Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs. Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment. Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s-1. The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17. The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.
{"title":"Screening of New HPAM Base Polymers for Applications in High Temperature and High Salinity Carbonate Reservoirs","authors":"Umar Alfazazi, W. Alameri, M. Hashmet","doi":"10.2118/192805-MS","DOIUrl":"https://doi.org/10.2118/192805-MS","url":null,"abstract":"\u0000 Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs.\u0000 Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment.\u0000 Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s-1. The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17.\u0000 The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73445459","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}
While organizations envisage flawless strategies and impeccable objectives to reach their ambitious missions, the unseen blind spot always happen to be the resources through which these objectives or initiatives have to be executed. Specifically with in the resources of people, process and technology, it is the people element that always take the back seat for the primary reason that it's an inside out process as compared to outside in. This paper aims to look at how to possibly solve this age long issue of talent engagement and what necessary easy to implement steps can be taken in order to address the issue with in organizations and thus build a workforce who are not just physically present during work but very much mentally as well. Below are a few objectives and outcomes we aim to achieve through the right implementation of engagement strategies. Once we manage to create a sense of belonging in the workforce through constructing an ecosystem where everyone feels valued, safe, and empowered; employees will manifest positive attitude in the workplace and strengthen one another thus achieving greater business results with no extra resource. often times we tend to forget that our employees are actually the face of our organization and they represent us in every single transaction we make with our stakeholders. With an engaged workforce we have more possibility of concept sharing, interaction and ideation that stems right from the lowest to the top most layers in the organizational ladder. This is to prompt the employee to make him / her feel as part of the organization which contributes directly to higher efficiency, lesser leaves and even lesser attrition rate and better visibility for attracting talented workforce. Most importantly Talent engagement is about bridging the gap between the organizational goals and that of the workforce and building a workforce with a sense of fulfillment and happiness. While organizations give immense consideration in bringing in world class technologies and implementing fool proof processes, the inevitable failure happens due to their inadequate attention to people who will drive the change. In highly challenging times where organizations are forced to consider various initiatives to sustain the show, the importance of Talent Engagement is more prevalent than ever because, the efficient use of talent and resources at large within would pretty much make or break the organization in the time to come.
{"title":"Re-Defining the Talen Engagement Experience","authors":"Bader Al Mansoori","doi":"10.2118/192721-ms","DOIUrl":"https://doi.org/10.2118/192721-ms","url":null,"abstract":"\u0000 \u0000 \u0000 While organizations envisage flawless strategies and impeccable objectives to reach their ambitious missions, the unseen blind spot always happen to be the resources through which these objectives or initiatives have to be executed. Specifically with in the resources of people, process and technology, it is the people element that always take the back seat for the primary reason that it's an inside out process as compared to outside in. This paper aims to look at how to possibly solve this age long issue of talent engagement and what necessary easy to implement steps can be taken in order to address the issue with in organizations and thus build a workforce who are not just physically present during work but very much mentally as well. Below are a few objectives and outcomes we aim to achieve through the right implementation of engagement strategies.\u0000 \u0000 \u0000 \u0000 Once we manage to create a sense of belonging in the workforce through constructing an ecosystem where everyone feels valued, safe, and empowered; employees will manifest positive attitude in the workplace and strengthen one another thus achieving greater business results with no extra resource.\u0000 \u0000 \u0000 \u0000 often times we tend to forget that our employees are actually the face of our organization and they represent us in every single transaction we make with our stakeholders.\u0000 \u0000 \u0000 \u0000 With an engaged workforce we have more possibility of concept sharing, interaction and ideation that stems right from the lowest to the top most layers in the organizational ladder.\u0000 \u0000 \u0000 \u0000 This is to prompt the employee to make him / her feel as part of the organization which contributes directly to higher efficiency, lesser leaves and even lesser attrition rate and better visibility for attracting talented workforce.\u0000 \u0000 \u0000 \u0000 Most importantly Talent engagement is about bridging the gap between the organizational goals and that of the workforce and building a workforce with a sense of fulfillment and happiness.\u0000 While organizations give immense consideration in bringing in world class technologies and implementing fool proof processes, the inevitable failure happens due to their inadequate attention to people who will drive the change. In highly challenging times where organizations are forced to consider various initiatives to sustain the show, the importance of Talent Engagement is more prevalent than ever because, the efficient use of talent and resources at large within would pretty much make or break the organization in the time to come.\u0000","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73731394","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}
O. Kindi, A. Dobroskok, S. Pande, Salha Mahruqi, T. Regan, Arlene Winchester, Basayir Lawati
In the central area of the Sultanate of Oman, gas and condensate from five different fields are processed through one gas production station which has been in operation for over 10 years. Despite the highly consolidated nature of these deep sandstone reservoirs, sand was observed in the inlet separators. This work will: Illustrate the methods used to identify the source of sand (field, well, and formation).Establish short, medium, and long term solutions. A strategy was created to investigate the source of sand and the extent of damage inflicted on the facility. Mitigation measures in the form of short to long term solutions were also implemented, addressing issues arising both in the surface and subsurface. Monitoring included clamp-on sand detectors and Sonic MPLT with camera with mitigation work including modification of the inlet separator and desander installation upstream the inlet separator Two fields were identified to be the potential source of sand, based on the clamp on sand detection campaign. One field has commingled production from three reservoirs and was later confirmed to be the true source of sand; the second field was identified to be producing frac proppant only. Different techniques were used to narrow down the sand producing reservoir by comparative study of the minerology of existing core and produced sand samples, sonic MPLT with camera, modeling of formation stress mechanics, and other means of WRM interventions. Results concluded that sand production was not limited to a single reservoir yet the deepest is the major contributer. To maintain the integrity of the facility, both surface and subsurface mitigation measures were assesed. Due to limitations in the existing well completions, surface solutions were preferred.. By evaluating the facility, it was decided to modify the design of the inlet separator to trap the sand and clean it out periodically. In addition, well flow rates were constrained to below the erosion critical velocity to avoid any loss of containment. Finally, an integrity test was conducted to the flowline and equipment (from wellhead to export line), to create a surveillance and maintenance strategy to prevent facility damage. In summary: Modern technologies including Sonic MPLT with Camera proved capable of identifying the formation responsible for sand production under the conditions of fluid clarity and flow condition (Turbulent.Deep, well consolidated sandstone reservoirs are capable of sand production due to depletion and or water production.The facility downstream was protected by means of a simple modification to the inlet separator, demonstrating a simple and unconventional solution.Sand management system usage enabled sand removal from the inlet separator water stream during production, preventing loss of production.
{"title":"Sand Containment in Deep Gas Fields","authors":"O. Kindi, A. Dobroskok, S. Pande, Salha Mahruqi, T. Regan, Arlene Winchester, Basayir Lawati","doi":"10.2118/193042-MS","DOIUrl":"https://doi.org/10.2118/193042-MS","url":null,"abstract":"\u0000 In the central area of the Sultanate of Oman, gas and condensate from five different fields are processed through one gas production station which has been in operation for over 10 years. Despite the highly consolidated nature of these deep sandstone reservoirs, sand was observed in the inlet separators. This work will: Illustrate the methods used to identify the source of sand (field, well, and formation).Establish short, medium, and long term solutions.\u0000 A strategy was created to investigate the source of sand and the extent of damage inflicted on the facility. Mitigation measures in the form of short to long term solutions were also implemented, addressing issues arising both in the surface and subsurface. Monitoring included clamp-on sand detectors and Sonic MPLT with camera with mitigation work including modification of the inlet separator and desander installation upstream the inlet separator\u0000 Two fields were identified to be the potential source of sand, based on the clamp on sand detection campaign. One field has commingled production from three reservoirs and was later confirmed to be the true source of sand; the second field was identified to be producing frac proppant only. Different techniques were used to narrow down the sand producing reservoir by comparative study of the minerology of existing core and produced sand samples, sonic MPLT with camera, modeling of formation stress mechanics, and other means of WRM interventions. Results concluded that sand production was not limited to a single reservoir yet the deepest is the major contributer.\u0000 To maintain the integrity of the facility, both surface and subsurface mitigation measures were assesed.\u0000 Due to limitations in the existing well completions, surface solutions were preferred.. By evaluating the facility, it was decided to modify the design of the inlet separator to trap the sand and clean it out periodically. In addition, well flow rates were constrained to below the erosion critical velocity to avoid any loss of containment. Finally, an integrity test was conducted to the flowline and equipment (from wellhead to export line), to create a surveillance and maintenance strategy to prevent facility damage. In summary: Modern technologies including Sonic MPLT with Camera proved capable of identifying the formation responsible for sand production under the conditions of fluid clarity and flow condition (Turbulent.Deep, well consolidated sandstone reservoirs are capable of sand production due to depletion and or water production.The facility downstream was protected by means of a simple modification to the inlet separator, demonstrating a simple and unconventional solution.Sand management system usage enabled sand removal from the inlet separator water stream during production, preventing loss of production.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74508222","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}
B. D. Ribet, Jaehong Jun, Yulee Kim, T. Trowbridge, K. Shin
Because of the complexity of properties and heterogeneities, the challenge in a carbonate reservoir is to predict the spatial distribution of the best reservoir facies. Due to the sparse distribution of wells, uncertainties exist, especially where fewer cored wells are available. The aim of this study was to employ machine learning, using the full dimensionality of 3D seismic data and well data, to predict lithofacies heterogeneities distribution in major reservoirs of the Thamama Group, for a recently developed large UAE onshore field. This technology generates a probabilistic seismic facies model derived from the 3D seismic data. An association of naive neural networks, each with a different learning strategy, is run simultaneously, to avoid biasing any of the neural network architectures. To train the neural networks, seismic data and the lithofacies at the well location extracted along the wellbore are used as labelled data. To avoid overfitting from a limited dataset, we introduce seismic data away from the borehole (soft data) so that the neural networks can "vote" on their integration to improve the final training dataset before reaching the ultimate learning stage. The application of this technique on Lower Cretaceous carbonate reservoirs shows promising results. The analysis of the probability distribution gives good insights into reservoir facies distribution uncertainty. Lithofacies are created from electrofacies by subdividing facies based on hydrocarbons. The resultant prediction was validated through comparison with observations from a new drilled well, adding confidence in the decision-making process when selecting future drilling locations. This method uncovers new potential for seismic data reliability when predicting the reservoir lithofacies away from wells, especially when referring to prestack data with any type of seismic attributes. Using this method, the major reservoir lithofacies can be precisely predicted within the field. As the probabilistic facies model is calibrated to wells, this lithofacies data can be used for both geologic modeling and volumetrics analysis. Machine learning techniques were successfully applied to generate lithofacies from electrofacies from the 3D seismic data, leading to accelerated interpretation and reservoir characterization processes. In many cases, they provided faster images of the subsurface while still maintaining accuracy, thus helping to improve the decision-making process when determining new drilling locations.
{"title":"Machine Learning Provides Higher-Quality Insights into Facies Heterogeneities over Complex Carbonate Reservoirs in a Recently Developed Abu Dhabi Oilfield, Middle East","authors":"B. D. Ribet, Jaehong Jun, Yulee Kim, T. Trowbridge, K. Shin","doi":"10.2118/192944-MS","DOIUrl":"https://doi.org/10.2118/192944-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Because of the complexity of properties and heterogeneities, the challenge in a carbonate reservoir is to predict the spatial distribution of the best reservoir facies. Due to the sparse distribution of wells, uncertainties exist, especially where fewer cored wells are available. The aim of this study was to employ machine learning, using the full dimensionality of 3D seismic data and well data, to predict lithofacies heterogeneities distribution in major reservoirs of the Thamama Group, for a recently developed large UAE onshore field.\u0000 \u0000 \u0000 \u0000 This technology generates a probabilistic seismic facies model derived from the 3D seismic data. An association of naive neural networks, each with a different learning strategy, is run simultaneously, to avoid biasing any of the neural network architectures. To train the neural networks, seismic data and the lithofacies at the well location extracted along the wellbore are used as labelled data. To avoid overfitting from a limited dataset, we introduce seismic data away from the borehole (soft data) so that the neural networks can \"vote\" on their integration to improve the final training dataset before reaching the ultimate learning stage.\u0000 \u0000 \u0000 \u0000 The application of this technique on Lower Cretaceous carbonate reservoirs shows promising results. The analysis of the probability distribution gives good insights into reservoir facies distribution uncertainty. Lithofacies are created from electrofacies by subdividing facies based on hydrocarbons. The resultant prediction was validated through comparison with observations from a new drilled well, adding confidence in the decision-making process when selecting future drilling locations. This method uncovers new potential for seismic data reliability when predicting the reservoir lithofacies away from wells, especially when referring to prestack data with any type of seismic attributes. Using this method, the major reservoir lithofacies can be precisely predicted within the field. As the probabilistic facies model is calibrated to wells, this lithofacies data can be used for both geologic modeling and volumetrics analysis.\u0000 \u0000 \u0000 \u0000 Machine learning techniques were successfully applied to generate lithofacies from electrofacies from the 3D seismic data, leading to accelerated interpretation and reservoir characterization processes. In many cases, they provided faster images of the subsurface while still maintaining accuracy, thus helping to improve the decision-making process when determining new drilling locations.\u0000","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74120902","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}
Ashim Dutta, Salman Alawadhi, R. Masoud, A. Jaiyeola, Huda Al Beshr, Velimir Radman, M. A. Hosani, M. Baslaib, B. Ateeq
This case study is of drilling extended reach 6" lateral (more than 7,000 ft) in thin multi -layered carbonate gas reservoirs with a novel approach of tapping the multiple target reservoir units in dual points starting from top reservoir unit to the base unit and placing the well back to top reservoir unit in steps. The well trajectory was planned with Top-Bottom-Top (TBT) approach, starting from top to bottom layers and steering back to the top layer in stair-step trajectory. The MWD-LWD BHA was selected to continuously monitor the porosity to avoid exiting from porous subunits – owing to the thinness of sweet spot in reservoir subunits with the range of 4 to 5 ft. only. Azimuthal Resistivity tool with LWD triple combo was used while geosteering the well to assess and map the subunit boundary as there is good resistivity contrast between porous subunits and bounding stylolite. LWD Pressure Formation Tester was used to record the current reservoir pressure in the target reservoir for the purpose of optimization of the mud weight to avoid the risk of differential sticking due to higher overbalance. The differential sticking was experienced in the previous wells due to higher mud weight and overbalance. Hence, mud weight optimization helped to drill more than 7000 ft of 6" horizontal section with a complex stair-step well trajectory design. The first 5,000 ft of horizontal section have been drilled successfully using distance to boundary Azimuthal resistivity tool in addition to density-neutron tool. While in the remaining of 2,000 ft horizontal length of drain hole, the radioactive source tool was replaced with source less BHA of azimuthal resistivity and sonic tools. The reason for replacing source tool with sourceless tool is the risk of string stuck up with radioactive source in the BHA. This may be caused by complex stair-step well trajectory, reservoir pressure uncertainty and any down hole complication. The target reservoir identified for this approach has low average permeability of less than 1 mD with limited sweep area. The target is thin stacked reservoir subunits of thickness ranging from 4 to 8ft. The Subunits porosity range is 3 to 17% and are distinctly bounded by thin non-porous stylolite. The risk of drilling with complex well trajectory was handled by constant maintenance of dogleg severity (DLS) less than 2deg/100ft. Each subunit was targeted with very gentle inclination and inter-bedded stylolites were cut with higher inclination to achieve more than 90% of reservoir contact. The project has resulted in reservoir characterization in selective areas with selective drain. Being laterally heterogeneous, the Top-bottom-top approach provides the scope of selective drain in the reservoir along the well path. A higher production performance is expected from this approach as each subunit was targeted according to their reservoir properties. This case study proves to be novel especially in tight reservoirs with limited drainage
{"title":"Multiple Drain Point Approach in Thin Multi-Layered Carbonate Gas Reservoir, A Case Study of Onshore Extended Reach Drilling in UAE","authors":"Ashim Dutta, Salman Alawadhi, R. Masoud, A. Jaiyeola, Huda Al Beshr, Velimir Radman, M. A. Hosani, M. Baslaib, B. Ateeq","doi":"10.2118/192922-MS","DOIUrl":"https://doi.org/10.2118/192922-MS","url":null,"abstract":"\u0000 This case study is of drilling extended reach 6\" lateral (more than 7,000 ft) in thin multi -layered carbonate gas reservoirs with a novel approach of tapping the multiple target reservoir units in dual points starting from top reservoir unit to the base unit and placing the well back to top reservoir unit in steps.\u0000 The well trajectory was planned with Top-Bottom-Top (TBT) approach, starting from top to bottom layers and steering back to the top layer in stair-step trajectory.\u0000 The MWD-LWD BHA was selected to continuously monitor the porosity to avoid exiting from porous subunits – owing to the thinness of sweet spot in reservoir subunits with the range of 4 to 5 ft. only. Azimuthal Resistivity tool with LWD triple combo was used while geosteering the well to assess and map the subunit boundary as there is good resistivity contrast between porous subunits and bounding stylolite. LWD Pressure Formation Tester was used to record the current reservoir pressure in the target reservoir for the purpose of optimization of the mud weight to avoid the risk of differential sticking due to higher overbalance. The differential sticking was experienced in the previous wells due to higher mud weight and overbalance. Hence, mud weight optimization helped to drill more than 7000 ft of 6\" horizontal section with a complex stair-step well trajectory design.\u0000 The first 5,000 ft of horizontal section have been drilled successfully using distance to boundary Azimuthal resistivity tool in addition to density-neutron tool. While in the remaining of 2,000 ft horizontal length of drain hole, the radioactive source tool was replaced with source less BHA of azimuthal resistivity and sonic tools. The reason for replacing source tool with sourceless tool is the risk of string stuck up with radioactive source in the BHA. This may be caused by complex stair-step well trajectory, reservoir pressure uncertainty and any down hole complication.\u0000 The target reservoir identified for this approach has low average permeability of less than 1 mD with limited sweep area. The target is thin stacked reservoir subunits of thickness ranging from 4 to 8ft. The Subunits porosity range is 3 to 17% and are distinctly bounded by thin non-porous stylolite.\u0000 The risk of drilling with complex well trajectory was handled by constant maintenance of dogleg severity (DLS) less than 2deg/100ft. Each subunit was targeted with very gentle inclination and inter-bedded stylolites were cut with higher inclination to achieve more than 90% of reservoir contact.\u0000 The project has resulted in reservoir characterization in selective areas with selective drain. Being laterally heterogeneous, the Top-bottom-top approach provides the scope of selective drain in the reservoir along the well path. A higher production performance is expected from this approach as each subunit was targeted according to their reservoir properties.\u0000 This case study proves to be novel especially in tight reservoirs with limited drainage ","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"102 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78599447","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}
Amna Yaaqob Khamis Salem Aladsani, J. Aranda, M. Ahmed, Salah Al Qallabi, I. Bankole, Mubashir Ahmed, Ashim Dutta, M. Baslaib, Omar Aljeelani, Fahad Alrumaithi, Z. Hajri, Mohamed Anwar, Adel Al Hammadi
Objective/Scope; ADNOC onshore has overcome yet another challenge in drilling longest horizontal well 10,000 ft in aggressive environment having ±30% H2S and ±10 CO2 with reservoir temperature around ±300°F. This project is part of the country strategy in meeting energy growth in sour gas wells for the coming future development. Methods, Procedure, Process; the strategy is to enhance the well productivity by minimizing the footprint and drilling long horizontal well in harsh environment by achieving maximum accessible reservoir contact. A detailed well design was generated for each zone separately that touched different aspects from the planning phase to the execution and production in safe operating manner. It required an integrated approach bringing together many different technical and operation solution to achieve the drilling of long horizontal well. The well design was reviewed at each step was agreed One the challenges to start drilling Sour Gas exploration well was penetrating multiple high temperature high pressure reservoirs with minimum geosteering to maintain smooth trajectory thru the structure of the reservoir to enhance well accessibility intervention. The objective was achieved by using rig capable to drill long horizontal well and drilling fluid which is compatible with logging tools that contains low salinity and low solids which assists in enhance the efficiency of the tools and achieving the target of drilling 10,000 ft horizontal sour gas well. The torque and drag calculation were reviewed and accordingly the drilling assemblies were selected. The well was completed with specialized material that will withstand the temperature and pressure changes during production and toxic environment having ±30% H2S and ±10 CO2. Moreover, this was also subjected to comprehensive review of HSE rules and regulations including safety and precautions while drilling. Results, Observations, conclusions; Drilling and developing sour gas well with more than ±30% H2S and ±10 CO2 is an accomplishment. ADNOC onshore has studied the opportunity of drilling long horizontal well achieving maximum reservoir contact with the minimum footprintwhich will assist in reducing the cost of the future wells. Over the past years, ADNOC onshore has developed experience in drilling long horizontal wells in sour wells keeping in mind the safety and environmental aspects. A team of professional expects and support is available to achieve the objective safely & efficiently. Novel/Additive Information; Developing sour gas wells has always been challenge due to the sour environment and accessing deeper horizon that require advance theology. Sour gas opens new marketing channels for ADNOC by maximizing the investment opportunities for the future investors and stakeholders. This will open new cost, maximizing the productivity without compromising the safety and allow drilling long horizontal wells in challenging atmosphere. The paper will describe the various issues
{"title":"Successful Drilling Longest Horizontal Sour Gas Well","authors":"Amna Yaaqob Khamis Salem Aladsani, J. Aranda, M. Ahmed, Salah Al Qallabi, I. Bankole, Mubashir Ahmed, Ashim Dutta, M. Baslaib, Omar Aljeelani, Fahad Alrumaithi, Z. Hajri, Mohamed Anwar, Adel Al Hammadi","doi":"10.2118/193017-MS","DOIUrl":"https://doi.org/10.2118/193017-MS","url":null,"abstract":"\u0000 Objective/Scope; ADNOC onshore has overcome yet another challenge in drilling longest horizontal well 10,000 ft in aggressive environment having ±30% H2S and ±10 CO2 with reservoir temperature around ±300°F. This project is part of the country strategy in meeting energy growth in sour gas wells for the coming future development.\u0000 Methods, Procedure, Process; the strategy is to enhance the well productivity by minimizing the footprint and drilling long horizontal well in harsh environment by achieving maximum accessible reservoir contact. A detailed well design was generated for each zone separately that touched different aspects from the planning phase to the execution and production in safe operating manner. It required an integrated approach bringing together many different technical and operation solution to achieve the drilling of long horizontal well. The well design was reviewed at each step was agreed\u0000 One the challenges to start drilling Sour Gas exploration well was penetrating multiple high temperature high pressure reservoirs with minimum geosteering to maintain smooth trajectory thru the structure of the reservoir to enhance well accessibility intervention. The objective was achieved by using rig capable to drill long horizontal well and drilling fluid which is compatible with logging tools that contains low salinity and low solids which assists in enhance the efficiency of the tools and achieving the target of drilling 10,000 ft horizontal sour gas well. The torque and drag calculation were reviewed and accordingly the drilling assemblies were selected. The well was completed with specialized material that will withstand the temperature and pressure changes during production and toxic environment having ±30% H2S and ±10 CO2. Moreover, this was also subjected to comprehensive review of HSE rules and regulations including safety and precautions while drilling.\u0000 Results, Observations, conclusions; Drilling and developing sour gas well with more than ±30% H2S and ±10 CO2 is an accomplishment. ADNOC onshore has studied the opportunity of drilling long horizontal well achieving maximum reservoir contact with the minimum footprintwhich will assist in reducing the cost of the future wells. Over the past years, ADNOC onshore has developed experience in drilling long horizontal wells in sour wells keeping in mind the safety and environmental aspects. A team of professional expects and support is available to achieve the objective safely & efficiently.\u0000 Novel/Additive Information; Developing sour gas wells has always been challenge due to the sour environment and accessing deeper horizon that require advance theology. Sour gas opens new marketing channels for ADNOC by maximizing the investment opportunities for the future investors and stakeholders. This will open new cost, maximizing the productivity without compromising the safety and allow drilling long horizontal wells in challenging atmosphere. The paper will describe the various issues ","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81885331","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}
I. Primasari, Geraldie Lukman Wijaya, Aen Nuril Hadi, Lusiana Chendrika, Putu Astari Merati
Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production. Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments. Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018. A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.
Handil是一个成熟的油气田，在70米范围内钻了几十口井。它自1975年开始开发，由印度尼西亚国家石油公司PT Pertamina Hulu Mahakam运营。Handil浅层油藏位于200 - 1500米的真垂直深度(TVD)之间。该油藏具有较强的含水层支撑和松散的渗透性砂岩储层，且粒度分选差，需要砾石充填完井。自2005年以来，已经完成了39口砾石充填井，占Handil油田总产量的40%。Handil砾石充填井面临产能下降的问题;一些生产测试表明，30%的已完工层在生产几年后的产能指数非常低(低于0.5 STB/D/psi)。提出了有机粘土酸(OCA)作为基质酸化技术，以溶解临界近井基质中的细粒。多年来，基质酸化一直被用于消除含硅粘土地层的地层损害或提高产能。最常用的处理液是泥浆酸，它是氢氟酸(HF)和盐酸(HCl)的混合物。在许多常规泥浆酸化处理中，在处理初期效果良好后，产量下降到与处理前相似的水平;这被认为是由于HF与硅材料在长石/粘土上反应产生的沉淀，导致更多的水合硅胶。与传统的泥浆酸不同，OCA可以使活性酸更深地渗透到地层中，并限制可能的反应产物沉淀，这将提高增产处理的有效性。通过连续油管进行了两次OCA试验处理。在第一次作业中，化学物质产生了一种乳剂，与地面设施上的液体不相容。表面破乳剂处理成功稀释了乳化液。在第二次作业中对化学成分进行了一些调整，成功地去除了乳化液。先导试验的产油量瞬时增加了900桶/天(4000桶/天)，将表皮从>100降低到5，产能提高了约80%。目前，这两口井在投产6个月后仍在生产。在这个成功的故事之后，2018年计划有超过11个OCA工作岗位来提高现有区域的生产力。最近在Handil浅井进行了基质酸化作业，重点介绍了损害验证、候选物选择、酸化学、操作限制、生产结果和未来机会。讨论了沼泽地区废酸返排、酸中和、地面设施中添加破乳剂等物流问题。在基质酸化处理之前，没有可用的岩心样品对酸进行地层响应测试。
{"title":"Rejuvenating Handil Shallow Gravel Pack Wells with Effective Matrix Stimulation using Organic Clay Acid: Challenges, Lessons Learned, Results and Way Forward for Mature Fields Abstract","authors":"I. Primasari, Geraldie Lukman Wijaya, Aen Nuril Hadi, Lusiana Chendrika, Putu Astari Merati","doi":"10.2118/193175-MS","DOIUrl":"https://doi.org/10.2118/193175-MS","url":null,"abstract":"\u0000 Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production.\u0000 Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments.\u0000 Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018.\u0000 A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80864227","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Al-Anssari, Zain-Ul-Abedin Arain, A. Barifcani, A. Keshavarz, Muhammad Ali, S. Iglauer
Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.
{"title":"Influence of Pressure and Temperature on CO2-Nanofluid Interfacial Tension: Implication for Enhanced Oil Recovery and Carbon Geosequestration","authors":"S. Al-Anssari, Zain-Ul-Abedin Arain, A. Barifcani, A. Keshavarz, Muhammad Ali, S. Iglauer","doi":"10.2118/192964-MS","DOIUrl":"https://doi.org/10.2118/192964-MS","url":null,"abstract":"\u0000 Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80989135","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. Al-Yami, Mohammed Al-Jubran, V. Wagle, Marwan Al-Mulhim
Drilling gas reservoir requires high mud density to balance the reservoir pressure. To formulate such fluids, calcium carbonate (CaCO3) was used because of its high acid solubility. However, due to the high concentration of CaCO3 required for high density drilling fluid, sticking might occur which might result in fishing and/or sidetracks operations. To minimize sticking problems, barite (BaSO4) is added with CaCO3 to reduce the amount of solids needed to formulate the drilling fluid. However, barite can cause potential damage because it does not dissolve in commonly used acids. Drilling fluids were developed at a wide range of densities using CaCl2 salt with Manganese Tetroxide (Mn3O4). No similar formulations were developed before to the best of the authors’ knowledge. The properties of small particle size (D50=1 microns), spherical shape and high specific gravity (4.9 g/cm3) of Mn3O4 make it good weighting material to reduce solids loading and settling compared to CaCO3 (2.78 g/cm3 and D50=10 microns) and BaSO4 (4.20 g/cm3 and D50=20 microns). The objective of this study is to show the lab work involved in designing water-based drilling fluids using CaCl2 / Mn3O4. The experimental work in this paper involved rheological properties, thermal stability, API and HT/HP filtration. The data generated from this study showed that Lignite and Vinyl amide/vinyl sulfonate copolymer are recommended to provide good rheological stability and filtration control for CaCl2/Mn3O4 drilling fluid. Polyanionic cellulose polymer and starch can used to formulate KCl/Mn3O4 drilling fluid with good properties at 300 °F.
{"title":"Development of a New Reservoir-Friendly Drilling Fluid for Higher Gas Production","authors":"A. Al-Yami, Mohammed Al-Jubran, V. Wagle, Marwan Al-Mulhim","doi":"10.2118/192762-MS","DOIUrl":"https://doi.org/10.2118/192762-MS","url":null,"abstract":"\u0000 Drilling gas reservoir requires high mud density to balance the reservoir pressure. To formulate such fluids, calcium carbonate (CaCO3) was used because of its high acid solubility. However, due to the high concentration of CaCO3 required for high density drilling fluid, sticking might occur which might result in fishing and/or sidetracks operations. To minimize sticking problems, barite (BaSO4) is added with CaCO3 to reduce the amount of solids needed to formulate the drilling fluid. However, barite can cause potential damage because it does not dissolve in commonly used acids.\u0000 Drilling fluids were developed at a wide range of densities using CaCl2 salt with Manganese Tetroxide (Mn3O4). No similar formulations were developed before to the best of the authors’ knowledge. The properties of small particle size (D50=1 microns), spherical shape and high specific gravity (4.9 g/cm3) of Mn3O4 make it good weighting material to reduce solids loading and settling compared to CaCO3 (2.78 g/cm3 and D50=10 microns) and BaSO4 (4.20 g/cm3 and D50=20 microns). The objective of this study is to show the lab work involved in designing water-based drilling fluids using CaCl2 / Mn3O4.\u0000 The experimental work in this paper involved rheological properties, thermal stability, API and HT/HP filtration. The data generated from this study showed that Lignite and Vinyl amide/vinyl sulfonate copolymer are recommended to provide good rheological stability and filtration control for CaCl2/Mn3O4 drilling fluid. Polyanionic cellulose polymer and starch can used to formulate KCl/Mn3O4 drilling fluid with good properties at 300 °F.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"5 1-2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85443113","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}
P. S. Omrani, Iulian Dobrovolschi, S. Belfroid, P. Kronberger, Esteban Muñoz
In this study we have investigated a fully data-driven approach (artificial neural networks) for real-time back-allocation and virtual flow metering in oil and gas production wells. The main goal of this study is to develop computationally efficient data-driven models to determine the multiphase production rates of individual phases (gas and liquid) in wells using existing measured data in fields. The developed approach was tested on simulated and field data from several gas wells. Two different type of artificial neural networks (ANNs) were tested on simulated and field data to assess the accuracy of estimations for steady-state, transients and dynamics in productions due to cyclic operation (shut-ins and restart). The results showed that ANN was capable of accurately estimate the multiphase flow rates in both simulated and field data. The accuracy of the production rates estimation depends on the type of neural networks employed, production behavior (steady-state or transients) and uncertainties in data.
{"title":"Improving the Accuracy of Virtual Flow Metering and Back-Allocation through Machine Learning","authors":"P. S. Omrani, Iulian Dobrovolschi, S. Belfroid, P. Kronberger, Esteban Muñoz","doi":"10.2118/192819-MS","DOIUrl":"https://doi.org/10.2118/192819-MS","url":null,"abstract":"\u0000 In this study we have investigated a fully data-driven approach (artificial neural networks) for real-time back-allocation and virtual flow metering in oil and gas production wells. The main goal of this study is to develop computationally efficient data-driven models to determine the multiphase production rates of individual phases (gas and liquid) in wells using existing measured data in fields. The developed approach was tested on simulated and field data from several gas wells. Two different type of artificial neural networks (ANNs) were tested on simulated and field data to assess the accuracy of estimations for steady-state, transients and dynamics in productions due to cyclic operation (shut-ins and restart). The results showed that ANN was capable of accurately estimate the multiphase flow rates in both simulated and field data. The accuracy of the production rates estimation depends on the type of neural networks employed, production behavior (steady-state or transients) and uncertainties in data.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"105 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85899775","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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