DME as a water-soluble solvent for enhanced oil recovery has been introduced and some study results of DME enhanced waterflooding have recently been reported. However, DME-based EOR has not yet been implemented because of high prices of DME, the consequent need to recycle and reinject DME, and uncertain incremental oil per injected DME. This paper describes new insights into the different aspects (lab, subsurface, and economic) of DME-based EOR technology. An experimental protocol was defined to study the IFT, viscosity, and density of DME-Oil-brine mixtures as a function of T, P, and salinity, and DME compatibility with heavy components (e.g., asphaltenes), and adsorption on minerals. A compositional fractured-reservoir dynamic model that honors the PVT characteristics of DME was developed to investigate the performance of DME flood into fractured and unfractured reservoirs with light and heavy crudes. A business case as a function of DME recycling efficiencies, incremental oil, and phase implementation was discussed. The experimental results revealed that the oil viscosity 31 cP is significantly reduced to below 2 cP when mixed with DME in small volume ratios. No asphaltene precipitation (asphaltene content = 6.4 wt%) was observed when the oil was mixed with DME at increasing ratios up to 80 v/v%. Compatibility tests with formation water (total salinity 9.2 wt%) showed that DME is soluble in the formation water without any incompatibility or salting-out effect. The DME partitioning into oleic phase improves when temperature and brine-salinity increase. Imbibition tests at 5 bars and 50°C with DME-saturated formation water and limestone core plugs (permeability: 1.3–2.2 mD) increased the ultimate recovery to 70%. The simulation results indicate that DME injection into unfractured reservoirs does not improve the displacement efficiency, but it accelerates oil production because of improved injectivity up to 30%. However, DME injection into heavy-oil fractured reservoirs can improve displacement efficiency initially by enhancing imbibition rates from the matrix to the fracture system. However, this improved displacement efficiency decreases as DME injection continues because of DME breakthrough and there will be a point at which the DME displacement efficiency becomes the same as water. Nonetheless, DME significantly increases the recovery factor from heavy-oil fractured reservoirs (up to 200%). The economic results demonstrate that to have an economic DME-based EOR technology, the DME-recycling efficiency must be higher than 80%, incremental oil must be higher than 15%, and development must be a phased development plan.
{"title":"Dimethyl Ether DME Solvent Based Enhanced-Oil-Recovery Technology - A Laboratory and Subsurface Study","authors":"H. Salimi, A. Ameri, J. Nieuwerf","doi":"10.2118/200223-ms","DOIUrl":"https://doi.org/10.2118/200223-ms","url":null,"abstract":"\u0000 DME as a water-soluble solvent for enhanced oil recovery has been introduced and some study results of DME enhanced waterflooding have recently been reported. However, DME-based EOR has not yet been implemented because of high prices of DME, the consequent need to recycle and reinject DME, and uncertain incremental oil per injected DME. This paper describes new insights into the different aspects (lab, subsurface, and economic) of DME-based EOR technology.\u0000 An experimental protocol was defined to study the IFT, viscosity, and density of DME-Oil-brine mixtures as a function of T, P, and salinity, and DME compatibility with heavy components (e.g., asphaltenes), and adsorption on minerals.\u0000 A compositional fractured-reservoir dynamic model that honors the PVT characteristics of DME was developed to investigate the performance of DME flood into fractured and unfractured reservoirs with light and heavy crudes.\u0000 A business case as a function of DME recycling efficiencies, incremental oil, and phase implementation was discussed.\u0000 The experimental results revealed that the oil viscosity 31 cP is significantly reduced to below 2 cP when mixed with DME in small volume ratios. No asphaltene precipitation (asphaltene content = 6.4 wt%) was observed when the oil was mixed with DME at increasing ratios up to 80 v/v%. Compatibility tests with formation water (total salinity 9.2 wt%) showed that DME is soluble in the formation water without any incompatibility or salting-out effect. The DME partitioning into oleic phase improves when temperature and brine-salinity increase. Imbibition tests at 5 bars and 50°C with DME-saturated formation water and limestone core plugs (permeability: 1.3–2.2 mD) increased the ultimate recovery to 70%.\u0000 The simulation results indicate that DME injection into unfractured reservoirs does not improve the displacement efficiency, but it accelerates oil production because of improved injectivity up to 30%. However, DME injection into heavy-oil fractured reservoirs can improve displacement efficiency initially by enhancing imbibition rates from the matrix to the fracture system. However, this improved displacement efficiency decreases as DME injection continues because of DME breakthrough and there will be a point at which the DME displacement efficiency becomes the same as water. Nonetheless, DME significantly increases the recovery factor from heavy-oil fractured reservoirs (up to 200%).\u0000 The economic results demonstrate that to have an economic DME-based EOR technology, the DME-recycling efficiency must be higher than 80%, incremental oil must be higher than 15%, and development must be a phased development plan.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87301558","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}
Seismic modeled responses for known geological models, often using well logs, help interpret field seismic data for reservoir characterization. The seismic response of the Barik reservoir is investigated based on its properties as revealed by well logs. The porous Middle Barik manifests itself on the synthetic seismic data within the relevant bandwidth of the available seismic. In the Extended Elastic Impedance domain, chi projections of +30 and -60 appear to separate sand from shale lithology, and relatively high from low porosity in the Barik reservoir, respectively. Various models of the Barik reservoir are also built. These include ones with varying rock properties, thicknesses, and porosity. In the models with varying rock properties, the AVO signature of the Barik sand changes from class IV when the change in Vp/Vs ratio at the interface is weak, to class II or III in other cases. Effects of changes in fluid type are negligible, although a gas charged Barik sand exhibit strong AVO intercept and gradient amplitudes. The AVO behavior of the Barik sand is also dependent on its thickness. A thicker Barik sand shows class IV AVO with a strong negative intercept and positive gradient, whereas one that is half as thick displays class II AVO with a weak negative intercept and negative gradient. The porosity of the Barik sand influences its AVO behavior. The insitu and relatively low porosity Barik sand show class IV AVO with a sharply decreasing gradient for tighter Barik, whereas a higher porosity Barik sand showed a stronger gradient. Lastly, the frequency-dependent AVO signature of the Barik reservoir is investigated. The analysis revealed that the fluid signature is indistinguishable at 20 Hz but may be distinguished at 30 Hz.
{"title":"Seismic Models of the Barik Reservoir","authors":"A. Gangopadhyay, Dhananjay Kumar","doi":"10.2118/200302-ms","DOIUrl":"https://doi.org/10.2118/200302-ms","url":null,"abstract":"\u0000 Seismic modeled responses for known geological models, often using well logs, help interpret field seismic data for reservoir characterization. The seismic response of the Barik reservoir is investigated based on its properties as revealed by well logs. The porous Middle Barik manifests itself on the synthetic seismic data within the relevant bandwidth of the available seismic. In the Extended Elastic Impedance domain, chi projections of +30 and -60 appear to separate sand from shale lithology, and relatively high from low porosity in the Barik reservoir, respectively. Various models of the Barik reservoir are also built. These include ones with varying rock properties, thicknesses, and porosity. In the models with varying rock properties, the AVO signature of the Barik sand changes from class IV when the change in Vp/Vs ratio at the interface is weak, to class II or III in other cases. Effects of changes in fluid type are negligible, although a gas charged Barik sand exhibit strong AVO intercept and gradient amplitudes. The AVO behavior of the Barik sand is also dependent on its thickness. A thicker Barik sand shows class IV AVO with a strong negative intercept and positive gradient, whereas one that is half as thick displays class II AVO with a weak negative intercept and negative gradient. The porosity of the Barik sand influences its AVO behavior. The insitu and relatively low porosity Barik sand show class IV AVO with a sharply decreasing gradient for tighter Barik, whereas a higher porosity Barik sand showed a stronger gradient. Lastly, the frequency-dependent AVO signature of the Barik reservoir is investigated. The analysis revealed that the fluid signature is indistinguishable at 20 Hz but may be distinguished at 30 Hz.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82646028","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. A. Al Hinai, J. Florez, Mohamed Said Al Hinai, Khalid Hassan Al Raisi, Guru P. Budur, Anandraju Gopalappa, Ali Al Ghaithi
The ultimate goal of hydraulic stimulation in terms of business value is "production", especially in those cases where the well is approaching the economic limit, is to increase the hydrocarbon flow, improve the ultimate recovery and make it profitable. During a sing stage fracturing operation, extensive data is produced. Unfortunately, less than 10% of the data are properly preserved. Finally resides in corporate repositories. Comparable is the case of knowledge, where just in few cases, previous lessons learned are taken into consideration when designing a new job. Data Quality and human talent dedication are not the exception; data completeness levels of just 40% has been estimated. While Production Technologist and Frac Engineers during a normal Frac design, dedicate nearly much of their time on searching for data. It was identified the need for having a centralized database, and avoid the dissemination of "local" customized spreadsheets to track the fracturing activities. At the same time, there were no fracturing workflow identified, instead, multiple version depending on each well/cluster approach. Hydraulic Fracturing Project emerged as a corporate initiative to support the HF evolution, and the vision to provide the business the best tools (knowledge, standard process, data, and technical resources) to get the maximum benefit from this broadly adopted technology. The paper discusses the analytical aspects, operational workflow and administrative and quality control for properly managing the Frac data, from pre-Frac (job design) to post-Frac (job performance evaluation), embedding Frac execution, and including workflow. The data base allowed efficient management of hydraulic fracturing operations, better identification of the fracture candidates, and better design of fracturing treatment, Hence, Frac Platform will improve efficiency, performance & delivery well targets that could essentially reduce resources in data management.
{"title":"Qualitative & Quantitative Digital Frac Platform for Reservoir Stimulation Operations in Oman Fields","authors":"A. A. Al Hinai, J. Florez, Mohamed Said Al Hinai, Khalid Hassan Al Raisi, Guru P. Budur, Anandraju Gopalappa, Ali Al Ghaithi","doi":"10.2118/200065-ms","DOIUrl":"https://doi.org/10.2118/200065-ms","url":null,"abstract":"\u0000 The ultimate goal of hydraulic stimulation in terms of business value is \"production\", especially in those cases where the well is approaching the economic limit, is to increase the hydrocarbon flow, improve the ultimate recovery and make it profitable.\u0000 During a sing stage fracturing operation, extensive data is produced. Unfortunately, less than 10% of the data are properly preserved. Finally resides in corporate repositories. Comparable is the case of knowledge, where just in few cases, previous lessons learned are taken into consideration when designing a new job. Data Quality and human talent dedication are not the exception; data completeness levels of just 40% has been estimated. While Production Technologist and Frac Engineers during a normal Frac design, dedicate nearly much of their time on searching for data.\u0000 It was identified the need for having a centralized database, and avoid the dissemination of \"local\" customized spreadsheets to track the fracturing activities. At the same time, there were no fracturing workflow identified, instead, multiple version depending on each well/cluster approach. Hydraulic Fracturing Project emerged as a corporate initiative to support the HF evolution, and the vision to provide the business the best tools (knowledge, standard process, data, and technical resources) to get the maximum benefit from this broadly adopted technology.\u0000 The paper discusses the analytical aspects, operational workflow and administrative and quality control for properly managing the Frac data, from pre-Frac (job design) to post-Frac (job performance evaluation), embedding Frac execution, and including workflow. The data base allowed efficient management of hydraulic fracturing operations, better identification of the fracture candidates, and better design of fracturing treatment, Hence, Frac Platform will improve efficiency, performance & delivery well targets that could essentially reduce resources in data management.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82847505","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. Alali, H. Aljamaan, Mahbub S. Ahmed, Hanan Alomani
Subsurface gas storage is a strategic tool used to balance seasonal sales gas supply and demand fluctuations. Developing and managing gas storage reservoirs requires the application of standard reservoir engineering tools and practices; however, a number of additional challenges are specific to Underground Gas Storage (UGS). This paper addresses these challenges and present both modelling, design, and operational solutions. There are important considerations and challenges that can be associated with areas such as reservoir selection, surface-subsurface modelling, and optimum number of wells with the best design in gas storage reservoirs. Nevertheless, operational challenges can also be very critical and lead to jeopardizing the success of the project, if not mitigated properly. Due to the cyclic nature of gas storage during injection and re-production, cyclic stress effects can be a concern and should be studied via appropriate geomechanical models and laboratory tests (Thick-Walled-Cylinder) to address any imapct on wellbore stability and potential sand/solid production. Although mature gas reservoirs are good candidates for underground gas storage, drilling any new wells can be challenging and has to be addressed using state of the art technologies such as managed-pressure-drilling (MPD) or under-balance-coiled-tubing drilling (UBCTD). The well completion in terms of material selection and design will also impact the workover frequency and productivity/injectivity of the gas storage wells. As such, accurate evaluation of flow assurance and completion accessories are essential to ensure long term suitability of the gas storage wells. Last but not least, due to the lean nature of the gas in these developments, the risk of hydrates formation is very likely and should be analyzed and mitigated with the right engineering tools. This work presents the basic theory and applications of the above-mentioned methods and evaluations with the ultimate goal of proposing general guidelines for the development of UGS. The results and interpretations of geomechanical modelling and laboratory testing are presented as well as the drilling design and its challenges. Well integrity and erosional velocity assessment are discussed as part of the flow assurance as well as hydrates formation envelopes and its prediction methods. Gas storage projects are strategic for gas operating companies and require careful planning and economic feasibility evaluation. The challenges and lessons learnt, discussed in this paper, are required to guarantee the success of such initiative.
{"title":"Overcoming Challenges in the Development of Underground Gas Storage","authors":"A. Alali, H. Aljamaan, Mahbub S. Ahmed, Hanan Alomani","doi":"10.2118/200300-ms","DOIUrl":"https://doi.org/10.2118/200300-ms","url":null,"abstract":"\u0000 Subsurface gas storage is a strategic tool used to balance seasonal sales gas supply and demand fluctuations. Developing and managing gas storage reservoirs requires the application of standard reservoir engineering tools and practices; however, a number of additional challenges are specific to Underground Gas Storage (UGS). This paper addresses these challenges and present both modelling, design, and operational solutions. There are important considerations and challenges that can be associated with areas such as reservoir selection, surface-subsurface modelling, and optimum number of wells with the best design in gas storage reservoirs. Nevertheless, operational challenges can also be very critical and lead to jeopardizing the success of the project, if not mitigated properly. Due to the cyclic nature of gas storage during injection and re-production, cyclic stress effects can be a concern and should be studied via appropriate geomechanical models and laboratory tests (Thick-Walled-Cylinder) to address any imapct on wellbore stability and potential sand/solid production. Although mature gas reservoirs are good candidates for underground gas storage, drilling any new wells can be challenging and has to be addressed using state of the art technologies such as managed-pressure-drilling (MPD) or under-balance-coiled-tubing drilling (UBCTD). The well completion in terms of material selection and design will also impact the workover frequency and productivity/injectivity of the gas storage wells. As such, accurate evaluation of flow assurance and completion accessories are essential to ensure long term suitability of the gas storage wells. Last but not least, due to the lean nature of the gas in these developments, the risk of hydrates formation is very likely and should be analyzed and mitigated with the right engineering tools. This work presents the basic theory and applications of the above-mentioned methods and evaluations with the ultimate goal of proposing general guidelines for the development of UGS. The results and interpretations of geomechanical modelling and laboratory testing are presented as well as the drilling design and its challenges. Well integrity and erosional velocity assessment are discussed as part of the flow assurance as well as hydrates formation envelopes and its prediction methods. Gas storage projects are strategic for gas operating companies and require careful planning and economic feasibility evaluation. The challenges and lessons learnt, discussed in this paper, are required to guarantee the success of such initiative.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82879256","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}
Shubham Mishra, Garud Sridhar, Muhammad Ibrahim, Akshay Aggarwal, V. Reddy, B. Saikia, D. Rao
Whereas the application of EOR methods is estimated to recover nearly 6 out of the 9 trillion barrels initially in-place globally, there is a high chance of failure of an EOR project due to lack of characterization, operational challenges, misplaced concept, etc. It is extremely challenging to reduce these uncertainties and hence the success of an EOR project is a big question, except for the case in which the method is relatively immune to such uncertainties. The gas-assisted gravity drainage (GAGD) technique is an excellent example of such a method where the recovery is enhanced by concepts of gravity and fluids' density differences and thus relatively safer from execution failures. It has been proposed as a viable alternative to, and improvement over, conventional gas injection techniques such as water-alternating-gas (WAG) and continuous gas injection (CGI), because of its higher chance of success. The success of GAGD hinges very strongly on the interplay between in-situ reservoir properties (rock and fluid parameters) and the range of operating parameters imposed. In the primary GAGD configuration, gas is injected in the crest, and oil is withdrawn (produced) via a horizontal well at the bottom of the structure. In this study, a simplified black-oil numerical simulation framework has been developed to assess the viability of the GAGD process in candidate reservoirs with focus around lower permeability reservoirs coupled with hydraulically fractured rocks. Incremental production over natural depletion and hydraulic fractured cases have been used as the assessment criterion.
{"title":"Parametric Investigation of the Gas-Assisted Gravity Drainage Technique","authors":"Shubham Mishra, Garud Sridhar, Muhammad Ibrahim, Akshay Aggarwal, V. Reddy, B. Saikia, D. Rao","doi":"10.2118/200197-ms","DOIUrl":"https://doi.org/10.2118/200197-ms","url":null,"abstract":"\u0000 Whereas the application of EOR methods is estimated to recover nearly 6 out of the 9 trillion barrels initially in-place globally, there is a high chance of failure of an EOR project due to lack of characterization, operational challenges, misplaced concept, etc. It is extremely challenging to reduce these uncertainties and hence the success of an EOR project is a big question, except for the case in which the method is relatively immune to such uncertainties. The gas-assisted gravity drainage (GAGD) technique is an excellent example of such a method where the recovery is enhanced by concepts of gravity and fluids' density differences and thus relatively safer from execution failures. It has been proposed as a viable alternative to, and improvement over, conventional gas injection techniques such as water-alternating-gas (WAG) and continuous gas injection (CGI), because of its higher chance of success.\u0000 The success of GAGD hinges very strongly on the interplay between in-situ reservoir properties (rock and fluid parameters) and the range of operating parameters imposed. In the primary GAGD configuration, gas is injected in the crest, and oil is withdrawn (produced) via a horizontal well at the bottom of the structure. In this study, a simplified black-oil numerical simulation framework has been developed to assess the viability of the GAGD process in candidate reservoirs with focus around lower permeability reservoirs coupled with hydraulically fractured rocks. Incremental production over natural depletion and hydraulic fractured cases have been used as the assessment criterion.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76683688","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}
Morteza Roostaei, M. Mohammadtabar, S. A. Hosseini, A. Velayati, M. Soroush, Mahdi Mahmoudi, Nolan Porttin, Farshad Mohammadtabar, H. Izadi, Ahmad Alkouh, Vahidoddin Fattahpour
Productivity of cased and perforated wellbores completed with standalone screen depends on the interactions of parameters such as perforation diameter, length, phasing and density, the gap between the casing and the standalone screen, and standalone screen aperture/pore size. Moreover, the permeability of the sand in the gap plays a major role in the overall productivity. This study aims at providing a numerical estimation of pressure drop for such completions. This study uses Computational Fluid Dynamics (CFD) in order to simulate the flow around a wellbore equipped with cased and perforated completion with standalone screen. Slotted liner was used as the standalone screen in this study. Details of such a complex completion were imported into the Finite Volume (FV) based numerical simulation via Computer-Aided Design (CAD). In addition to the geometrical design of the completion, different scenarios for the perforation stability, which affect the permeability of the perforation tunnel and result in potential fill-up of the annular gap between the slotted liner and perforations, were investigated. A large number of simulations (over 200 models) were completed to cover the different scenarios for perforation design and strategy along with different Open to Flow Area (OFA) values for the standalone slotted liner. Based on the results, completion efficiency is strongly changed by perforation and gap flow properties. The OFA for the standalone slotted liner completion has minor influence on the overall pressure drop if the gap between the casing and the standalone screen and the perforation is clean, unless the perforations are collapsed and the annular gap between the casing and slotted liner is filled up with sand. This is mainly because perforation parameters, such as penetration and diameter dominate the effect of all the other parameters, including slotted liner configuration. The results emphasize the effect of the completion geometry, perforation strategy, and opening size on the skin and productivity. Another main observation was the need to better understand the stability of the perforations and sanding potential from perforations, which dictate the permeability of the perforation and annular space. The results of this study highlight the comparative importance of different standalone screen designs and perforation parameters on well productivity. This study is the basis for optimizing the sand control and perforation strategy as an alternative to other completion types such as gravel packing in cased and perforated completions in vertical and slant wells.
{"title":"Standalone Screen Design and Evaluation for Cased and Perforated Application in Unconsolidated Formations: The Role of Perforation Strategy and Sand Control Design on Well Productivity","authors":"Morteza Roostaei, M. Mohammadtabar, S. A. Hosseini, A. Velayati, M. Soroush, Mahdi Mahmoudi, Nolan Porttin, Farshad Mohammadtabar, H. Izadi, Ahmad Alkouh, Vahidoddin Fattahpour","doi":"10.2118/200270-ms","DOIUrl":"https://doi.org/10.2118/200270-ms","url":null,"abstract":"\u0000 Productivity of cased and perforated wellbores completed with standalone screen depends on the interactions of parameters such as perforation diameter, length, phasing and density, the gap between the casing and the standalone screen, and standalone screen aperture/pore size. Moreover, the permeability of the sand in the gap plays a major role in the overall productivity. This study aims at providing a numerical estimation of pressure drop for such completions.\u0000 This study uses Computational Fluid Dynamics (CFD) in order to simulate the flow around a wellbore equipped with cased and perforated completion with standalone screen. Slotted liner was used as the standalone screen in this study. Details of such a complex completion were imported into the Finite Volume (FV) based numerical simulation via Computer-Aided Design (CAD). In addition to the geometrical design of the completion, different scenarios for the perforation stability, which affect the permeability of the perforation tunnel and result in potential fill-up of the annular gap between the slotted liner and perforations, were investigated.\u0000 A large number of simulations (over 200 models) were completed to cover the different scenarios for perforation design and strategy along with different Open to Flow Area (OFA) values for the standalone slotted liner. Based on the results, completion efficiency is strongly changed by perforation and gap flow properties. The OFA for the standalone slotted liner completion has minor influence on the overall pressure drop if the gap between the casing and the standalone screen and the perforation is clean, unless the perforations are collapsed and the annular gap between the casing and slotted liner is filled up with sand. This is mainly because perforation parameters, such as penetration and diameter dominate the effect of all the other parameters, including slotted liner configuration. The results emphasize the effect of the completion geometry, perforation strategy, and opening size on the skin and productivity. Another main observation was the need to better understand the stability of the perforations and sanding potential from perforations, which dictate the permeability of the perforation and annular space.\u0000 The results of this study highlight the comparative importance of different standalone screen designs and perforation parameters on well productivity. This study is the basis for optimizing the sand control and perforation strategy as an alternative to other completion types such as gravel packing in cased and perforated completions in vertical and slant wells.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83611996","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}
In this age, there are many technology companies that specialize in big data analytics, making every piece of data useful to the end user. At BP, we have strived to build and utilize tools that enable us to work meaningfully with our data – to proactively eliminate defects across reservoir and well chokes, to track our well vulnerabilities, and flag well performance issues easily – so we can transform this data into value-adding actions. A suite of tools had to be built to meet our objectives. The first tool, called the Production Management Tool (PMT), utilizes automation and machine learning capability to estimate live reservoir pressure and productivity index in real-time, generate short-term production profiles for every well using a decline curve analysis concept, flag opportunity and risk using a wells heat map, and optimize well decline using one platform. The approach to estimate live reservoir pressure in a tight gas field, without utilizing a reservoir model, is unprecedented. It allows for a live estimation, without any waiting time which is the case with traditional methods. Similarly, decline curve analysis on a high gas capacity wells which are choked back is difficult and questionable, as there is no decline detected. Through PMT, a decline curve analysis concept is possible by modelling declines on a well's capacity rather than its actual rate. These innovative approaches rely on industry known methods that have been repurposed and transformed to incorporate the latest data science concepts. Next, a Hidden Defects Tool was constructed, which proactively drives defect elimination across the reservoir and well chokes by quantifying unproduced gas rate and condensate deferrals and assigning those deferrals to defect categories. This tool also supports the user in initiating remediation plans by describing the production risk in an interactive visual dashboard. Finally, a vulnerability matrix was constructed to link our hidden defects conclusion and well performance metrics to understand the biggest production threats by visualizing the risk severity based on well groupings, or overall risk value. All these tools highlight the importance of remaining current with the latest technology, as it can provide huge potential to advance technical capabilities and maximize business value.
{"title":"Agility in BP Oman – Doing More with Less","authors":"Ghaida Al Farsi, Angeni Jayawickramarajah","doi":"10.2118/200296-ms","DOIUrl":"https://doi.org/10.2118/200296-ms","url":null,"abstract":"\u0000 In this age, there are many technology companies that specialize in big data analytics, making every piece of data useful to the end user. At BP, we have strived to build and utilize tools that enable us to work meaningfully with our data – to proactively eliminate defects across reservoir and well chokes, to track our well vulnerabilities, and flag well performance issues easily – so we can transform this data into value-adding actions.\u0000 A suite of tools had to be built to meet our objectives. The first tool, called the Production Management Tool (PMT), utilizes automation and machine learning capability to estimate live reservoir pressure and productivity index in real-time, generate short-term production profiles for every well using a decline curve analysis concept, flag opportunity and risk using a wells heat map, and optimize well decline using one platform. The approach to estimate live reservoir pressure in a tight gas field, without utilizing a reservoir model, is unprecedented. It allows for a live estimation, without any waiting time which is the case with traditional methods. Similarly, decline curve analysis on a high gas capacity wells which are choked back is difficult and questionable, as there is no decline detected. Through PMT, a decline curve analysis concept is possible by modelling declines on a well's capacity rather than its actual rate. These innovative approaches rely on industry known methods that have been repurposed and transformed to incorporate the latest data science concepts.\u0000 Next, a Hidden Defects Tool was constructed, which proactively drives defect elimination across the reservoir and well chokes by quantifying unproduced gas rate and condensate deferrals and assigning those deferrals to defect categories. This tool also supports the user in initiating remediation plans by describing the production risk in an interactive visual dashboard. Finally, a vulnerability matrix was constructed to link our hidden defects conclusion and well performance metrics to understand the biggest production threats by visualizing the risk severity based on well groupings, or overall risk value.\u0000 All these tools highlight the importance of remaining current with the latest technology, as it can provide huge potential to advance technical capabilities and maximize business value.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90466832","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}
Yaqoob Abri, S. Choudhury, Mohamood Harthi, A. Anbari, Ali Lawati, Suhaib Ghatrifi, A. Sabahi, Iman Mahrooqi, B. Marpaung, H. Busaidi, Khalfan Harthy
Waterflood response in a brownfield with complex reservoir dynamics have significantly delayed the expected water injection response in Field ‘A’. The field is one of the highest oil producers in Oman South, spead over ~37 Km2, with more than 400 active wells, contributing > 90,000 BoE/d over the last 3 decades. The field is producing under strong bottom aquifer water drive and improved oil recovery waterflood. Current field development is focused in drilling horizontal in-fill wells and maximize recovery through well reservoir and facility management (WRFM). Production is from a combination of Mahwis aeolian and Al Khlata glacial reservoir formations. Sub-surface challenges are to arrest pressure decline, enhance sweep efficiency, ramp-up water injection (target > 440,000 BoE/d), and source additional water and manage complex operations. The produced water from oil producing wells post treatment gets re-injected into the aquifer ~100m below oil water contact (‘Deep Injection’) with 38 vertical injectors. This ‘Deep Injection’ albeit have prolonged water breakthrough has yet not delivered the optimum oil drive efficiency. One of the key subsurface challenge is the unfavorable mobility contrast between the oil and water causing early water breakthrough. Field wide variable mobility contrast, presence of intra reservoir baffles and enlarged size of the aquifer compared the legacy model assumptions triggered a transformation of the improved recovery strategy of the field – both short term and longer term. More effective injection strategy through ‘Field Trials’ have now been deployed (viz. ‘Water Re-Distribution’, ‘Make-up Water Diversion’ and ‘Shallow Injection’) over the last two years. Initial response from these trials shows encouraging results in terms of pressure support and sweep efficiency. Learning from the trails are incorporated in the future development and asset management strategy. This paper highlights the ‘Field Trials’ – practical approaches implemented to manage and optimize the field performamance. In a cost competitive low oil price time the team focused in enhancing efficient and impactful trials which yields short-term production gains keeping in mind the longer term persepective.
{"title":"Brownfield Waterflood Management - Strategic Implementation of Field Trial Learning, South Oman","authors":"Yaqoob Abri, S. Choudhury, Mohamood Harthi, A. Anbari, Ali Lawati, Suhaib Ghatrifi, A. Sabahi, Iman Mahrooqi, B. Marpaung, H. Busaidi, Khalfan Harthy","doi":"10.2118/200059-ms","DOIUrl":"https://doi.org/10.2118/200059-ms","url":null,"abstract":"\u0000 Waterflood response in a brownfield with complex reservoir dynamics have significantly delayed the expected water injection response in Field ‘A’. The field is one of the highest oil producers in Oman South, spead over ~37 Km2, with more than 400 active wells, contributing > 90,000 BoE/d over the last 3 decades. The field is producing under strong bottom aquifer water drive and improved oil recovery waterflood. Current field development is focused in drilling horizontal in-fill wells and maximize recovery through well reservoir and facility management (WRFM). Production is from a combination of Mahwis aeolian and Al Khlata glacial reservoir formations. Sub-surface challenges are to arrest pressure decline, enhance sweep efficiency, ramp-up water injection (target > 440,000 BoE/d), and source additional water and manage complex operations. The produced water from oil producing wells post treatment gets re-injected into the aquifer ~100m below oil water contact (‘Deep Injection’) with 38 vertical injectors. This ‘Deep Injection’ albeit have prolonged water breakthrough has yet not delivered the optimum oil drive efficiency. One of the key subsurface challenge is the unfavorable mobility contrast between the oil and water causing early water breakthrough. Field wide variable mobility contrast, presence of intra reservoir baffles and enlarged size of the aquifer compared the legacy model assumptions triggered a transformation of the improved recovery strategy of the field – both short term and longer term. More effective injection strategy through ‘Field Trials’ have now been deployed (viz. ‘Water Re-Distribution’, ‘Make-up Water Diversion’ and ‘Shallow Injection’) over the last two years. Initial response from these trials shows encouraging results in terms of pressure support and sweep efficiency. Learning from the trails are incorporated in the future development and asset management strategy.\u0000 This paper highlights the ‘Field Trials’ – practical approaches implemented to manage and optimize the field performamance. In a cost competitive low oil price time the team focused in enhancing efficient and impactful trials which yields short-term production gains keeping in mind the longer term persepective.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73733724","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Gassert, T. Castellitto, Gianvito Inzerillo, G. Citi, Lorenzo Dell'Orto
The paper intends to review the most recent offshore oil & gas field developments where production hubs have been introduced and technical solutions are being developed in order to produce all reservoirs of a same block or area towards a central hub facility. Different success stories among the most recent developments will be analyzed in the paper both for oil developments and gas developments: particular attention to the design basis, design envelopes and expected flexibilities will be highlighted, planning for future tiebacks will be discussed and their design and features will be addressed. The paper will touch process, safety and plant design aspects for a central processing floater or plant as well as subsea and wellhead platform tiebacks to the Hub. At the present time and with the today qualified technologies, as far as oil developments are concerned, it is deemed possible to develop from a central hub an area exceeding 100 km of radius even in deepwater and probably more in conventional waters. As far as gas developments are concerned and with the adequate design provisions and technics it is probably possible to develop from a central hub a complete basin covering distances above 250-300 km and boosting production up to distant midstream facilities. Combined oil and gas offshore hubs in areas where both oil and gas assets are to be developed demonstrate to be very interesting and efficient ways of developing an extended area through efficient synergies in tie backs and processing facilities. Please explain how this paper will present novel (new) or additive information to the existing body of literature: The paper is based on real case studies and both: extensive work ongoing intended to further utilize the recently developed hubs as well as extensive design activities for the upcoming greenfield developments.
{"title":"Offshore Oil & Gas Upstream Production Hubs, a Way to Success in Fields Development","authors":"M. Gassert, T. Castellitto, Gianvito Inzerillo, G. Citi, Lorenzo Dell'Orto","doi":"10.2118/200191-ms","DOIUrl":"https://doi.org/10.2118/200191-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The paper intends to review the most recent offshore oil & gas field developments where production hubs have been introduced and technical solutions are being developed in order to produce all reservoirs of a same block or area towards a central hub facility.\u0000 \u0000 \u0000 \u0000 Different success stories among the most recent developments will be analyzed in the paper both for oil developments and gas developments: particular attention to the design basis, design envelopes and expected flexibilities will be highlighted, planning for future tiebacks will be discussed and their design and features will be addressed. The paper will touch process, safety and plant design aspects for a central processing floater or plant as well as subsea and wellhead platform tiebacks to the Hub.\u0000 \u0000 \u0000 \u0000 At the present time and with the today qualified technologies, as far as oil developments are concerned, it is deemed possible to develop from a central hub an area exceeding 100 km of radius even in deepwater and probably more in conventional waters.\u0000 As far as gas developments are concerned and with the adequate design provisions and technics it is probably possible to develop from a central hub a complete basin covering distances above 250-300 km and boosting production up to distant midstream facilities.\u0000 Combined oil and gas offshore hubs in areas where both oil and gas assets are to be developed demonstrate to be very interesting and efficient ways of developing an extended area through efficient synergies in tie backs and processing facilities.\u0000 Please explain how this paper will present novel (new) or additive information to the existing body of literature:\u0000 The paper is based on real case studies and both: extensive work ongoing intended to further utilize the recently developed hubs as well as extensive design activities for the upcoming greenfield developments.\u0000","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87121875","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}
Dakhil Al-Enezi, Talal Al-Wehaidah, B. Goswami, Mohammed Al-Salamin, A. Salaheldin, Feraz Hosein, Manuel Centeno, Alexander Dundin, Ebrahim Albinali, Rodrigo Gallo, Ayomarz Jokhi, Anant Carasco, Rashad Mohiey
A new cutting element technology bit along with new drilling automation software provides a solution to drill the challenging 12 ¼" section in two fields in Northern Kuwait. The 12 ¼" section was drilled using directional BHA building the angle between 25 to 30 degrees. The formations are characterized to be interbedded limestone and reactive shale causing high downhole vibrations, high torque and stick and slip which affects the buildup capability of the directional tool and overall performance in this section. The main objective is to improve drilling performance by developing an integrated solution to eliminate the downhole tool failures and increase the rate of penetration. The engineering team incorporated a unique geometry into the bit cutting elements design and developed the Ridged Diamond Element (RDE) bit which has new cutting element technology and different geometry than the standard PDC cutters. The ridge shape cutter face helps to reduce the reactive torque generated through the cutter face. The ridge shape cutter face also helps in improving rate of penetration (ROP) by efficient rock removal. With regards to the drilling automation software, the objective is to determine (through the analysis of surface data) the best drilling parameters of RPM/WOB to achieve the maximum ROP for each formation while at the same time detecting and mitigating drilling dysfunctions such as shocks, vibrations and stick slip. The system was operated in advice mode as it will be explained more in detailed throughout the paper. Torque reduction system technology was used to reduce the surface torque variation and reduce the stick and slip by instantaneously altering surface string rotation (RPM). The new cutting element technology in combination with the drilling automation software provide an integrated solution to the challenges faced in the drilling operations for this 12-1/4" hole section. On the first test well, RDE bit and the drilling automation software were used with a motorized rotary steerable system (RSS), to drill 1,060 feet in 15.27 on-bottom hours with an effective ROP of 69.4 feet/hour. The second test well was in a different field, drilling 1,265 feet in 25.22 on-bottom hours achieving ROP of 50.16 feet/hour. Both test runs set new benchmark performance in comparison to the respective field offset wells. This high performance seen in both test runs were enabled by increase in ROP & the significant reduction of downhole vibrations and stick and slip brought by combining the new technologies in bit and drilling automation software. The first-time application of the new technologies helped the operator to solve drilling challenges, increasing performance and reducing the cost per foot by 20%.
{"title":"First Time Application of Bit with Unique-Geometry Cutting Element and Step Change Drilling Automation Software & Torque Reduction System Set New Performance Benchmarks in Northern Kuwait Fields","authors":"Dakhil Al-Enezi, Talal Al-Wehaidah, B. Goswami, Mohammed Al-Salamin, A. Salaheldin, Feraz Hosein, Manuel Centeno, Alexander Dundin, Ebrahim Albinali, Rodrigo Gallo, Ayomarz Jokhi, Anant Carasco, Rashad Mohiey","doi":"10.2118/200235-ms","DOIUrl":"https://doi.org/10.2118/200235-ms","url":null,"abstract":"\u0000 A new cutting element technology bit along with new drilling automation software provides a solution to drill the challenging 12 ¼\" section in two fields in Northern Kuwait. The 12 ¼\" section was drilled using directional BHA building the angle between 25 to 30 degrees. The formations are characterized to be interbedded limestone and reactive shale causing high downhole vibrations, high torque and stick and slip which affects the buildup capability of the directional tool and overall performance in this section. The main objective is to improve drilling performance by developing an integrated solution to eliminate the downhole tool failures and increase the rate of penetration.\u0000 The engineering team incorporated a unique geometry into the bit cutting elements design and developed the Ridged Diamond Element (RDE) bit which has new cutting element technology and different geometry than the standard PDC cutters. The ridge shape cutter face helps to reduce the reactive torque generated through the cutter face. The ridge shape cutter face also helps in improving rate of penetration (ROP) by efficient rock removal. With regards to the drilling automation software, the objective is to determine (through the analysis of surface data) the best drilling parameters of RPM/WOB to achieve the maximum ROP for each formation while at the same time detecting and mitigating drilling dysfunctions such as shocks, vibrations and stick slip. The system was operated in advice mode as it will be explained more in detailed throughout the paper. Torque reduction system technology was used to reduce the surface torque variation and reduce the stick and slip by instantaneously altering surface string rotation (RPM). The new cutting element technology in combination with the drilling automation software provide an integrated solution to the challenges faced in the drilling operations for this 12-1/4\" hole section.\u0000 On the first test well, RDE bit and the drilling automation software were used with a motorized rotary steerable system (RSS), to drill 1,060 feet in 15.27 on-bottom hours with an effective ROP of 69.4 feet/hour. The second test well was in a different field, drilling 1,265 feet in 25.22 on-bottom hours achieving ROP of 50.16 feet/hour. Both test runs set new benchmark performance in comparison to the respective field offset wells. This high performance seen in both test runs were enabled by increase in ROP & the significant reduction of downhole vibrations and stick and slip brought by combining the new technologies in bit and drilling automation software.\u0000 The first-time application of the new technologies helped the operator to solve drilling challenges, increasing performance and reducing the cost per foot by 20%.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83902496","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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