With the drop of oil reservoirs’ natural pressure, and injection of higher amounts of water, predicting energy consumption required to extract multiphase hydrocarbon product, and separate it into crude, gas, and water has become a challenging and more dynamic problem. This paper discusses a detailed technique to forecast energy demand for water injection and Gas-Oil Separation Plant (GOSP). Key elements of the method include identifying the energy, products, and feed streams, along with other parameters impacting the energy demand. The relationships among all independent and dependent variables are identified, along with the consideration of ambient conditions and equipment operating efficiencies. Machine Learning (ML) algorithms are then applied, using available industry software, to build and improve these relationships using the historical data. The best-fit forecast models, also called champion models, are selected that provide the least variance from actual data. These models can be updated, using the software, as the new data is received and variance between predicted and actual energy increases. The forecasted energy demand is converted to CO2 emissions using the conversion factors for fuel gas and power. The forecasting results and underlying process can be converted into dashboards for visualization and utilization by the users of operating plants. The method described in the paper is novel and first of a kind for predicting energy demand and CO2 emissions for a GOSP considering increases in water cut and water-injection.
{"title":"Forecasting Energy Demand and CO2 Emissions for Crude Extraction and Separation Using Machine Learning","authors":"Muhammad Abbas, Omar Naeem","doi":"10.2523/iptc-22801-ms","DOIUrl":"https://doi.org/10.2523/iptc-22801-ms","url":null,"abstract":"\u0000 With the drop of oil reservoirs’ natural pressure, and injection of higher amounts of water, predicting energy consumption required to extract multiphase hydrocarbon product, and separate it into crude, gas, and water has become a challenging and more dynamic problem. This paper discusses a detailed technique to forecast energy demand for water injection and Gas-Oil Separation Plant (GOSP). Key elements of the method include identifying the energy, products, and feed streams, along with other parameters impacting the energy demand. The relationships among all independent and dependent variables are identified, along with the consideration of ambient conditions and equipment operating efficiencies. Machine Learning (ML) algorithms are then applied, using available industry software, to build and improve these relationships using the historical data. The best-fit forecast models, also called champion models, are selected that provide the least variance from actual data. These models can be updated, using the software, as the new data is received and variance between predicted and actual energy increases. The forecasted energy demand is converted to CO2 emissions using the conversion factors for fuel gas and power. The forecasting results and underlying process can be converted into dashboards for visualization and utilization by the users of operating plants. The method described in the paper is novel and first of a kind for predicting energy demand and CO2 emissions for a GOSP considering increases in water cut and water-injection.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122637920","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}
Agnes Yin Yee Ho, Dzulkarnain B Azaman, Umar Zakir Ahmad, Han Shen Chin
The objective of this paper is to share on the application and performance monitoring of Compound Air Plasma Lightning Rejection (CPLR) system at an onshore terminal facility. Malaysia is one of the top three countries in the world with high lightning density, recorded average of 13.9 flashes per square kilometer annually. Thus, the country's oil and gas industry is indeed vulnerable to the dangerous impact of lightning, often associated with risk like fire, explosion, and release of hazardous material. During the initial stage of lightning development, the air acts as an insulator between positive and negative charges at the cloud and ground. However, when the difference between charges is too great, the insulating capacity of the air breaks down, caused rapid discharge of electricity and resulting in a lightning formation. Upon detection of potential difference between storm cloud and ground, CPLR will release plasma ion, that in theory will neutralize the positive and negative ions and eventually prevent lightning to happen. This paper will discuss on the investigation outcome of two vent fire incidents at the produced water tanks of an oil and gas receiving facility at east coast of Malaysia, in relation with the functionality of this novel active lightning protection system. Detailed comparison has been made between CPLR lightning rejection data and the data from an electricity utility research company (TNB-Research) lightning mapping to study the system's reliability and effectiveness. During the first vent fire incident in 2018, data analysis showed that there was no lightning strike within the CPLR coverage area and suspected the lightning propagated from the nearest striking point in lightning mapping following the path of least resistance. In addition, this also surfaced up several installation issues such as insufficient protection coverage due to incorrect pole height design, communication card failure etc. Identified action items have been implemented to restore the CPLR system for tank lightning protection. After that, the system has been closely monitored for its performance and it showed reliable lightning rejection data in year 2020 with no vent fire occurence. However, the second vent fire incident happened in 2021. Post investigation, TNB-R data showed that the lightning stroke 200m from the produced water tank recorded peak current value at −68kA which was two times higher than the average lightning amperage. This concluded that CPLR was unable to reject propagated lightning of high magnitude as well. In overall, CPLR system is proved to be functioning but with limitation in terms of coverage area and lightning magnitude (kA). With this paper presented, it is expected to complement this novel technology literature with its proof of function, field site installation precautions and as-found system limitations.
{"title":"Application and Performance Monitoring of Compound Air Plasma Lightning Rejection System","authors":"Agnes Yin Yee Ho, Dzulkarnain B Azaman, Umar Zakir Ahmad, Han Shen Chin","doi":"10.2523/iptc-22896-ea","DOIUrl":"https://doi.org/10.2523/iptc-22896-ea","url":null,"abstract":"\u0000 The objective of this paper is to share on the application and performance monitoring of Compound Air Plasma Lightning Rejection (CPLR) system at an onshore terminal facility. Malaysia is one of the top three countries in the world with high lightning density, recorded average of 13.9 flashes per square kilometer annually. Thus, the country's oil and gas industry is indeed vulnerable to the dangerous impact of lightning, often associated with risk like fire, explosion, and release of hazardous material. During the initial stage of lightning development, the air acts as an insulator between positive and negative charges at the cloud and ground. However, when the difference between charges is too great, the insulating capacity of the air breaks down, caused rapid discharge of electricity and resulting in a lightning formation. Upon detection of potential difference between storm cloud and ground, CPLR will release plasma ion, that in theory will neutralize the positive and negative ions and eventually prevent lightning to happen.\u0000 This paper will discuss on the investigation outcome of two vent fire incidents at the produced water tanks of an oil and gas receiving facility at east coast of Malaysia, in relation with the functionality of this novel active lightning protection system. Detailed comparison has been made between CPLR lightning rejection data and the data from an electricity utility research company (TNB-Research) lightning mapping to study the system's reliability and effectiveness.\u0000 During the first vent fire incident in 2018, data analysis showed that there was no lightning strike within the CPLR coverage area and suspected the lightning propagated from the nearest striking point in lightning mapping following the path of least resistance. In addition, this also surfaced up several installation issues such as insufficient protection coverage due to incorrect pole height design, communication card failure etc. Identified action items have been implemented to restore the CPLR system for tank lightning protection. After that, the system has been closely monitored for its performance and it showed reliable lightning rejection data in year 2020 with no vent fire occurence. However, the second vent fire incident happened in 2021. Post investigation, TNB-R data showed that the lightning stroke 200m from the produced water tank recorded peak current value at −68kA which was two times higher than the average lightning amperage. This concluded that CPLR was unable to reject propagated lightning of high magnitude as well.\u0000 In overall, CPLR system is proved to be functioning but with limitation in terms of coverage area and lightning magnitude (kA). With this paper presented, it is expected to complement this novel technology literature with its proof of function, field site installation precautions and as-found system limitations.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"127 ","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114051937","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}
Sustained casing pressure (SCP) is an industry wide challenge, and the evaluation and validation of a new cement system proactively mitigates SCP defending against numerous flow mechanisms, by delivering a barrier that minimizes fluid loss, shortens transition time, improves shear bonding, and reduces permeability. The application of this new cement system in the Denver-Julesburg Basin demonstrates its ability to mitigate and reduce the occurrence of SCP both pre and post fracturing while delivering a more efficient and sustainable solution. The innovative chemistry of the cement system enables an efficient delivery of a dry blended system, providing enhanced cement properties without the need for premium liquid additives. The system was evaluated in the laboratory to mitigate SCP caused by flow through unset cement as well as evaluated for its long-term integrity to better withstand stresses placed on the cement sheath during fracturing operations. Pre and post frac SCP are well documented and monitored across the Denver-Julesburg (D-J) basin and the new cement system was pumped on over 200 wells and has shown a reduction in both pre- and post-fracturing SCP (COGCC 2022). The SCP mitigation cement system can deliver over a 40% increase in shear bond strength, increasing the anchoring forces the cement sheath has to the casing and formation while proving to be a more crack resistant barrier. With a 75% reduction in cement permeability, it has increased resistance to flow and degradation from corrosive fluids or gases. The cement system enables operators to proactively mitigate SCP, minimize risk, and limit their carbon footprint by eliminating the need for future remediation and can be tailored and applied to other basins with similar challenges across the globe to mitigate SCP and improve long term well integrity
{"title":"Mitigating Sustained Casing Pressure in the Denver-Julesburg Basin with a Low Permeability Flow Resistant Cementing Solution","authors":"Brittany Elbel Clark, William Pearl, Dale Hopwood","doi":"10.2523/iptc-22872-ea","DOIUrl":"https://doi.org/10.2523/iptc-22872-ea","url":null,"abstract":"\u0000 Sustained casing pressure (SCP) is an industry wide challenge, and the evaluation and validation of a new cement system proactively mitigates SCP defending against numerous flow mechanisms, by delivering a barrier that minimizes fluid loss, shortens transition time, improves shear bonding, and reduces permeability. The application of this new cement system in the Denver-Julesburg Basin demonstrates its ability to mitigate and reduce the occurrence of SCP both pre and post fracturing while delivering a more efficient and sustainable solution.\u0000 The innovative chemistry of the cement system enables an efficient delivery of a dry blended system, providing enhanced cement properties without the need for premium liquid additives. The system was evaluated in the laboratory to mitigate SCP caused by flow through unset cement as well as evaluated for its long-term integrity to better withstand stresses placed on the cement sheath during fracturing operations. Pre and post frac SCP are well documented and monitored across the Denver-Julesburg (D-J) basin and the new cement system was pumped on over 200 wells and has shown a reduction in both pre- and post-fracturing SCP (COGCC 2022).\u0000 The SCP mitigation cement system can deliver over a 40% increase in shear bond strength, increasing the anchoring forces the cement sheath has to the casing and formation while proving to be a more crack resistant barrier. With a 75% reduction in cement permeability, it has increased resistance to flow and degradation from corrosive fluids or gases.\u0000 The cement system enables operators to proactively mitigate SCP, minimize risk, and limit their carbon footprint by eliminating the need for future remediation and can be tailored and applied to other basins with similar challenges across the globe to mitigate SCP and improve long term well integrity","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"66 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125526685","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}
Kittipong Limchuchua, S. Sarisittitham, Pichaya Ruthairung, J. Whangkitjamorn, Nuddanet Sikharin, Nitshakhan Jitpipatpong, P. Kritsadativud
Because tight reservoir has become important energy resources in sustaining production, PTTEP has recently evaluated a number of these reservoirs. For development plan optimization and resources estimation, 3D-modelling is the most efficient tool. However, the complicated workflow usually impedes inexperienced users to work with reservoir simulation. This study aims to construct an automatic 3D-modelling generator which could handle the tight reservoir. This would allow non-simulation expert to construct any 3D models for further simulation study. In this study, black oil simulation model is selected for simplicity. A generic multi-layer tight reservoir model is consisted of cartesian grids with the local grid refinement (LGR) at a well location to capture flow regime near a hydraulic fracture. The user interface tabs contain input spreadsheet for grid design, rock and fluid properties, initial conditions, well completion, and production schedule. Then, the script files with black oil simulator keywords will be generated. The capability to adjust all the input data is finally introduced to ensure user-friendly interface before finalizing the script files to simulation software without any complication with the simulation keywords. With the created Tight Reservoir Automatic 3D-Modelling Generator, all complicated workflows (the black oil simulator keywords and structure) are handled. The 3D modelling for tight reservoir does not require highly experienced user anymore. Also, neither high expertise in simulation nor programming is required. The generator provides user friendly interface with full capability of automatic multi-layer model construction. It also can handle any kind of fluid system (oil/gas/water and saturated/undersaturated reservoir), and the presence of a hydraulic fracture in any specific layers. In terms of the well and production control, it provides the option frequently used e.g., control BHP, control THP, control flow rate. This generator has been used in several PTTEP projects which have proven the success of the application. Currently, for the high-level field evaluation of the tight reservoir, any inexperienced user could construct the 3D model for their usage without having to request support from the simulation team. Regarding this advantage, there has been measurable manpower saving for model construction. Therefore, user could have more time to focus on engineering analysis such as sensitivity study on relevant parameters or production forecast and optimization which ultimately bring the best value for the project evaluation. Although commercial software may be available, they require costs and learning. Also, that software may not fully fit with specific objective. With in-house development of this pre-processer modeling tool, the interface is proven to be ease of use and fit-for-purpose with no additional cost. Further improvement would easily be performed. The concept of coupling the familiar user interface with
{"title":"Tight Reservoir Automatic 3D-Modelling Generator: Turning Complicated into Effortless Application","authors":"Kittipong Limchuchua, S. Sarisittitham, Pichaya Ruthairung, J. Whangkitjamorn, Nuddanet Sikharin, Nitshakhan Jitpipatpong, P. Kritsadativud","doi":"10.2523/iptc-22965-ea","DOIUrl":"https://doi.org/10.2523/iptc-22965-ea","url":null,"abstract":"\u0000 Because tight reservoir has become important energy resources in sustaining production, PTTEP has recently evaluated a number of these reservoirs. For development plan optimization and resources estimation, 3D-modelling is the most efficient tool. However, the complicated workflow usually impedes inexperienced users to work with reservoir simulation. This study aims to construct an automatic 3D-modelling generator which could handle the tight reservoir. This would allow non-simulation expert to construct any 3D models for further simulation study.\u0000 In this study, black oil simulation model is selected for simplicity. A generic multi-layer tight reservoir model is consisted of cartesian grids with the local grid refinement (LGR) at a well location to capture flow regime near a hydraulic fracture. The user interface tabs contain input spreadsheet for grid design, rock and fluid properties, initial conditions, well completion, and production schedule. Then, the script files with black oil simulator keywords will be generated. The capability to adjust all the input data is finally introduced to ensure user-friendly interface before finalizing the script files to simulation software without any complication with the simulation keywords.\u0000 With the created Tight Reservoir Automatic 3D-Modelling Generator, all complicated workflows (the black oil simulator keywords and structure) are handled. The 3D modelling for tight reservoir does not require highly experienced user anymore. Also, neither high expertise in simulation nor programming is required. The generator provides user friendly interface with full capability of automatic multi-layer model construction. It also can handle any kind of fluid system (oil/gas/water and saturated/undersaturated reservoir), and the presence of a hydraulic fracture in any specific layers. In terms of the well and production control, it provides the option frequently used e.g., control BHP, control THP, control flow rate. This generator has been used in several PTTEP projects which have proven the success of the application. Currently, for the high-level field evaluation of the tight reservoir, any inexperienced user could construct the 3D model for their usage without having to request support from the simulation team. Regarding this advantage, there has been measurable manpower saving for model construction. Therefore, user could have more time to focus on engineering analysis such as sensitivity study on relevant parameters or production forecast and optimization which ultimately bring the best value for the project evaluation.\u0000 Although commercial software may be available, they require costs and learning. Also, that software may not fully fit with specific objective. With in-house development of this pre-processer modeling tool, the interface is proven to be ease of use and fit-for-purpose with no additional cost. Further improvement would easily be performed. The concept of coupling the familiar user interface with","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"293 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117343901","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Y. Bao, Haibo Zhao, Cheng Wang, Yangyang Wang, Feng Yan, Zhiming Zhang, Shuai Guo, Xingyuan Li, Shunyu Yao
New exploration field of Shale-oil located on Songliao Basin in the northeast of China show good prospects has been found very strong anisotropy and varies greatly from location to another through laboratory measurement of drilled cores. But the thickness of high-quality target layer is less than 10m and average vertical depth is 2500m, conventional seismic migration results cannot support accurate geosteering of horizontal-wells. We adopted the result-driven integrated seismic and geological modeling concept to guide the following processing in order to eliminate the structural errors existing in the seismic processing results of Well-X1 and the trajectory calibration of horizontal wells, the fidelity velocity analysis technology based on the combined constraints of rockphysical analysis firstly, the anisotropic forward modeling results is used to obtain accurate isotropic velocity field, and then the "Well-control + Stratification + Fault-control" modeling technology is used to establish a high-precision velocity model. The depth errors of the seismic and geological model and the horizontal well trajectory are directly calibrated quantitatively in the depth domain after the PSDM (Prestack Depth Migration), and the anisotropic model is modified for iterative PSDM. Finally, the structural errors of the horizontal well trajectory and seismic profile in the correlation between the seismic results of the new method and the vertical well synthesis record increased from 79% to 91%. Then, the anisotropy model was updated by quantitative calibration with existing horizontal-well trajectory in the depth domain, so that the final VTI anisotropic PSDM results and the horizontal well construction error in the depth domain was less than 1‰. The anisotropic PSDM results provide accurate guidance for geosteering, and the posterior horizontal-well verifies the high accuracy of the method. The technology can effectively support the deployment of horizontal-well groups in new fields and the beneficial development and utilization of new types of reservoirs in Daqing oilfield, it also demonstrated that the seismic-geological integration anisotropy modeling and PSDM technology can provide reliable support for the deployment of horizontal-wells in the same type of deep, thin, anisotropic reservoirs.
{"title":"Application of Seismic-Geological Integration Anisotropy Modeling and PSDM Technology to Horizontal-Well Group Deployment in New Exploration Field","authors":"Y. Bao, Haibo Zhao, Cheng Wang, Yangyang Wang, Feng Yan, Zhiming Zhang, Shuai Guo, Xingyuan Li, Shunyu Yao","doi":"10.2523/iptc-22941-ms","DOIUrl":"https://doi.org/10.2523/iptc-22941-ms","url":null,"abstract":"\u0000 New exploration field of Shale-oil located on Songliao Basin in the northeast of China show good prospects has been found very strong anisotropy and varies greatly from location to another through laboratory measurement of drilled cores. But the thickness of high-quality target layer is less than 10m and average vertical depth is 2500m, conventional seismic migration results cannot support accurate geosteering of horizontal-wells. We adopted the result-driven integrated seismic and geological modeling concept to guide the following processing in order to eliminate the structural errors existing in the seismic processing results of Well-X1 and the trajectory calibration of horizontal wells, the fidelity velocity analysis technology based on the combined constraints of rockphysical analysis firstly, the anisotropic forward modeling results is used to obtain accurate isotropic velocity field, and then the \"Well-control + Stratification + Fault-control\" modeling technology is used to establish a high-precision velocity model. The depth errors of the seismic and geological model and the horizontal well trajectory are directly calibrated quantitatively in the depth domain after the PSDM (Prestack Depth Migration), and the anisotropic model is modified for iterative PSDM. Finally, the structural errors of the horizontal well trajectory and seismic profile in the correlation between the seismic results of the new method and the vertical well synthesis record increased from 79% to 91%. Then, the anisotropy model was updated by quantitative calibration with existing horizontal-well trajectory in the depth domain, so that the final VTI anisotropic PSDM results and the horizontal well construction error in the depth domain was less than 1‰. The anisotropic PSDM results provide accurate guidance for geosteering, and the posterior horizontal-well verifies the high accuracy of the method. The technology can effectively support the deployment of horizontal-well groups in new fields and the beneficial development and utilization of new types of reservoirs in Daqing oilfield, it also demonstrated that the seismic-geological integration anisotropy modeling and PSDM technology can provide reliable support for the deployment of horizontal-wells in the same type of deep, thin, anisotropic reservoirs.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"131 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125939408","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. Cherubini, Simon Richard, C. Jestin, G. Calbris, V. Lanticq
Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) measurements are technologies which are adding some benefits in the aim to replace or complete traditional logging measurements like noise logging tools (NLT) or production logging tools (PLT). The aim of well integrity interventions using distributed fiber optic sensing (DFOS) is to significantly reduce the duration and the cost of these operations, and to provide additional information in comparison to traditional logging tool. The combination of DAS and DTS can offer both qualitative and quantitative information regarding fluid dynamics in the context of well integrity investigation, as the flow characteristics (intensity of turbulences). In this study, we will investigate different failure patterns occurring on the well completion, as the production tubing or packers. On the first hand, we will see that the combination of DAS and DTS provides complementary information regarding leaks characterization. On the other hand, we will investigate the monitoring of temperature gradient (DTGS for Distributed Temperature Gradient Sensing) using DAS by the integration of low frequency acoustic signal (< 1 Hz).
分布式声学传感(DAS)和分布式温度传感(DTS)测量技术正在增加一些优势，旨在取代或完成传统的测井测量，如噪声测井工具(NLT)或生产测井工具(PLT)。使用分布式光纤传感(DFOS)进行井完整性干预的目的是显著缩短作业时间和成本，并提供比传统测井工具更多的信息。DAS和DTS的结合可以在井完整性调查的背景下提供关于流体动力学的定性和定量信息，如流动特性(湍流强度)。在这项研究中，我们将研究完井过程中发生的不同失效模式，如生产油管或封隔器。首先，我们将看到DAS和DTS的组合提供了关于泄漏表征的补充信息。另一方面，我们将研究利用DAS通过低频声信号(< 1 Hz)的集成来监测温度梯度(DTGS for Distributed temperature gradient Sensing)。
{"title":"Real-Time Downhole Monitoring Using DAS and DTS: A New Technology for Leak Detection and Well Integrity","authors":"A. Cherubini, Simon Richard, C. Jestin, G. Calbris, V. Lanticq","doi":"10.2523/iptc-23102-ea","DOIUrl":"https://doi.org/10.2523/iptc-23102-ea","url":null,"abstract":"\u0000 Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) measurements are technologies which are adding some benefits in the aim to replace or complete traditional logging measurements like noise logging tools (NLT) or production logging tools (PLT). The aim of well integrity interventions using distributed fiber optic sensing (DFOS) is to significantly reduce the duration and the cost of these operations, and to provide additional information in comparison to traditional logging tool. The combination of DAS and DTS can offer both qualitative and quantitative information regarding fluid dynamics in the context of well integrity investigation, as the flow characteristics (intensity of turbulences).\u0000 In this study, we will investigate different failure patterns occurring on the well completion, as the production tubing or packers. On the first hand, we will see that the combination of DAS and DTS provides complementary information regarding leaks characterization. On the other hand, we will investigate the monitoring of temperature gradient (DTGS for Distributed Temperature Gradient Sensing) using DAS by the integration of low frequency acoustic signal (< 1 Hz).","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"117 21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126408263","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}
Ahmed M. Al Haji, Makhanbet Zholaushiyev, Alibek Neldybayev
This paper summarizes the use of an interventionless flotation device when deploying casing, liner or completion strings to increase the success rate of reaching the planned target depth (TD). This can be challenging, especially in wells with extended lateral lengths (ERD) and high angled dogleg well profiles. High frictional forces can pose difficulties running different tubular configurations throughout the horizontal open-hole (OH) section to well TD. Sometimes these additional side forces and friction can prevent deployed tubular configurations from reaching target depth. Flotation devices are deployed as part of the completion configuration, whether casing or a liner, and they allow air to be trapped in a portion of the installed completion. The trapped air increases the buoyancy of the completion string, reducing the frictional forces along the wellbore in the process. Also, some drilling fluid is filled inside the casing and above the tempered-glass flotation device to provide additional forces to push the completion string to TD. At well TD, pressure is applied from surface, shattering the glass into small particles, establishing well circulation for wellbore conditioning and cementing operations. The optimal location of the flotation device is determined based on the well trajectory, casing design and fluid types. In an ERD well, the challenging wellbore geometry and extended lateral section were identified as major risks that could prevent the completion from reaching TD. The well had more than 10,000 ft of an 8-1/2″ open-hole section, and was planned to be cased off with a 5-1/2″ production casing. The completion string could not reach TD during the first run of deployment, resulting in a decision to pull out of the hole and re-run the completion string with a flotation device in the configuration. The solution deployed a tempered-glass flotation device, dramatically improving the run-in-hole effectiveness of the completion string, resulting in a successful run to TD. During the second run, the completion was installed successfully with significant reductions in side forces, buckling effects, as well as no operational issues were observed while running through the highest dogleg interval in the open hole (3.6-7.2 degree/100 ft). This installation was supported with the use of torque and drag software allowing the flotation effects to be modelled, compared against the nonfloated completion optimized based on floatation device placement location. Some of the flotation device novel features in wells with challenging high angled dogleg well profiles are: reduction in drag forces faced while running into the open hole (~30% reduction) and improvement in the relative stand-off percentage of the completion string (165% improvement), which comes from reducing side forces (lateral forces) and buckling effects faced while running into the open hole. After successful deployment, fullbore access was granted by shattering the tempered-glass
{"title":"Overcoming Challenging Openhole Conditions Using Flotation Approach","authors":"Ahmed M. Al Haji, Makhanbet Zholaushiyev, Alibek Neldybayev","doi":"10.2523/iptc-22822-ea","DOIUrl":"https://doi.org/10.2523/iptc-22822-ea","url":null,"abstract":"\u0000 This paper summarizes the use of an interventionless flotation device when deploying casing, liner or completion strings to increase the success rate of reaching the planned target depth (TD). This can be challenging, especially in wells with extended lateral lengths (ERD) and high angled dogleg well profiles. High frictional forces can pose difficulties running different tubular configurations throughout the horizontal open-hole (OH) section to well TD. Sometimes these additional side forces and friction can prevent deployed tubular configurations from reaching target depth.\u0000 Flotation devices are deployed as part of the completion configuration, whether casing or a liner, and they allow air to be trapped in a portion of the installed completion. The trapped air increases the buoyancy of the completion string, reducing the frictional forces along the wellbore in the process. Also, some drilling fluid is filled inside the casing and above the tempered-glass flotation device to provide additional forces to push the completion string to TD. At well TD, pressure is applied from surface, shattering the glass into small particles, establishing well circulation for wellbore conditioning and cementing operations. The optimal location of the flotation device is determined based on the well trajectory, casing design and fluid types.\u0000 In an ERD well, the challenging wellbore geometry and extended lateral section were identified as major risks that could prevent the completion from reaching TD. The well had more than 10,000 ft of an 8-1/2″ open-hole section, and was planned to be cased off with a 5-1/2″ production casing. The completion string could not reach TD during the first run of deployment, resulting in a decision to pull out of the hole and re-run the completion string with a flotation device in the configuration.\u0000 The solution deployed a tempered-glass flotation device, dramatically improving the run-in-hole effectiveness of the completion string, resulting in a successful run to TD. During the second run, the completion was installed successfully with significant reductions in side forces, buckling effects, as well as no operational issues were observed while running through the highest dogleg interval in the open hole (3.6-7.2 degree/100 ft).\u0000 This installation was supported with the use of torque and drag software allowing the flotation effects to be modelled, compared against the nonfloated completion optimized based on floatation device placement location.\u0000 Some of the flotation device novel features in wells with challenging high angled dogleg well profiles are: reduction in drag forces faced while running into the open hole (~30% reduction) and improvement in the relative stand-off percentage of the completion string (165% improvement), which comes from reducing side forces (lateral forces) and buckling effects faced while running into the open hole.\u0000 After successful deployment, fullbore access was granted by shattering the tempered-glass","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"299 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121487687","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 significant factor affecting the success of stimulation treatments is maximizing the stimulated reservoir volume. There is a tendency for stimulation fluids to follow the path of least resistance. This includes zones with high permeability and low stress as well as perforation clusters that have already been treated. As a result, stimulation fluids can bypass regions that could benefit the most from treatment. It may be possible to solve this problem by using particulate diverting agents which help create complex fracturing systems and increase the stimulated reservoir volume. The use of biodegradable particulate diverters in hydraulic fracturing and refracturing operations has shown promising results in numerous published lab and field studies. It was revealed that the use of these particulates could increase production, lower costs, and improve the overall well economics. However, some still question their effectiveness for many reasons including inconsistent downhole placement of particulates, especially in horizontal wells. Another issue associated with these diverters is the slow degradation rates seen in the field that cause delays in flowback from the plugged zones. In this research, biodegradable particulate diverters made from polylactide (PLA) were tested using an automated permeability plugging apparatus (APPA) under different conditions. A total of 56 APPA tests were conducted to determine the variables that influence the plugging performance of these particulates. The tested variables include diverters’ physical characteristics, diverter mass, temperature, differential pressure, and heating and pressurization duration. According to the results of this study, temperature significantly impacts the plugging performance of biodegradable particulate diverters. The ability of these diverters to deform above their glass transition temperature (Tg) results in enhanced plugging performance, while utilizing significantly lower amounts of particulates with a one-size distribution. The surface of PLA particulates softens above Tg and becomes flexible and rubbery. This deformation, in turn, can cause the particulates to fuse together and form a plug capable of sealing perforations and large fractures. Upon cooling down to room temperature, the particulates solidify again and remain fused, demonstrating their ability to remain intact during the cooler portions of hydraulic fracturing treatments. Additionally, different shapes and sizes of biodegradable particulates behave differently above Tg. Contrary to conventional diverters, the lower permeability of the diverter pack does not result in enhanced diversion efficiency for these biodegradable diverters above Tg. This difference in behavior at different temperatures helps explain the inconsistent results observed by many operators when used in hydraulic fracturing and refracturing operations where downhole temperatures vary considerably. In the field, these differences in behavior at various
{"title":"The Use of Biodegradable Particulate Diverting Agents in Hydraulic Fracturing and Refracturing: An Experimental Study","authors":"Ola M. Akrad, J. Miskimins","doi":"10.2523/iptc-23059-ms","DOIUrl":"https://doi.org/10.2523/iptc-23059-ms","url":null,"abstract":"\u0000 A significant factor affecting the success of stimulation treatments is maximizing the stimulated reservoir volume. There is a tendency for stimulation fluids to follow the path of least resistance. This includes zones with high permeability and low stress as well as perforation clusters that have already been treated. As a result, stimulation fluids can bypass regions that could benefit the most from treatment. It may be possible to solve this problem by using particulate diverting agents which help create complex fracturing systems and increase the stimulated reservoir volume. The use of biodegradable particulate diverters in hydraulic fracturing and refracturing operations has shown promising results in numerous published lab and field studies. It was revealed that the use of these particulates could increase production, lower costs, and improve the overall well economics. However, some still question their effectiveness for many reasons including inconsistent downhole placement of particulates, especially in horizontal wells. Another issue associated with these diverters is the slow degradation rates seen in the field that cause delays in flowback from the plugged zones.\u0000 In this research, biodegradable particulate diverters made from polylactide (PLA) were tested using an automated permeability plugging apparatus (APPA) under different conditions. A total of 56 APPA tests were conducted to determine the variables that influence the plugging performance of these particulates. The tested variables include diverters’ physical characteristics, diverter mass, temperature, differential pressure, and heating and pressurization duration.\u0000 According to the results of this study, temperature significantly impacts the plugging performance of biodegradable particulate diverters. The ability of these diverters to deform above their glass transition temperature (Tg) results in enhanced plugging performance, while utilizing significantly lower amounts of particulates with a one-size distribution. The surface of PLA particulates softens above Tg and becomes flexible and rubbery. This deformation, in turn, can cause the particulates to fuse together and form a plug capable of sealing perforations and large fractures. Upon cooling down to room temperature, the particulates solidify again and remain fused, demonstrating their ability to remain intact during the cooler portions of hydraulic fracturing treatments. Additionally, different shapes and sizes of biodegradable particulates behave differently above Tg. Contrary to conventional diverters, the lower permeability of the diverter pack does not result in enhanced diversion efficiency for these biodegradable diverters above Tg. This difference in behavior at different temperatures helps explain the inconsistent results observed by many operators when used in hydraulic fracturing and refracturing operations where downhole temperatures vary considerably. In the field, these differences in behavior at various","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132384078","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Greater Sirikit Oilfield (GS1) is an onshore asset located in Kamphaeng Phet, Thailand. Waterflooding accounts for over 64% of the crude output in this field. Consequently, the water cut at GS1 continue to escalate rapidly with the current level approaching 70%. To unlock additional processing capacities, the Lan Krabue Well Site L (LKU-L) Processing Facility is being upgraded with primary and secondary water treatment units to adequately manage and dispose the rising produced water volumes. The LKU-L Processing Facility upgrades include the following primary/secondary water treatment units: Desander & deoiler hydrocylones to remove solid particles and recover free-oil droplets. Dissolved Gas Flotation (DGF) package to reduce suspended solid/oil concentrations in produced water used for waterflooding. Throughout the execution, project requirements were continuously refined to value past design and operational pain-points through multiple, collaborative feedback sessions with the end-user operations team. Lessons learned from the successful pilot DGF/DAF units at GS1 were also methodically scrutinized to improve equipment design, process scheme, and operation/control philosophy ensuring the new unit consistently achieve performance specifications. The new desander and deoiler hydrocyclones at the LKU-L Processing Facility will condition the produced water stream for secondary treatment by reducing the solid and free-oil concentrations to below 200 mg/L (>95% removal for particles > 20 microns) and 100 ppm,v respectively. The DGF unit will then further decrease the total suspended solids and oil-in-water contents below 20 mg/L (>80% removal for particles > 5 microns) and 25 ppm,v respectively. Improvements in the quality of disposal water used for waterflooding will mitigate injectivity concerns in up to 72 injection wells resulting in a cost-savings of $7.2 million. Moreover, gross production entering the LKU-L facility can also be increased by 18,400 bpd (+134%) which will generate an additional 5,520 bpd of crude (+$98.4 million/year revenue). Several technical enhancements were also contrived to tackle existing operational concerns and brownfield modification challenges: Revamp existing process design and control schemes to improve the deoiler hydrocyclone performance. Unique partitioning of the desander & deoiler hydrocyclones to allow flexible turndown capacities. Revisit the retention time of the DGF unit to improve solid and oil removal efficiencies. Online weir adjustment functionality in the DGF vessel to facilitate performance optimization. Installation of sand-jetting system in an existing separator without hot work The design enhancements for the primary/secondary water treatment units at the upgraded LKU-L Processing Facility are being liberally replicated and implemented at three other similar processing facilities in GS1. Furthermore, the design improvements of the DGF unit can serve as a best-practice guideline for sim
{"title":"Rejuvenating Late Life Field Opportunitiies at the Greater Sirikit Oilfied: Effective Produced Water Management and Facility Upgrades at the Lan Krabue Well Site L Processing Facility","authors":"Pacharapol Charoensuk, Supaluck Watanapanich, Nattapong Lertrojanachusit, Saranee Nitayaphan","doi":"10.2523/iptc-22900-ms","DOIUrl":"https://doi.org/10.2523/iptc-22900-ms","url":null,"abstract":"\u0000 The Greater Sirikit Oilfield (GS1) is an onshore asset located in Kamphaeng Phet, Thailand. Waterflooding accounts for over 64% of the crude output in this field. Consequently, the water cut at GS1 continue to escalate rapidly with the current level approaching 70%. To unlock additional processing capacities, the Lan Krabue Well Site L (LKU-L) Processing Facility is being upgraded with primary and secondary water treatment units to adequately manage and dispose the rising produced water volumes.\u0000 The LKU-L Processing Facility upgrades include the following primary/secondary water treatment units:\u0000 Desander & deoiler hydrocylones to remove solid particles and recover free-oil droplets. Dissolved Gas Flotation (DGF) package to reduce suspended solid/oil concentrations in produced water used for waterflooding.\u0000 Throughout the execution, project requirements were continuously refined to value past design and operational pain-points through multiple, collaborative feedback sessions with the end-user operations team. Lessons learned from the successful pilot DGF/DAF units at GS1 were also methodically scrutinized to improve equipment design, process scheme, and operation/control philosophy ensuring the new unit consistently achieve performance specifications.\u0000 The new desander and deoiler hydrocyclones at the LKU-L Processing Facility will condition the produced water stream for secondary treatment by reducing the solid and free-oil concentrations to below 200 mg/L (>95% removal for particles > 20 microns) and 100 ppm,v respectively. The DGF unit will then further decrease the total suspended solids and oil-in-water contents below 20 mg/L (>80% removal for particles > 5 microns) and 25 ppm,v respectively. Improvements in the quality of disposal water used for waterflooding will mitigate injectivity concerns in up to 72 injection wells resulting in a cost-savings of $7.2 million. Moreover, gross production entering the LKU-L facility can also be increased by 18,400 bpd (+134%) which will generate an additional 5,520 bpd of crude (+$98.4 million/year revenue).\u0000 Several technical enhancements were also contrived to tackle existing operational concerns and brownfield modification challenges:\u0000 Revamp existing process design and control schemes to improve the deoiler hydrocyclone performance. Unique partitioning of the desander & deoiler hydrocyclones to allow flexible turndown capacities. Revisit the retention time of the DGF unit to improve solid and oil removal efficiencies. Online weir adjustment functionality in the DGF vessel to facilitate performance optimization. Installation of sand-jetting system in an existing separator without hot work\u0000 The design enhancements for the primary/secondary water treatment units at the upgraded LKU-L Processing Facility are being liberally replicated and implemented at three other similar processing facilities in GS1. Furthermore, the design improvements of the DGF unit can serve as a best-practice guideline for sim","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"81 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130736330","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}
Yang Wang, Yuedong Yao, Hao Wu, Jinyou Dai, Lian Wang, Zhongqi Mu
Low-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied. To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs. The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows: The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m3. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m3. All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production. This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.
{"title":"Cause Analyses and Countermeasures of Abnormal-Low-Production Wells in Jingbian Tight Gas Reservoir, Ordos Basin","authors":"Yang Wang, Yuedong Yao, Hao Wu, Jinyou Dai, Lian Wang, Zhongqi Mu","doi":"10.2523/iptc-22870-ms","DOIUrl":"https://doi.org/10.2523/iptc-22870-ms","url":null,"abstract":"\u0000 Low-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied.\u0000 To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs.\u0000 The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows:\u0000 The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m3. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m3.\u0000 All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production.\u0000 This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134258063","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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