element analysis as an optimum method to model the material behavior. Failure of crack growth under cyclic loading is typically modeled using the CZM. However, finding the constitutive behavior parameters is considered challenging. In this work, the maximum stress, which is difficult to calculate experimentally, is estimated using the virtual closure technique (VCCT) as it is considered less complicated and costy than the conventional methods. The VCCT is a finite element method that is employed to simulate monotonic crack growth. From this model, the maximum stress is recorded and used as the maximum traction stress in the cohesive zone model (CZM) to simulate fatigue crack growth. The bilinear traction separation law was employed to simulate the cohesive process zone. To calibrate the model results, an experiment is conducted on two samples those were treated by two different methods. One sample has a sandblasting surface pre-treatment and the other is pre-treated by peelply. Each pre-treatment enhances different material toughness and hence validity of the results if supported. Both samples were tested under both static and cyclic loadings. The maximum energy release rate and the crack length were selected as comparison parameters between the models results and the experimental observations. Overall, it was noticed that the results are considered having reasonable fit.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85379346","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}
Carbon dioxide (CO2) capture, utilization, and storage is the best option for mitigating atmospheric emissions of CO2 and thereby controlling the greenhouse gas concentrations in the atmosphere. Despite the benefits, there have been a limited number of projects solely for CO2 sequestration being implemented. The industry is well-versed in gas injection in reservoir formation for pressure maintenance and improving oil recovery. However, there are striking differences between the injection of CO2 into depleted hydrocarbon reservoirs and the engineered storage of CO2. The differences and challenges are compounded when the storage site is karstified carbonate in offshore and bulk storage volume. It is paramount to know upfront that CO2 can be stored at a potential storage site and demonstrate that the site can meet required storage performance safety criteria. Comprehensive screening for site selection has been carried out for suitable CO2 storage sites in offshore Sarawak, Malaysia using geographical, geological, geophysical, geomechanical and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generating performance scenarios of the site. In addition, the geochemical interaction of CO2 with reservoir rock has been studied to understand possible changes that may occur during/after injection and their impact on injection processes/mechanisms. Novel 3-way coupled modelling of dynamic-geochemistry-geomechanics processes were carried out to study long-term dynamic behaviour and fate of CO2 in the formation. The 3-way coupled modelling helped to understand the likely state of injectant in future and the storage mechanism, i.e., structural, solubility, residual, and mineralized trapping. It also provided realistic storage capacity estimation, incorporating reservoir compaction and porosity/permeability changes. The study indicates deficient localized plastic shear strain in overburden flank fault whilst all the other flaws remained stable. The potential threat of leakage is minimal as target injection pressure is set at initial reservoir pressure, which is much lower than caprock breaching pressure during injection. Furthermore, it was found that the geochemical reaction impact is shallow and localized at the top of the reservoir, making the storage safe in the long term. The integrity of existing wells was evaluated for potential leakage and planned for a proper mitigation plan. Comprehensive measurement, monitoring, and verification (MMV) were also designed using state-of-art tools and dynamic simulation results. The understanding gaps are closed with additional technical work to improve technologies application and decrease the uncertainties. A comprehensive study for offshore CO2 storage projects identifying critical impacting elements is crucial for estimation, inje
{"title":"A Toolkit for Offshore Carbon Capture and Storage CCS","authors":"R. Tewari, C. Tan, M. Sedaralit","doi":"10.2523/iptc-22307-ms","DOIUrl":"https://doi.org/10.2523/iptc-22307-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) capture, utilization, and storage is the best option for mitigating atmospheric emissions of CO2 and thereby controlling the greenhouse gas concentrations in the atmosphere. Despite the benefits, there have been a limited number of projects solely for CO2 sequestration being implemented. The industry is well-versed in gas injection in reservoir formation for pressure maintenance and improving oil recovery. However, there are striking differences between the injection of CO2 into depleted hydrocarbon reservoirs and the engineered storage of CO2. The differences and challenges are compounded when the storage site is karstified carbonate in offshore and bulk storage volume.\u0000 It is paramount to know upfront that CO2 can be stored at a potential storage site and demonstrate that the site can meet required storage performance safety criteria. Comprehensive screening for site selection has been carried out for suitable CO2 storage sites in offshore Sarawak, Malaysia using geographical, geological, geophysical, geomechanical and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generating performance scenarios of the site. In addition, the geochemical interaction of CO2 with reservoir rock has been studied to understand possible changes that may occur during/after injection and their impact on injection processes/mechanisms. Novel 3-way coupled modelling of dynamic-geochemistry-geomechanics processes were carried out to study long-term dynamic behaviour and fate of CO2 in the formation.\u0000 The 3-way coupled modelling helped to understand the likely state of injectant in future and the storage mechanism, i.e., structural, solubility, residual, and mineralized trapping. It also provided realistic storage capacity estimation, incorporating reservoir compaction and porosity/permeability changes. The study indicates deficient localized plastic shear strain in overburden flank fault whilst all the other flaws remained stable. The potential threat of leakage is minimal as target injection pressure is set at initial reservoir pressure, which is much lower than caprock breaching pressure during injection. Furthermore, it was found that the geochemical reaction impact is shallow and localized at the top of the reservoir, making the storage safe in the long term. The integrity of existing wells was evaluated for potential leakage and planned for a proper mitigation plan. Comprehensive measurement, monitoring, and verification (MMV) were also designed using state-of-art tools and dynamic simulation results. The understanding gaps are closed with additional technical work to improve technologies application and decrease the uncertainties.\u0000 A comprehensive study for offshore CO2 storage projects identifying critical impacting elements is crucial for estimation, inje","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82227730","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}
Despite its value and importance to oilfield development and reservoir management, carbon/oxygen (CO) logs are commonly associated with significant challenges that are either related to the wellbore logging environment and/or the physics of the measurement. Shallow depth of investigation is considered the greatest challenge related to the nature of the pulsed-neutron (PN) measurement. It can imply a high degree of uncertainty on the measurement and consequently the calculated water saturation, affecting the true assessment of the reservoir fluids’ saturations, especially in challenging logging environments. In this paper we introduce and prove an innovative approach to increase the depth of investigation of the PN measurement. Currently, all PN logging tools use an electric pulsed neutron generator (PNG), or "particle accelerator" or Minitron, to probe downhole formations with 14 MeV neutrons and record the returning gamma ray signal at a shallow depth of investigation (DOI), which is generally in the range of 7 inches for C/O measurement and 12 inches for sigma measurement. In this new approach, we introduce the idea of increasing DOI of the measured gamma rays through increasing the energy level of the neutrons emitted by a PNG. To prove the concept, a computer modeling and simulation study was conducted using Monte Carlo N-Particle (MCNP) for a pulsed-neutron logging tool to determine DOI for neutron energies higher than 14 MeV. The study involved five different combinations of borehole and formation fluids. Each involved a "block" of 24 MCNP calculations. The 24 calculations inside each block represented the 24 possible combinations of 3 neutron energies (14, 20, 40 MeV), two gamma ray spectral types (inelastic, capture), and four detectors. Data simulation shows that the DOI rises substantially with energy for all tested detectors. Where the enhancement in DOI with the increase in neutron energy is more prolific in case of the inelastic measurement compared to the capture measurement. And of course the deeper the detector (further from the source) the better the DOI, although this can compromise the precision of the measurement. Yet with the recent technology advancements mainly in PNG (producing more neutron population) and GR detector technology (higher and faster count rates), this shall enhance the precision of the measurement and enable us to acquire both accurate and precise measurements at deeper detectors. This patented, innovative approach shall significantly reduce and possibly eliminate one of the main reasons behind the uncertainty of reservoir saturation monitoring using PN logs, which is shallow depth of investigation of the measurement. Having a PNG that can produce neutrons at higher energy levels compared to current industry standard shall allow a deeper, more accurate and a representative evaluation of the reservoir.
{"title":"A Novel System for Large Depth-of-Investigation Pulsed Neutron Measurements and Enhanced Reservoir Saturation Evaluation","authors":"Y. Eltaher, G. Schmid","doi":"10.2523/iptc-22500-ms","DOIUrl":"https://doi.org/10.2523/iptc-22500-ms","url":null,"abstract":"\u0000 Despite its value and importance to oilfield development and reservoir management, carbon/oxygen (CO) logs are commonly associated with significant challenges that are either related to the wellbore logging environment and/or the physics of the measurement. Shallow depth of investigation is considered the greatest challenge related to the nature of the pulsed-neutron (PN) measurement. It can imply a high degree of uncertainty on the measurement and consequently the calculated water saturation, affecting the true assessment of the reservoir fluids’ saturations, especially in challenging logging environments. In this paper we introduce and prove an innovative approach to increase the depth of investigation of the PN measurement.\u0000 Currently, all PN logging tools use an electric pulsed neutron generator (PNG), or \"particle accelerator\" or Minitron, to probe downhole formations with 14 MeV neutrons and record the returning gamma ray signal at a shallow depth of investigation (DOI), which is generally in the range of 7 inches for C/O measurement and 12 inches for sigma measurement. In this new approach, we introduce the idea of increasing DOI of the measured gamma rays through increasing the energy level of the neutrons emitted by a PNG. To prove the concept, a computer modeling and simulation study was conducted using Monte Carlo N-Particle (MCNP) for a pulsed-neutron logging tool to determine DOI for neutron energies higher than 14 MeV.\u0000 The study involved five different combinations of borehole and formation fluids. Each involved a \"block\" of 24 MCNP calculations. The 24 calculations inside each block represented the 24 possible combinations of 3 neutron energies (14, 20, 40 MeV), two gamma ray spectral types (inelastic, capture), and four detectors. Data simulation shows that the DOI rises substantially with energy for all tested detectors. Where the enhancement in DOI with the increase in neutron energy is more prolific in case of the inelastic measurement compared to the capture measurement. And of course the deeper the detector (further from the source) the better the DOI, although this can compromise the precision of the measurement. Yet with the recent technology advancements mainly in PNG (producing more neutron population) and GR detector technology (higher and faster count rates), this shall enhance the precision of the measurement and enable us to acquire both accurate and precise measurements at deeper detectors.\u0000 This patented, innovative approach shall significantly reduce and possibly eliminate one of the main reasons behind the uncertainty of reservoir saturation monitoring using PN logs, which is shallow depth of investigation of the measurement. Having a PNG that can produce neutrons at higher energy levels compared to current industry standard shall allow a deeper, more accurate and a representative evaluation of the reservoir.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82238697","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}
L. Affede, R. Lorefice, Larissa Pinto Vieira, M. Giubertoni, Lorenzo Buzzi, G. Carpineta
During drilling of three exploration wells challenging conditions encountered, such as temperatures up to 180°C, interbedded highly reactive shales/silts, formation pressures which required mud weights up to 2.35 sg and narrow margin between pore and fracture gradients, posed a host of technical, logistical and cost challenges to Eni activities. These conditions required an accurate drilling fluids design to maximize operational efficiency and to minimize the risks related to such an extreme environment. Technical demands were particularly critical since the reactive shale formations had historically proved to be difficult to inhibit when drilled with Water Based Mud and might have caused swelling, tight hole, sticky wireline runs, bit-balling and accretion that could have resulted, among other issues, in low penetration rates (ROP). The formation nature coupled with ECD (Equivalent Circulation Density) constraints due to the high mud weight required to cope with high pore pressure, which also caused high mud rheology readings, were therefore the main limits to be overcome to achieve the well objectives. A tailored drilling fluid program was thus proposed which consisted of an inhibitive HPWBM (High Performance Water Based Mud) that could be converted to an HT-HPWBM, (High Temperature-High Performances Water Based Mud) while drilling, to cross the deeper and hotter sections of the well. This fluid was specifically engineered and optimized after each well in order to contain high concentration of a combination of monovalent salts to guarantee inhibition and reduce solids loading, dedicated polyamine shale inhibitor and fluid loss additives to minimize API/HPHT filtrate and filter cake thickness with the aim to reduce shale water invasion throughout the drilling campaign, graphite to minimizes fluid invasion and fracture propagation and ROP (Rate Of Penetration) enhancer continuously injected using dedicated pump to act as anti-balling and anti-accretion additive. The achieved results were drilling targets delivered safely, on time and with good overall fluid performances which either reduced or eliminated many of the challenges seen in offset wells, including: no barite sag, rheology stability, and stable long-term mud properties and wellbore conditions even during extended formation logs acquisitions. This paper covers the design, execution and accomplishments of the water-based drilling fluids employed on three HP/HT wells drilled, together with all of the lessons learned captured, highlighting the evolution of these systems to reach a step-change in terms of performances in such a harsh environment.
{"title":"Drilling Offshore Wells with HP WBM in Extreme HP HT Conditions","authors":"L. Affede, R. Lorefice, Larissa Pinto Vieira, M. Giubertoni, Lorenzo Buzzi, G. Carpineta","doi":"10.2523/iptc-21965-ms","DOIUrl":"https://doi.org/10.2523/iptc-21965-ms","url":null,"abstract":"\u0000 During drilling of three exploration wells challenging conditions encountered, such as temperatures up to 180°C, interbedded highly reactive shales/silts, formation pressures which required mud weights up to 2.35 sg and narrow margin between pore and fracture gradients, posed a host of technical, logistical and cost challenges to Eni activities. These conditions required an accurate drilling fluids design to maximize operational efficiency and to minimize the risks related to such an extreme environment.\u0000 Technical demands were particularly critical since the reactive shale formations had historically proved to be difficult to inhibit when drilled with Water Based Mud and might have caused swelling, tight hole, sticky wireline runs, bit-balling and accretion that could have resulted, among other issues, in low penetration rates (ROP). The formation nature coupled with ECD (Equivalent Circulation Density) constraints due to the high mud weight required to cope with high pore pressure, which also caused high mud rheology readings, were therefore the main limits to be overcome to achieve the well objectives.\u0000 A tailored drilling fluid program was thus proposed which consisted of an inhibitive HPWBM (High Performance Water Based Mud) that could be converted to an HT-HPWBM, (High Temperature-High Performances Water Based Mud) while drilling, to cross the deeper and hotter sections of the well. This fluid was specifically engineered and optimized after each well in order to contain high concentration of a combination of monovalent salts to guarantee inhibition and reduce solids loading, dedicated polyamine shale inhibitor and fluid loss additives to minimize API/HPHT filtrate and filter cake thickness with the aim to reduce shale water invasion throughout the drilling campaign, graphite to minimizes fluid invasion and fracture propagation and ROP (Rate Of Penetration) enhancer continuously injected using dedicated pump to act as anti-balling and anti-accretion additive.\u0000 The achieved results were drilling targets delivered safely, on time and with good overall fluid performances which either reduced or eliminated many of the challenges seen in offset wells, including: no barite sag, rheology stability, and stable long-term mud properties and wellbore conditions even during extended formation logs acquisitions.\u0000 This paper covers the design, execution and accomplishments of the water-based drilling fluids employed on three HP/HT wells drilled, together with all of the lessons learned captured, highlighting the evolution of these systems to reach a step-change in terms of performances in such a harsh environment.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81759873","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}
M. A. Hassan, Jim Strand, A. Strømhaug, Lene Lykke Erichsen
Well Construction Automation is gradually becoming more prominent in oil & gas industry. It encompasses the application of digital technology in all aspects of well drilling and completion (i.e., automatic well design, digi-talization of downhole tools & surface equipment, remote monitoring, real time data transmission, and robotic rig systems). This paper presents a new workflow of Automatic Well Design, at a mere click of a computer mouse, using integrated cloud software. A software tool, named WellDesign, is used to demonstrate Automatic Well Design workflow. It utilizes net-works and cloud computers for data storage and collaboration and offers a set of Application Programming In-terfaces (APIs), enabling full automation, where whole or parts of the software can be operated by other com-puters. The software GUI can be accessed via any modern web browser across all kinds of computers (Win-dows, Macs) and any other smart devices (tablets, phones). Two automatic design workflows shall be illustrated in detail: Automatic Well Trajectories Automatic Casing Design
{"title":"1-Click Automatic Well Design Using Integrated Cloud Software","authors":"M. A. Hassan, Jim Strand, A. Strømhaug, Lene Lykke Erichsen","doi":"10.2523/iptc-22018-ms","DOIUrl":"https://doi.org/10.2523/iptc-22018-ms","url":null,"abstract":"\u0000 Well Construction Automation is gradually becoming more prominent in oil & gas industry. It encompasses the application of digital technology in all aspects of well drilling and completion (i.e., automatic well design, digi-talization of downhole tools & surface equipment, remote monitoring, real time data transmission, and robotic rig systems). This paper presents a new workflow of Automatic Well Design, at a mere click of a computer mouse, using integrated cloud software.\u0000 A software tool, named WellDesign, is used to demonstrate Automatic Well Design workflow. It utilizes net-works and cloud computers for data storage and collaboration and offers a set of Application Programming In-terfaces (APIs), enabling full automation, where whole or parts of the software can be operated by other com-puters. The software GUI can be accessed via any modern web browser across all kinds of computers (Win-dows, Macs) and any other smart devices (tablets, phones).\u0000 Two automatic design workflows shall be illustrated in detail:\u0000 Automatic Well Trajectories Automatic Casing Design","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89829759","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}
A. Aljawder, Yusuf Engineer, Bader Alhammadi, A.Wahab Buarki
The Ahmadi formation of Bahrain field is of Middle Cretaceous age. It is predominantly a shale lying immediately below the Magwa member of the Rumaila formation and contains two limestone units in the Bahrain field, which are referred to as Aa and Ab members. Limestone Aa and Ab are present with practically uniform thickness over the entire Bahrain field area, as a blanket like deposition. The Ahmadi Reservoir in the Bahrain Field has been producing since 1933. Ahmadi consists of two main limestone units, AA and AB, separated by a 40-45 ft shale member. The AA reservoir is typically 3 to 4 feet thick, while the AB is divided into three separate units: AB1, AB2, and AB3. AB1 and AB3 are fairly clean limestone units, with a cumulative net reservoir of 12 to 14 ft. AB2 is about 4 to 5 feet thick, and characterized as a non-reservoir. The matrix permeability ranges from 1 to 2 mD. The main focus of the primary development plan was established by infill horizontal open hole lateral section, targeting the AB3 zone. However, poor matrix permeability and the irregularly spaced natural fracture network of the AB3 zone can hinder the primary development strategy and well production. Therefore, acid fracturing with 8 stages (60 ft each) in the open hole lateral section was implemented to improve well performance. A study was initiated in 2019 to improve the acid fracturing technique in the AB3 open hole lateral section (horizontal wells) by increasing the number of stages from 8 stages (60 ft each) to 18 stages (60 ft each). The wells targeted were located in areas with low reservoir quality and low fracture networks in order to induce artificial fractures, thereby improving well performance.
{"title":"A Study on Increasing the Number of Stages in the Acid Fracturing Stimulation Technique in Horizontal Wells for a Tight Fractured Carbonate Reservoir in the Bahrain Field","authors":"A. Aljawder, Yusuf Engineer, Bader Alhammadi, A.Wahab Buarki","doi":"10.2523/iptc-22586-ea","DOIUrl":"https://doi.org/10.2523/iptc-22586-ea","url":null,"abstract":"\u0000 The Ahmadi formation of Bahrain field is of Middle Cretaceous age. It is predominantly a shale lying immediately below the Magwa member of the Rumaila formation and contains two limestone units in the Bahrain field, which are referred to as Aa and Ab members. Limestone Aa and Ab are present with practically uniform thickness over the entire Bahrain field area, as a blanket like deposition.\u0000 The Ahmadi Reservoir in the Bahrain Field has been producing since 1933. Ahmadi consists of two main limestone units, AA and AB, separated by a 40-45 ft shale member. The AA reservoir is typically 3 to 4 feet thick, while the AB is divided into three separate units: AB1, AB2, and AB3. AB1 and AB3 are fairly clean limestone units, with a cumulative net reservoir of 12 to 14 ft. AB2 is about 4 to 5 feet thick, and characterized as a non-reservoir. The matrix permeability ranges from 1 to 2 mD.\u0000 The main focus of the primary development plan was established by infill horizontal open hole lateral section, targeting the AB3 zone. However, poor matrix permeability and the irregularly spaced natural fracture network of the AB3 zone can hinder the primary development strategy and well production. Therefore, acid fracturing with 8 stages (60 ft each) in the open hole lateral section was implemented to improve well performance.\u0000 A study was initiated in 2019 to improve the acid fracturing technique in the AB3 open hole lateral section (horizontal wells) by increasing the number of stages from 8 stages (60 ft each) to 18 stages (60 ft each). The wells targeted were located in areas with low reservoir quality and low fracture networks in order to induce artificial fractures, thereby improving well performance.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80863568","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}
Electrical submersible pump providers are always collaborating with client to overcome the challenges of costly ESP change out by offshore workover rigs and the conventional well intervention by offshore barges, in addition to the harsh reservoir environments due to high H2S and high temperature. Accordingly, operating companies are keen to minimize the number of ESP failures and avoid costly offshore workovers especially in high producers and when the demand of production is high. In effort to improve the ESP reliability and ensure continuous production, several recent technologies were combined to boost the run life of the overall completion. The combination of these technologies improved the run life and the reliability of the system and resulted in massive financial impact as it saves rig cost, Barge cost, wireline cost, operations cost and more importantly the deferred production. This paper will elaborate in details about the technologies utilized in this completion and how it caused considerable financial impact on both vendor and client.
{"title":"First Metal to Metal Dual Auto Switch ESP","authors":"Ali AlOlaywat","doi":"10.2523/iptc-22426-ms","DOIUrl":"https://doi.org/10.2523/iptc-22426-ms","url":null,"abstract":"\u0000 Electrical submersible pump providers are always collaborating with client to overcome the challenges of costly ESP change out by offshore workover rigs and the conventional well intervention by offshore barges, in addition to the harsh reservoir environments due to high H2S and high temperature. Accordingly, operating companies are keen to minimize the number of ESP failures and avoid costly offshore workovers especially in high producers and when the demand of production is high. In effort to improve the ESP reliability and ensure continuous production, several recent technologies were combined to boost the run life of the overall completion.\u0000 The combination of these technologies improved the run life and the reliability of the system and resulted in massive financial impact as it saves rig cost, Barge cost, wireline cost, operations cost and more importantly the deferred production.\u0000 This paper will elaborate in details about the technologies utilized in this completion and how it caused considerable financial impact on both vendor and client.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78257610","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}
For most offshore and tidal zolone oil development in North China, one of the major challenges of the industry is high drilling uncertainty and low reservoir encountered rate at the braided river delta and fluvial deposition environment with the common characters of thin sand channels, severe lateral change, unstable sand structure and low sand connectivity. Optimizing the wellbore placement inside the complex reservoir and depicting the sand with detailed information are gradually being critical to real time geosteering in these areas. Over the last decades, the continuous improvement of distance-to-boundary logging while drilling workflows has dramatically enhance the drilling efficiency of horizontal well. However, relatively short depth of detection (DOD) and low sensitivity to multi-layer environment still cannot meet the requirement of drilling under these complicated geologies. To reduce the geosteering uncertainty and enhance formation evaluation in complex environment, a new advancement in mapping-while-drilling electromagnetic propagation resistivity method, with the industry's first combination of axial, tilted and transverse antennas and significant software enhancements, made a momentous progress for complex reservoir geosteering and characterization. Compared to the previous generation, this service could provide: Larger depth of detection which doubled the previous generation. For one hand, larger DOD means earlier proactive strategy for the well position optimization; For the other one, enlarged vision also helps achieve whole delineation of the target sand channel and thus much better geological understanding for the reservoir.More sensitivity for anisotropy and local sedimentary character. Improved measurements set and enhanced software algorithm can visualize the detailed characteristics inside the sand channel. With its up-to-eight-layer resistivity reconstruction, the refined inversion exceeds the existing propagation resistivity answer product. Outstanding performance was observed during the implementation. The target sand channel of 6-7m thickness could be delineated clearly by the refined inversion. It not only depicted the whole picture the sand body, but also provided an earlier sign of structural fluctuation, which ensured the success and high oil recovery rate of the horizontal section. For the well with higher anisotropy or more local sedimentary features, comparing to the blur reflection of the previous method, this ultra-high-definition technology could provide a sophisticated vision of the shape, thickness, direction and resistivity property of the local thin layers and shaly block. Reliable evidence of both outline and inside characteristics of the sand channels improved the further well path design and geological understanding. The ultra-high-definition mapping-while-drilling technology opened the market of complex deposition environment drilling. It remarkably increased the reservoir encountered rate and
{"title":"Next Level of Complex Reservoir Geosteering: The New Generation of Ultra-High-Definition Directional Resistivity Propagation Method","authors":"Guoquan Zhao, Baoqiang Jin, Liuhe Yang, Wei Li, Junliang Zhou, Lili Zhang, Fei Wang, Haifeng Wang, Shuzhong Li, Zhongtiang Hu, Tianyun Xu, J. Dolan","doi":"10.2523/iptc-22208-ea","DOIUrl":"https://doi.org/10.2523/iptc-22208-ea","url":null,"abstract":"\u0000 For most offshore and tidal zolone oil development in North China, one of the major challenges of the industry is high drilling uncertainty and low reservoir encountered rate at the braided river delta and fluvial deposition environment with the common characters of thin sand channels, severe lateral change, unstable sand structure and low sand connectivity. Optimizing the wellbore placement inside the complex reservoir and depicting the sand with detailed information are gradually being critical to real time geosteering in these areas.\u0000 Over the last decades, the continuous improvement of distance-to-boundary logging while drilling workflows has dramatically enhance the drilling efficiency of horizontal well. However, relatively short depth of detection (DOD) and low sensitivity to multi-layer environment still cannot meet the requirement of drilling under these complicated geologies.\u0000 To reduce the geosteering uncertainty and enhance formation evaluation in complex environment, a new advancement in mapping-while-drilling electromagnetic propagation resistivity method, with the industry's first combination of axial, tilted and transverse antennas and significant software enhancements, made a momentous progress for complex reservoir geosteering and characterization.\u0000 Compared to the previous generation, this service could provide: Larger depth of detection which doubled the previous generation. For one hand, larger DOD means earlier proactive strategy for the well position optimization; For the other one, enlarged vision also helps achieve whole delineation of the target sand channel and thus much better geological understanding for the reservoir.More sensitivity for anisotropy and local sedimentary character. Improved measurements set and enhanced software algorithm can visualize the detailed characteristics inside the sand channel. With its up-to-eight-layer resistivity reconstruction, the refined inversion exceeds the existing propagation resistivity answer product.\u0000 Outstanding performance was observed during the implementation. The target sand channel of 6-7m thickness could be delineated clearly by the refined inversion. It not only depicted the whole picture the sand body, but also provided an earlier sign of structural fluctuation, which ensured the success and high oil recovery rate of the horizontal section.\u0000 For the well with higher anisotropy or more local sedimentary features, comparing to the blur reflection of the previous method, this ultra-high-definition technology could provide a sophisticated vision of the shape, thickness, direction and resistivity property of the local thin layers and shaly block. Reliable evidence of both outline and inside characteristics of the sand channels improved the further well path design and geological understanding.\u0000 The ultra-high-definition mapping-while-drilling technology opened the market of complex deposition environment drilling. It remarkably increased the reservoir encountered rate and","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76507841","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}
Multiphase flow is frequently encountered in upstream O&G industry that has significant impact on the development of numerous production technologies such as multiphase flowmeter. Before the deployment of these technologies in an oil/gas field, the technologies are tested in a multiphase industrial flow loop test that emulates multiphase test conditions. This paper presents a digital twin of 2-phase flow (oil & water) as a low cost alternative to expensive multiphase flow test. We have adopted backward strategy to design the digital twin of multiphase flow. At first, we characterized our proprietary microwave water-cut (WC) meter in an industrial flow loop in variable test conditions. Then, multiple digital models of the flow regimes were built and tested on our microwave WC meter. One of those models (rotated zigzag) was able to accurately predict WC sensor response over full WC range in oil continuous as well as water continuous flow conditions under varying salinity levels. Two sets of responses have been recorded and compared – first obtained from the industrial flow loop trials and second from our EM simulation model. Key microwave resonator parameters such as resonant frequency (f0) and quality (Q) factor have been compared under varying conditions. The comparison suggests that f0 & Q-factor give higher sensitivity against WC in oil continuous and water continuous flow conditions respectively. Moreover, WC sensor performance was also compared under varying salinity conditions in the range of 20,000 ppm to 80,000 ppm and digital twin is able to successfully predict the sensor response in these conditions as well. Significant amount of resources are spent on setting desired flow condition such as flow regime, WC and required salinity level. Our proposed digital twin model is able to emulate all of these multiphase flow conditions at negligible cost. It can help develop & test new production technologies without requiring to spend huge amount of money on lengthy, complex and expensive multiphase flow loop tests.
{"title":"Digital Twin of Expensive Multiphase Flow Loop Test to Develop Next Generation of Production Technologies","authors":"M. A. Karimi, M. Arsalan, A. Shamim","doi":"10.2523/iptc-22124-ea","DOIUrl":"https://doi.org/10.2523/iptc-22124-ea","url":null,"abstract":"\u0000 Multiphase flow is frequently encountered in upstream O&G industry that has significant impact on the development of numerous production technologies such as multiphase flowmeter. Before the deployment of these technologies in an oil/gas field, the technologies are tested in a multiphase industrial flow loop test that emulates multiphase test conditions. This paper presents a digital twin of 2-phase flow (oil & water) as a low cost alternative to expensive multiphase flow test.\u0000 We have adopted backward strategy to design the digital twin of multiphase flow. At first, we characterized our proprietary microwave water-cut (WC) meter in an industrial flow loop in variable test conditions. Then, multiple digital models of the flow regimes were built and tested on our microwave WC meter. One of those models (rotated zigzag) was able to accurately predict WC sensor response over full WC range in oil continuous as well as water continuous flow conditions under varying salinity levels.\u0000 Two sets of responses have been recorded and compared – first obtained from the industrial flow loop trials and second from our EM simulation model. Key microwave resonator parameters such as resonant frequency (f0) and quality (Q) factor have been compared under varying conditions. The comparison suggests that f0 & Q-factor give higher sensitivity against WC in oil continuous and water continuous flow conditions respectively. Moreover, WC sensor performance was also compared under varying salinity conditions in the range of 20,000 ppm to 80,000 ppm and digital twin is able to successfully predict the sensor response in these conditions as well.\u0000 Significant amount of resources are spent on setting desired flow condition such as flow regime, WC and required salinity level. Our proposed digital twin model is able to emulate all of these multiphase flow conditions at negligible cost. It can help develop & test new production technologies without requiring to spend huge amount of money on lengthy, complex and expensive multiphase flow loop tests.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77352025","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}
To build live-RAM (Reliability, Availability, and Maintainability) model to enable evaluating System Production Availability (PA) associated with variety of shutdown scenarios, with an objective to ensure Production optimization, Reliability improvement, and to support system de-bottlenecking. This Model is complemented by web-based updating tools to reflect changes in Production Profile, Maintenance plans, Reliability and Maintainability data, and equipment modifications.
{"title":"Developing Live RAM Model for Production Availability Evaluation","authors":"Walid Mossa","doi":"10.2523/iptc-22250-ea","DOIUrl":"https://doi.org/10.2523/iptc-22250-ea","url":null,"abstract":"\u0000 \u0000 \u0000 To build live-RAM (Reliability, Availability, and Maintainability) model to enable evaluating System Production Availability (PA) associated with variety of shutdown scenarios, with an objective to ensure Production optimization, Reliability improvement, and to support system de-bottlenecking. This Model is complemented by web-based updating tools to reflect changes in Production Profile, Maintenance plans, Reliability and Maintainability data, and equipment modifications.\u0000","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75208907","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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