R. Guises, E. Auger, S. Bordoloi, Ayodele Ofi, C. Cranfield, H. Freitag
Natural gas consumption is expected to grow significantly in coming decades in response to cleaner energy initiatives. Underground gas storage (UGS) will be key to addressing supply and demand dynamics for this transition to be successful. This technical paper will demonstrate the importance of an integrated subsurface characterization and monitoring approach not only for the construction of UGS, but also to guarantee safe and efficient operation over many decades. Key to long-term success of UGS is maximizing working capacity with respect to volume and pressure and maintaining well injection and withdrawal capabilities. Initial assessment steps involve determination of maximum storage capacity and an estimation of required cushion gas volumes. In similar manner to conventional field evaluation, we perform an integrated geological, geophysical, petrophysical and geomechanical characterization of the subsurface. However, for UGS facilities, the impact of cyclic variations of reservoir pressures on subsurface behavior and cap rock integrity also needs to be evaluated to determine safe operating limits at every point in time during the life of the UGS project. The holistic approach described above allows the operator to optimize the number of wells, well placement, completion design, etc. to ensure long-term safe and efficient operations. Furthermore, close integration of subsurface understanding with optimization of surface facilities, such as the compression system, is another critical component to ensure optimum UGS performance and deliverability. Moreover, another important task of the final phase of UGS facilities design involves enablement of sustainable operation through an asset integrity management plan. This phase is articulated around reservoir surveillance plans that monitor pressure, rock deformation and seismicity, in addition to regular wellbore inspection. Through close operations monitoring and the utilization of advanced data analytics, observations are compared to existing models for validation and operation optimization. Importantly we show that adapted monitoring programs provide critical long-term insight regarding the field response during successive cycles, leading to significant improvement in working gas capacity. A key consideration of this integrated UGS development strategy is based on the seamless integration of subsurface characterization, wellbore construction and well completions to ensure technical and commercial flexibility. The approach also emphasizes the integration with surface facilities design to ensure a true "Storage to Consumer" view for effective de-bottlenecking. Coupled with integrated subsurface integrity monitoring, this ensures a faster, cost efficient and safe response to the construction and operation of UGS facilities.
{"title":"The Importance of Subsurface Characterization and Monitoring During Development and Operation of Underground Gas Storage Facilities","authors":"R. Guises, E. Auger, S. Bordoloi, Ayodele Ofi, C. Cranfield, H. Freitag","doi":"10.2118/204787-ms","DOIUrl":"https://doi.org/10.2118/204787-ms","url":null,"abstract":"\u0000 Natural gas consumption is expected to grow significantly in coming decades in response to cleaner energy initiatives. Underground gas storage (UGS) will be key to addressing supply and demand dynamics for this transition to be successful. This technical paper will demonstrate the importance of an integrated subsurface characterization and monitoring approach not only for the construction of UGS, but also to guarantee safe and efficient operation over many decades.\u0000 Key to long-term success of UGS is maximizing working capacity with respect to volume and pressure and maintaining well injection and withdrawal capabilities. Initial assessment steps involve determination of maximum storage capacity and an estimation of required cushion gas volumes. In similar manner to conventional field evaluation, we perform an integrated geological, geophysical, petrophysical and geomechanical characterization of the subsurface. However, for UGS facilities, the impact of cyclic variations of reservoir pressures on subsurface behavior and cap rock integrity also needs to be evaluated to determine safe operating limits at every point in time during the life of the UGS project.\u0000 The holistic approach described above allows the operator to optimize the number of wells, well placement, completion design, etc. to ensure long-term safe and efficient operations. Furthermore, close integration of subsurface understanding with optimization of surface facilities, such as the compression system, is another critical component to ensure optimum UGS performance and deliverability. Moreover, another important task of the final phase of UGS facilities design involves enablement of sustainable operation through an asset integrity management plan. This phase is articulated around reservoir surveillance plans that monitor pressure, rock deformation and seismicity, in addition to regular wellbore inspection. Through close operations monitoring and the utilization of advanced data analytics, observations are compared to existing models for validation and operation optimization. Importantly we show that adapted monitoring programs provide critical long-term insight regarding the field response during successive cycles, leading to significant improvement in working gas capacity.\u0000 A key consideration of this integrated UGS development strategy is based on the seamless integration of subsurface characterization, wellbore construction and well completions to ensure technical and commercial flexibility. The approach also emphasizes the integration with surface facilities design to ensure a true \"Storage to Consumer\" view for effective de-bottlenecking. Coupled with integrated subsurface integrity monitoring, this ensures a faster, cost efficient and safe response to the construction and operation of UGS facilities.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83041206","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}
Mohammad Al Kadem, Ali Radhi Al Ssafwany, Ahmed Abdulghani, Hussain Al Nasir
Stabilization time is an essential key for pressure measurement accuracy. Obtaining representative pressure points in build-up tests for pressure-sensitive reservoirs is driven by optimizing stabilization time. An artificial intelligence technique was used in the study for testing pressure-sensitive reservoirs using measuring gauges. The stabilization time function of reservoir characteristics is generally calculated using the diffusivity equation where rock and fluid properties are honored. The artificial neural network (ANN) technique will be used to predict the stabilization time and optimize it using readily available and known inputs or parameters. The values obtained from the formula known as the diffusion formula and the ANN technique are then compared against the actual values measured from pressure gauges in the reservoirs. The optimization of the number of datasets required to be fed to the network to allow for coverage over the whole range is essential as opposed to the clustering of the datasets. A total of about 3000 pressure derivative samples from the wells were used in the testing, training, and validation of the ANN. The datasets are optimized by dividing them into three fractional parts, and the number optimized through monitoring the ANN performance. The optimization of the stabilization time is essential and leads to the improvement of the ANN learning process. The sensitivity analysis proves that the use of the formula and ANN technique, compared to actual datasets, is better since, in the formula and ANN technique, the time was optimized with an average absolute relative error of 3.67%. The results are near the same, especially when the ANN technique undergoes testing using known and easily available parameters. Time optimization is essential since discreet points or datasets in the ANN technique and formula would not work, allowing ANN to work in situations of optimization. The study was expected to provide additional data and information, considering that stabilization time is essential in obtaining the pressure map representation. ANN is a superior technique and, through its superiority, allows for proper optimization of time as a parameter. Thus it can predict reservoir log data almost accurately. The method used in the study shows the importance of optimizing pressure stabilization time through reduction. The study results can, therefore, be applied in reservoir testing to achieve optimal results.
{"title":"Shut-in Stabilization Time Optimization for Better Reservoir Pressure Monitoring Harnessing Neural Network Modeling","authors":"Mohammad Al Kadem, Ali Radhi Al Ssafwany, Ahmed Abdulghani, Hussain Al Nasir","doi":"10.2118/204900-ms","DOIUrl":"https://doi.org/10.2118/204900-ms","url":null,"abstract":"\u0000 Stabilization time is an essential key for pressure measurement accuracy. Obtaining representative pressure points in build-up tests for pressure-sensitive reservoirs is driven by optimizing stabilization time. An artificial intelligence technique was used in the study for testing pressure-sensitive reservoirs using measuring gauges.\u0000 The stabilization time function of reservoir characteristics is generally calculated using the diffusivity equation where rock and fluid properties are honored. The artificial neural network (ANN) technique will be used to predict the stabilization time and optimize it using readily available and known inputs or parameters. The values obtained from the formula known as the diffusion formula and the ANN technique are then compared against the actual values measured from pressure gauges in the reservoirs.\u0000 The optimization of the number of datasets required to be fed to the network to allow for coverage over the whole range is essential as opposed to the clustering of the datasets. A total of about 3000 pressure derivative samples from the wells were used in the testing, training, and validation of the ANN. The datasets are optimized by dividing them into three fractional parts, and the number optimized through monitoring the ANN performance. The optimization of the stabilization time is essential and leads to the improvement of the ANN learning process. The sensitivity analysis proves that the use of the formula and ANN technique, compared to actual datasets, is better since, in the formula and ANN technique, the time was optimized with an average absolute relative error of 3.67%. The results are near the same, especially when the ANN technique undergoes testing using known and easily available parameters. Time optimization is essential since discreet points or datasets in the ANN technique and formula would not work, allowing ANN to work in situations of optimization.\u0000 The study was expected to provide additional data and information, considering that stabilization time is essential in obtaining the pressure map representation. ANN is a superior technique and, through its superiority, allows for proper optimization of time as a parameter. Thus it can predict reservoir log data almost accurately. The method used in the study shows the importance of optimizing pressure stabilization time through reduction. The study results can, therefore, be applied in reservoir testing to achieve optimal results.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89052502","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}
Ananda Pravana, Humaid Ali Hassan Albalushi, Zakaria Mamari, Badar Al Zeidi, Tom Newman, F. Mounzer
Drilling through some of the reactive shale formations in the western gas fields in the Sultanate of Oman has proven challenging and often troublesome. Frequently, time spent on backreaming would exceed the time required to drill the related hole sections. In addition, the carbonate Natih sequence has also proven problematic. High levels of vibrations are often encountered. Such drilling dysfunctions are known to be destructive to both bit and bottom hole assembly (BHA). Different mud systems, drive systems and reamer types were used in separate attempts to alleviate the faced dysfunctions to little avail. This paper illustrates a trial campaign introducing an alternative design stabilizer (ADS) and reamer (ADR) to the drilling BHA with the aim of addressing and resolving the aforementioned limiters. Based on a set of agreed-on key performance indicators (KPIs), and following a methodical approach, a 4-well trial was conducted in order to introduce a unique stabilizer-reamer design while simultaneously scrutinizing and optimizing the BHA configuration accordingly. Two of the candidate wells targeted the 17-1/2" section while the other 2 wells targeted the 12-1/4" sections. The main goals were to reduce the time spent on backreaming by 50% and minimize the experienced levels of vibrations in order to extend bit runs and reliability of the different BHA components. For further comparisons, the same approach was tested on a rotary BHA as well as a steerable motor BHA in the larger hole sections. Both 17-1/2" sections were each drilled in a single run similar to the second 12-1/4" section. The first 12-1/4" also proved smooth and required 2 runs due to bit hours, still noting a record section distance run for a single bit. All BHAs were optimized around the placement of the new design stab and reamer design combination. The optimized BHA configuration enabled pulling out of hole (POOH) on elevators for all 4 sections almost fully eliminating the hard backreaming experienced in past wells. In addition, it was also noted that in all cases the levels of vibrations were significantly reduced compared to what is typically experienced and recorded in the offset wells. This enabled a record setting bit run for that particular section and field. The authors detail the historical challenges encountered drilling such wells then present the applied benchmarking exercise and the adopted systematic approach to tackle those challenges. Following, the unique design characteristics of the deployed technology are highlighted and how this is applied in each of the runs in view of optimizing casing point to casing point section delivery times. Finally, the achieved results and gains are underlined together with a roadmap forward.
{"title":"Successful Mitigation of Excessive Backreaming in Troublesome Vertical Applications in the Sultanate of Oman","authors":"Ananda Pravana, Humaid Ali Hassan Albalushi, Zakaria Mamari, Badar Al Zeidi, Tom Newman, F. Mounzer","doi":"10.2118/204627-ms","DOIUrl":"https://doi.org/10.2118/204627-ms","url":null,"abstract":"\u0000 Drilling through some of the reactive shale formations in the western gas fields in the Sultanate of Oman has proven challenging and often troublesome. Frequently, time spent on backreaming would exceed the time required to drill the related hole sections.\u0000 In addition, the carbonate Natih sequence has also proven problematic. High levels of vibrations are often encountered. Such drilling dysfunctions are known to be destructive to both bit and bottom hole assembly (BHA). Different mud systems, drive systems and reamer types were used in separate attempts to alleviate the faced dysfunctions to little avail.\u0000 This paper illustrates a trial campaign introducing an alternative design stabilizer (ADS) and reamer (ADR) to the drilling BHA with the aim of addressing and resolving the aforementioned limiters.\u0000 Based on a set of agreed-on key performance indicators (KPIs), and following a methodical approach, a 4-well trial was conducted in order to introduce a unique stabilizer-reamer design while simultaneously scrutinizing and optimizing the BHA configuration accordingly. Two of the candidate wells targeted the 17-1/2\" section while the other 2 wells targeted the 12-1/4\" sections. The main goals were to reduce the time spent on backreaming by 50% and minimize the experienced levels of vibrations in order to extend bit runs and reliability of the different BHA components. For further comparisons, the same approach was tested on a rotary BHA as well as a steerable motor BHA in the larger hole sections.\u0000 Both 17-1/2\" sections were each drilled in a single run similar to the second 12-1/4\" section. The first 12-1/4\" also proved smooth and required 2 runs due to bit hours, still noting a record section distance run for a single bit. All BHAs were optimized around the placement of the new design stab and reamer design combination. The optimized BHA configuration enabled pulling out of hole (POOH) on elevators for all 4 sections almost fully eliminating the hard backreaming experienced in past wells. In addition, it was also noted that in all cases the levels of vibrations were significantly reduced compared to what is typically experienced and recorded in the offset wells. This enabled a record setting bit run for that particular section and field.\u0000 The authors detail the historical challenges encountered drilling such wells then present the applied benchmarking exercise and the adopted systematic approach to tackle those challenges. Following, the unique design characteristics of the deployed technology are highlighted and how this is applied in each of the runs in view of optimizing casing point to casing point section delivery times. Finally, the achieved results and gains are underlined together with a roadmap forward.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85911307","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}
Klemens Katterbauer, Abdallah Al Shehri, A. Marsala
Water front movement in fractured carbonate reservoirs occurs in micro-fractures, corridors and interconnected fracture channels (above 5 mm in size) that penetrate the carbonate reservoir structure. Determining the fracture channels and the water front movements within the flow corridors is critical to optimize sweep efficiency and increase hydrocarbon recovery. In this work, we present a new smart orthogonal matching pursuit (OMP) algorithm for water front movement detection in carbonate fracture channels. The method utilizes a combined artificial intelligence) AI-OMP approach to first analyze and extract the potential fracture channels and then subsequently deploys a deep learning approach for estimating the water saturation patterns in the fracture channels. The OMP utilizes the sparse fracture to sensor correlation to determine the fracture channels impacting each individual sensor. The deep learning method then utilizes the fracture channel estimates to assess the water front movements. We tested the AI-OMP framework on a synthetic fracture carbonate reservoir box model exhibiting a complex fracture system. Fracture Robots (FracBots, about 5mm in size) technology will be used to sense key reservoir parameters (e.g., temperature, pressure, pH and other chemical parameters) and represent an important step towards enhancing reservoir surveillance (Al Shehri, et al. 2021). The technology is comprised of a wireless micro-sensor network for mapping and monitoring fracture channels in conventional and unconventional reservoirs. The system establishes wireless network connectivity via magnetic induction (MI)-based communication, since it exhibits highly reliable and constant channel conditions with sufficiently communication range inside an oil reservoir environment. The system architecture of the FracBots network has two layers: FracBot nodes layer and a base station layer. A number of subsurface FracBot sensors are injected in the formation fracture channels to record data affected by changes in water saturation. The sensor placement can be adapted in the reservoir formation in order to improve sensor measurement data quality, as well as better track the penetrating water fronts. They will move with the injected fluids and distribute themselves in the fracture channels where they start sensing the surrounding environment’s conditions; they communicate the data, including their location coordinates, among each other to finally transmit the information in multi-hop fashion to the base station installed inside the wellbore. The base station layer consists of a large antenna connected to an aboveground gateway. The data collected from the FracBots network are transmitted to the control room via aboveground gateway for further processing. The results exhibited strong estimation performance in both accurately determining the fracture channels and the saturation pattern in the subsurface reservoir. The results indicate that the framework performs w
{"title":"Sparse Water Fracture Channel Detection from Subsurface Sensors Via a Smart Orthogonal Matching Pursuit","authors":"Klemens Katterbauer, Abdallah Al Shehri, A. Marsala","doi":"10.2118/204529-ms","DOIUrl":"https://doi.org/10.2118/204529-ms","url":null,"abstract":"\u0000 Water front movement in fractured carbonate reservoirs occurs in micro-fractures, corridors and interconnected fracture channels (above 5 mm in size) that penetrate the carbonate reservoir structure. Determining the fracture channels and the water front movements within the flow corridors is critical to optimize sweep efficiency and increase hydrocarbon recovery.\u0000 In this work, we present a new smart orthogonal matching pursuit (OMP) algorithm for water front movement detection in carbonate fracture channels. The method utilizes a combined artificial intelligence) AI-OMP approach to first analyze and extract the potential fracture channels and then subsequently deploys a deep learning approach for estimating the water saturation patterns in the fracture channels. The OMP utilizes the sparse fracture to sensor correlation to determine the fracture channels impacting each individual sensor. The deep learning method then utilizes the fracture channel estimates to assess the water front movements.\u0000 We tested the AI-OMP framework on a synthetic fracture carbonate reservoir box model exhibiting a complex fracture system. Fracture Robots (FracBots, about 5mm in size) technology will be used to sense key reservoir parameters (e.g., temperature, pressure, pH and other chemical parameters) and represent an important step towards enhancing reservoir surveillance (Al Shehri, et al. 2021). The technology is comprised of a wireless micro-sensor network for mapping and monitoring fracture channels in conventional and unconventional reservoirs. The system establishes wireless network connectivity via magnetic induction (MI)-based communication, since it exhibits highly reliable and constant channel conditions with sufficiently communication range inside an oil reservoir environment. The system architecture of the FracBots network has two layers: FracBot nodes layer and a base station layer. A number of subsurface FracBot sensors are injected in the formation fracture channels to record data affected by changes in water saturation. The sensor placement can be adapted in the reservoir formation in order to improve sensor measurement data quality, as well as better track the penetrating water fronts. They will move with the injected fluids and distribute themselves in the fracture channels where they start sensing the surrounding environment’s conditions; they communicate the data, including their location coordinates, among each other to finally transmit the information in multi-hop fashion to the base station installed inside the wellbore. The base station layer consists of a large antenna connected to an aboveground gateway. The data collected from the FracBots network are transmitted to the control room via aboveground gateway for further processing.\u0000 The results exhibited strong estimation performance in both accurately determining the fracture channels and the saturation pattern in the subsurface reservoir. The results indicate that the framework performs w","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73354617","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}
One of the harms to climate brought about by anthropogenically instigated environmental change is the overabundance creation of CO2 because of industrialization. Research and development endeavors so far have been focused on the improvement of CCS (Carbon Capture and Sequestration), with the fundamental spotlight on the best way to eliminate CO2 from vent gases and how to cover it perpetually in deep aquifers or depleted oil and gas reservoirs to save the environment from the detrimental effects of CO2. At one side, the alarming situation due to excess emission of CO2 from industries has been bulled out and simultaneously, there is higher potential for CO2 in the depleted oil fields which can aid to the Enhanced Oil Recovery (EOR) through the prolonged CO2 injection in depleted oil fields. It is currently turning out to be certain that CCS technology could advance the utilization of fossil fuels than in any case recently thought. This paper discusses the integration of Carbon Capture and Sequestration (CCS) technology with the progressive strategy of Enhanced Oil Recovery (EOR). CCS includes various advances that can be utilized to catch CO2 from point sources. Countries that are badly affected by the harmful effects of global warming with depleting oil reserves in the very near future can be the most viable target of the CCS Project. The scope and potential of different techniques of CCS along with the opportunities and challenges and the real case scenarios happening in the world are discussed in detail. The economics, process cycle and case studies of this futuristic technology intend to give valuable insight to the implementation of this integrated technique to the prevalent depleting oil fields around the globe.
{"title":"How Leaders Can Shape the Oil & Gas Industry – Accelerating Innovations Through Business & Environmental Intelligent Systems","authors":"Clifford Louis, Hassan Khan, Yawar Ali","doi":"10.2118/204556-ms","DOIUrl":"https://doi.org/10.2118/204556-ms","url":null,"abstract":"\u0000 One of the harms to climate brought about by anthropogenically instigated environmental change is the overabundance creation of CO2 because of industrialization. Research and development endeavors so far have been focused on the improvement of CCS (Carbon Capture and Sequestration), with the fundamental spotlight on the best way to eliminate CO2 from vent gases and how to cover it perpetually in deep aquifers or depleted oil and gas reservoirs to save the environment from the detrimental effects of CO2. At one side, the alarming situation due to excess emission of CO2 from industries has been bulled out and simultaneously, there is higher potential for CO2 in the depleted oil fields which can aid to the Enhanced Oil Recovery (EOR) through the prolonged CO2 injection in depleted oil fields. It is currently turning out to be certain that CCS technology could advance the utilization of fossil fuels than in any case recently thought.\u0000 This paper discusses the integration of Carbon Capture and Sequestration (CCS) technology with the progressive strategy of Enhanced Oil Recovery (EOR). CCS includes various advances that can be utilized to catch CO2 from point sources. Countries that are badly affected by the harmful effects of global warming with depleting oil reserves in the very near future can be the most viable target of the CCS Project. The scope and potential of different techniques of CCS along with the opportunities and challenges and the real case scenarios happening in the world are discussed in detail.\u0000 The economics, process cycle and case studies of this futuristic technology intend to give valuable insight to the implementation of this integrated technique to the prevalent depleting oil fields around the globe.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72574395","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 paper presents a systemic approach using Engineering and analytics methods to avail the fastest and safest responses to recovering business operations after Abqaiq Plants major disruption after the 2019 September 14th incident. This new approach using value and agile engineering, risk management methodologies combined with the business continuity model suggested was successfully applied to recover Abqaiq Plants Operations after catastrophic events occurred. This paper pretends to serve as example about how the business continuity plan should response to a major emergency and how this planning activity could be effectively supported using a Value Oriented Engineering Solutions (VOES). This VOES approach is based on Business continuity framework and adapted for use during emergency situations to generate effective and urgent responses to recover one of the most strategical operations in the Oil and Gas Industry worldwide ahead of the last year significant disruption. VOES approach vastly implemented during Abqaiq Plants Restoration allowed a 100% functional recovery on 9 days, 5 days in advance to the most optimistic scenario. This paper shows a case study implemented for major instrumentation and electrical equipment activities performed in UA Spheroids plant, one of the most affected area and responsible to process the 100% of the Abqaiq Plants Oil Production rate. This paper pretends to contribute with the research and practice on business continuity management. Considering a particular approach to BCM, incorporating value-oriented engineering solutions in the developing of continuity plans; we apply model-based techniques to provide quality assurance in the elaboration process, and to automate the generation/update of a BCP. On the practical side, this study converts Operational, Maintenance, Safety and Reliability perspectives in a holistic view provided from Engineering solutions responsible to generate the guidelines for an agile, effective and realizable recovery plan.
{"title":"Value Oriented Engineering Solutions for Business Continuity","authors":"Jose Luis Delgado Rivera","doi":"10.2118/204560-ms","DOIUrl":"https://doi.org/10.2118/204560-ms","url":null,"abstract":"\u0000 This paper presents a systemic approach using Engineering and analytics methods to avail the fastest and safest responses to recovering business operations after Abqaiq Plants major disruption after the 2019 September 14th incident. This new approach using value and agile engineering, risk management methodologies combined with the business continuity model suggested was successfully applied to recover Abqaiq Plants Operations after catastrophic events occurred.\u0000 This paper pretends to serve as example about how the business continuity plan should response to a major emergency and how this planning activity could be effectively supported using a Value Oriented Engineering Solutions (VOES). This VOES approach is based on Business continuity framework and adapted for use during emergency situations to generate effective and urgent responses to recover one of the most strategical operations in the Oil and Gas Industry worldwide ahead of the last year significant disruption.\u0000 VOES approach vastly implemented during Abqaiq Plants Restoration allowed a 100% functional recovery on 9 days, 5 days in advance to the most optimistic scenario. This paper shows a case study implemented for major instrumentation and electrical equipment activities performed in UA Spheroids plant, one of the most affected area and responsible to process the 100% of the Abqaiq Plants Oil Production rate.\u0000 This paper pretends to contribute with the research and practice on business continuity management. Considering a particular approach to BCM, incorporating value-oriented engineering solutions in the developing of continuity plans; we apply model-based techniques to provide quality assurance in the elaboration process, and to automate the generation/update of a BCP. On the practical side, this study converts Operational, Maintenance, Safety and Reliability perspectives in a holistic view provided from Engineering solutions responsible to generate the guidelines for an agile, effective and realizable recovery plan.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80924621","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}
It is generally believed that Cretaceous bioclastic limestone in Mesopotamia basin in central and southern Iraq is a typical porous reservoir with weak fracture development. Therefore, previous studies on the fracture of this kind of reservoir are rare. As a common seepage channel in carbonate rock, fracture has an important influence on single well productivity and waterflooding development of carbonate reservoir. Based on seismic, core and production data, this study analyzes the development characteristics of fractures from various aspects, and discusses the influence of fractures on water injection development of reservoirs. Through special processing of seismic data, it is found that there are a lot of micro fractures in Cretaceous bioclastic limestone reservoir. Most of these micro fractures are filled fractures without conductivity under the original reservoir conditions. However, with the further development of the reservoir, the reservoir pressure, oil-water movement, water injection and other conditions have changed, resulting in the original reservoir conditions of micro fractures with conductivity. The water cut of many production wells in the high part of reservoir rises sharply. In order to describe the three-dimensional spatial distribution of fractures, the core data is used to verify the seismic fracture distribution data volume. After the verification effect is satisfied, the three-dimensional fracture data volume is transformed into the geological model to establish the permeability field including fracture characteristics. The results of numerical simulation show that water mainly flows into the reservoir through high angle micro fractures. Fractures are identified by seismic and fracture model is established to effectively recognize the influence of micro fractures on water injection development in reservoir development process, which provides important guidance for oilfield development of Cretaceous bioclastic limestone reservoir in the central and southern Iraq fields.
{"title":"Identification of Micro Fractures in Cretaceous Bioclastic Limestone in Iraq and Its Influence on Development of Reservoirs","authors":"Genjiu Wang, D. Hu, Qianyao Li","doi":"10.2118/204602-ms","DOIUrl":"https://doi.org/10.2118/204602-ms","url":null,"abstract":"\u0000 It is generally believed that Cretaceous bioclastic limestone in Mesopotamia basin in central and southern Iraq is a typical porous reservoir with weak fracture development. Therefore, previous studies on the fracture of this kind of reservoir are rare. As a common seepage channel in carbonate rock, fracture has an important influence on single well productivity and waterflooding development of carbonate reservoir.\u0000 Based on seismic, core and production data, this study analyzes the development characteristics of fractures from various aspects, and discusses the influence of fractures on water injection development of reservoirs. Through special processing of seismic data, it is found that there are a lot of micro fractures in Cretaceous bioclastic limestone reservoir. Most of these micro fractures are filled fractures without conductivity under the original reservoir conditions. However, with the further development of the reservoir, the reservoir pressure, oil-water movement, water injection and other conditions have changed, resulting in the original reservoir conditions of micro fractures with conductivity. The water cut of many production wells in the high part of reservoir rises sharply. In order to describe the three-dimensional spatial distribution of fractures, the core data is used to verify the seismic fracture distribution data volume. After the verification effect is satisfied, the three-dimensional fracture data volume is transformed into the geological model to establish the permeability field including fracture characteristics.\u0000 The results of numerical simulation show that water mainly flows into the reservoir through high angle micro fractures. Fractures are identified by seismic and fracture model is established to effectively recognize the influence of micro fractures on water injection development in reservoir development process, which provides important guidance for oilfield development of Cretaceous bioclastic limestone reservoir in the central and southern Iraq fields.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74717505","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}
Acquiring data with single sensors or small arrays in a desert environment may lead to challenging data quality for subsequent processing. We present a new approach to effectively "heal" such data and allow efficient processing and imaging without requiring any additional acquisition. A novel method combines the power of seismic beamforming and time-frequency masking originating from speech processing. First, we create an enhanced version of the data with beamforming or local stacking. Beamforming effectively suppresses scattered noise and finds weak reflection signals, albeit sacrificing some higher frequencies. Next, we employ a seismic time-frequency masking procedure to fix the original data while using beamformed data as a guide. Time-frequency masking effectively fixes corrupt and broken phase of the original data. After such data-driven healing, prestack data can be effectively processed and imaged, while maintaining the higher frequencies lost during beamforming.
{"title":"Healing Seismic Data with Phase Corrections for Processing of Single-Sensor Data in the Desert Environment","authors":"A. Bakulin, I. Silvestrov, D. Neklyudov","doi":"10.2118/204701-ms","DOIUrl":"https://doi.org/10.2118/204701-ms","url":null,"abstract":"\u0000 Acquiring data with single sensors or small arrays in a desert environment may lead to challenging data quality for subsequent processing. We present a new approach to effectively \"heal\" such data and allow efficient processing and imaging without requiring any additional acquisition. A novel method combines the power of seismic beamforming and time-frequency masking originating from speech processing. First, we create an enhanced version of the data with beamforming or local stacking. Beamforming effectively suppresses scattered noise and finds weak reflection signals, albeit sacrificing some higher frequencies. Next, we employ a seismic time-frequency masking procedure to fix the original data while using beamformed data as a guide. Time-frequency masking effectively fixes corrupt and broken phase of the original data. After such data-driven healing, prestack data can be effectively processed and imaged, while maintaining the higher frequencies lost during beamforming.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91180989","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}
Kerou Liu, Hui Zhang, Renjun Xie, Yi Wu, Jingang Jiao, Zhixiang Cai, Hao Fu
Steering drilling technology can achieve precise control of wellbore trajectory, and related technologies have been widely used in the field of petroleum drilling. This paper proposed a new steering drilling technology based on the Pulsed Arc Plasma Shockwave Technology (PAPST),Plasma Pulse Steering Technology (PPST). PAPST transforms electric energy into mechanical energy by discharging electrodes, which can break rock. On the basis of PAPST, PPST can precisely control the discharge time and break the rock in the specified direction at the bottom of the well, so as to realize guided drilling. First, the discharge mechanism and guiding mechanism of the PPST were studied separately. Then, the discharge control model of PPST was established to explain the feasibility of using this technology to achieve drilling guidance. Finally, to verify the actual effect of this technology on rock breaking, an experiment was carried out with self-developed experimental equipment. Through the study of the mechanism and discharge control model of PPST, it is considered that it is feasible to use this technology to achieve guidance in theory. The experimental results show that the sandstone samples were damaged and a large area of pits appeared after the shockwave, and the ultrasonic penetration test results showed that there was damage inside the rock. As the number of impacts increased, the rock damage became more severe and fracture occurred. Therefore, it is feasible to apply PPST to the directional fracture of bottom hole rock. In summary, this technology has very good application prospects. For the first time, this paper proposed the idea of applying PAPST to steering drilling. Through the research on the steering mechanism and the experiment, the feasibility of this technology was proved and the theoretical basis was provided for the application of this technology in the field of oil drilling.
{"title":"New Steering Technology Using Pulsed Arc Plasma Shockwave: Plasma Pulse Steering Technology","authors":"Kerou Liu, Hui Zhang, Renjun Xie, Yi Wu, Jingang Jiao, Zhixiang Cai, Hao Fu","doi":"10.2118/204868-ms","DOIUrl":"https://doi.org/10.2118/204868-ms","url":null,"abstract":"\u0000 Steering drilling technology can achieve precise control of wellbore trajectory, and related technologies have been widely used in the field of petroleum drilling. This paper proposed a new steering drilling technology based on the Pulsed Arc Plasma Shockwave Technology (PAPST),Plasma Pulse Steering Technology (PPST).\u0000 PAPST transforms electric energy into mechanical energy by discharging electrodes, which can break rock. On the basis of PAPST, PPST can precisely control the discharge time and break the rock in the specified direction at the bottom of the well, so as to realize guided drilling. First, the discharge mechanism and guiding mechanism of the PPST were studied separately. Then, the discharge control model of PPST was established to explain the feasibility of using this technology to achieve drilling guidance. Finally, to verify the actual effect of this technology on rock breaking, an experiment was carried out with self-developed experimental equipment.\u0000 Through the study of the mechanism and discharge control model of PPST, it is considered that it is feasible to use this technology to achieve guidance in theory. The experimental results show that the sandstone samples were damaged and a large area of pits appeared after the shockwave, and the ultrasonic penetration test results showed that there was damage inside the rock. As the number of impacts increased, the rock damage became more severe and fracture occurred. Therefore, it is feasible to apply PPST to the directional fracture of bottom hole rock. In summary, this technology has very good application prospects.\u0000 For the first time, this paper proposed the idea of applying PAPST to steering drilling. Through the research on the steering mechanism and the experiment, the feasibility of this technology was proved and the theoretical basis was provided for the application of this technology in the field of oil drilling.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87495819","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}
Today's oil and gas industry is a global endeavor. With technological advances in data management and transfer, the ability for experienced engineers to receive, interpret, and make decisions from all over the globe in near real-time is not only achievable, but is becoming more desirable. Provoked by downturns and reduced personnel numbers, methods of increasing efficiency and cost reduction has gradually moved engineers away from the rig site, while still undertaking the same roles and responsibilities. This paper examines one case for an operator in the Caribbean. One major client drilling in the Caribbean was forced to explore reduced staffing options on one of its deep-water drilling rigs after flight cancellations, border closures, and isolation/quarantine procedures were implemented due to the COVID-19 pandemic. This made getting experienced data engineers and sample collection personnel to the rig site impossible. Two data engineers, two mud loggers, and two sample catchers are on the rig during normal operations, but with the above-mentioned challenges, only two mud loggers remained on site. The mudlogging service provider proposed intercompany collaboration with a region experienced in remote operational support, and a remote monitoring station was set up and manned with experienced data engineers to support real-time operations. A focal point between the remote engineers and the rig team was designated, and was responsible for communicating roles and responsibilities, linking the two teams. A robust communication protocol was established between the mudlogging crew, the remote personnel, the drill floor, and the company man which outlined specifics of which events would trigger communication between parties. Two intermediate hole sections were successfully drilled, without any interruption or delay. The remote engineers successfully participated in the rigs well control drills, calling directly to the rig when needed. During drilling, the experienced remote personnel were able to provide topic specific guidance to the less experienced engineers at the rig site, which accelerated their on-the-job training. This guidance encouraged and allowed for decreased reliance on the remote support over the course of drilling. The operator considered the implementation of the remote engineers a success and looked to implement additional remote resources from other service lines and providers. Development of additional remote support opportunities directly reduces risk and cost of personnel at the rig site throughout all aspects of the oil and gas industry. Reduction of personnel on site reduces overall exposure to the hazards associated with the rig site and would decrease the probability of incident. Recent improvements in technology and communication have made it possible for this to be a viable solution to de-manning the rig site in an evolving industry.
{"title":"Implementing Remote Mudlogging Solutions to Support a Deepwater Project in the Caribbean: A De-Manning Case Study","authors":"Evan Smith","doi":"10.2118/204654-ms","DOIUrl":"https://doi.org/10.2118/204654-ms","url":null,"abstract":"\u0000 Today's oil and gas industry is a global endeavor. With technological advances in data management and transfer, the ability for experienced engineers to receive, interpret, and make decisions from all over the globe in near real-time is not only achievable, but is becoming more desirable. Provoked by downturns and reduced personnel numbers, methods of increasing efficiency and cost reduction has gradually moved engineers away from the rig site, while still undertaking the same roles and responsibilities. This paper examines one case for an operator in the Caribbean.\u0000 One major client drilling in the Caribbean was forced to explore reduced staffing options on one of its deep-water drilling rigs after flight cancellations, border closures, and isolation/quarantine procedures were implemented due to the COVID-19 pandemic. This made getting experienced data engineers and sample collection personnel to the rig site impossible. Two data engineers, two mud loggers, and two sample catchers are on the rig during normal operations, but with the above-mentioned challenges, only two mud loggers remained on site. The mudlogging service provider proposed intercompany collaboration with a region experienced in remote operational support, and a remote monitoring station was set up and manned with experienced data engineers to support real-time operations. A focal point between the remote engineers and the rig team was designated, and was responsible for communicating roles and responsibilities, linking the two teams. A robust communication protocol was established between the mudlogging crew, the remote personnel, the drill floor, and the company man which outlined specifics of which events would trigger communication between parties.\u0000 Two intermediate hole sections were successfully drilled, without any interruption or delay. The remote engineers successfully participated in the rigs well control drills, calling directly to the rig when needed. During drilling, the experienced remote personnel were able to provide topic specific guidance to the less experienced engineers at the rig site, which accelerated their on-the-job training. This guidance encouraged and allowed for decreased reliance on the remote support over the course of drilling. The operator considered the implementation of the remote engineers a success and looked to implement additional remote resources from other service lines and providers.\u0000 Development of additional remote support opportunities directly reduces risk and cost of personnel at the rig site throughout all aspects of the oil and gas industry. Reduction of personnel on site reduces overall exposure to the hazards associated with the rig site and would decrease the probability of incident. Recent improvements in technology and communication have made it possible for this to be a viable solution to de-manning the rig site in an evolving industry.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85351447","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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