V. Syrtlanov, Y. Golovatskiy, K. Chistikov, Dmitriy Bormashov
This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).
{"title":"Experience in Optimizing the Location and Parameters of Multistage Hydraulic Fractures for a Multilateral Well Based on Reservoir Simulation","authors":"V. Syrtlanov, Y. Golovatskiy, K. Chistikov, Dmitriy Bormashov","doi":"10.2118/206541-ms","DOIUrl":"https://doi.org/10.2118/206541-ms","url":null,"abstract":"\u0000 This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86744011","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}
V. Kosarev, E. A. Yachmeneva, Aleksandr Vladimirovich Starovoyto, D. I. Kirgizov, Rustem Ramilevich Mukhamadiev, V. Sudakov, B. Akhmetov, Aleksandr Borisovich Savlenkov
This paper presents the efficiency of using artificial neural networks for solving problems of processing and interpreting geophysical data obtained by scanning magnetic introscopy. Neural networks of various architectures have been implemented to solve the problems of processing primary material, searching for well structure objects,identifying casing defects. The analysis of the capabilities of neural networks in comparison with mathematical algorithms is carried out. To test machine learning algorithms and mathematical algorithms for processing, visualizing and storing the results, a software shell was created in which all tasks are solved using a set of tools. It was found that the use of artificial neural networks can significantly speed up the process of data processing and interpretation, as well as improve the quality of the results in comparison with individual mathematical algorithms. Nevertheless, the use of mathematical algorithms in solving some problems gives consistently better results. In particular, the problematic aspects were identified at the stage of interpretation when identifying defects. This is due to the presence of conventions in the isolation of defects by the operator at the stage of preparing data for training neural networks, which is a subjective factor and requires a deeper study.
{"title":"Application of Artificial Neural Networks for Processing and Interpretation of Data from a Scanning Magnetic Introscope","authors":"V. Kosarev, E. A. Yachmeneva, Aleksandr Vladimirovich Starovoyto, D. I. Kirgizov, Rustem Ramilevich Mukhamadiev, V. Sudakov, B. Akhmetov, Aleksandr Borisovich Savlenkov","doi":"10.2118/206632-ms","DOIUrl":"https://doi.org/10.2118/206632-ms","url":null,"abstract":"\u0000 This paper presents the efficiency of using artificial neural networks for solving problems of processing and interpreting geophysical data obtained by scanning magnetic introscopy. Neural networks of various architectures have been implemented to solve the problems of processing primary material, searching for well structure objects,identifying casing defects. The analysis of the capabilities of neural networks in comparison with mathematical algorithms is carried out. To test machine learning algorithms and mathematical algorithms for processing, visualizing and storing the results, a software shell was created in which all tasks are solved using a set of tools. It was found that the use of artificial neural networks can significantly speed up the process of data processing and interpretation, as well as improve the quality of the results in comparison with individual mathematical algorithms. Nevertheless, the use of mathematical algorithms in solving some problems gives consistently better results. In particular, the problematic aspects were identified at the stage of interpretation when identifying defects. This is due to the presence of conventions in the isolation of defects by the operator at the stage of preparing data for training neural networks, which is a subjective factor and requires a deeper study.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85081722","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}
Pavel Nikolayevich Sergeev, Alexander Fyodorovich Mordyukov, A. Kozyrev, E. V. Bembak, Aleksander Mikhailovich Matsera, Alexander V. Kabanov, E. Tikhonov, A. Kharitonov
The Operator's challenge was the construction of a sub-horizontal well with 1500 m liner section in area with limited offset experience. The main development difficulty of the East Urengoy license area is the abnormally high pore pressure Achimov deposit. The widely used practice of drilling for these reservoirs with S-shaped profile wells has been utilized for a long while. However, the construction of sub-horizontal wells is still a challenge, and often accompanied by high incident rates. Before drilling the well, all necessary fluid engineering modelling was performed. According to the hydraulic calculations, drilling of the horizontal well with traditional fluid properties was not possible due to exceeding the maximum ECD range. Multiple laboratory tests were performed to optimize the drilling fluid parameters and rheological properties with respect to ECD reduction and reducing potential for weight fluctuations due to barite sag. Based on the data obtained, recommendations were issued to predict ECD levels while drilling and tripping. At the same time, step-by-step action plans were developed for trouble-free drilling. While utilizing this optimized fluid, with close interaction and cooperation between the project Operator (ROSPAN International), the Customer's research and development center, technical support service and the drilling contractor, the first sub-horizontal well on this licensed site has been successfully drilled. The following main actions were developed and executed during the well construction process: Maintained the hydraulic pressure (marginally) above the pore pressure through careful fluid management. The rheological properties of the drilling fluid were maintained to the developed (lab verified) specifications. Careful hydraulic pressure management during tripping. Extensive planning of the tripping operations included increasing the mud weight before tripping to create the necessary margin and optimization of the tripping rate. Ensuring effective drilling parameters and preparing the wellbore for the casing run according to hydraulic calculations. Recommended optimized drilling fluid parameters aimed at preventing barite sag under abnormally high pore pressure and high bottom hole temperatures (up to 110 deg C). Use of specialized pills to assist prevent the loss of circulation and wellbore instability. This article is devoted to the development of drilling fluid solutions and practical techniques for effectively drilling wells in the area with challenging formations. This case study, as well as the lessons learned will be used for ongoing drilling projects in the area.
{"title":"Engineering Fluids and Hydraulics to Drill the First Sub-Horizontal Well with Narrow ECD Window in Eastern Urengoy License Area","authors":"Pavel Nikolayevich Sergeev, Alexander Fyodorovich Mordyukov, A. Kozyrev, E. V. Bembak, Aleksander Mikhailovich Matsera, Alexander V. Kabanov, E. Tikhonov, A. Kharitonov","doi":"10.2118/206448-ms","DOIUrl":"https://doi.org/10.2118/206448-ms","url":null,"abstract":"\u0000 The Operator's challenge was the construction of a sub-horizontal well with 1500 m liner section in area with limited offset experience. The main development difficulty of the East Urengoy license area is the abnormally high pore pressure Achimov deposit. The widely used practice of drilling for these reservoirs with S-shaped profile wells has been utilized for a long while. However, the construction of sub-horizontal wells is still a challenge, and often accompanied by high incident rates.\u0000 Before drilling the well, all necessary fluid engineering modelling was performed. According to the hydraulic calculations, drilling of the horizontal well with traditional fluid properties was not possible due to exceeding the maximum ECD range. Multiple laboratory tests were performed to optimize the drilling fluid parameters and rheological properties with respect to ECD reduction and reducing potential for weight fluctuations due to barite sag. Based on the data obtained, recommendations were issued to predict ECD levels while drilling and tripping. At the same time, step-by-step action plans were developed for trouble-free drilling.\u0000 While utilizing this optimized fluid, with close interaction and cooperation between the project Operator (ROSPAN International), the Customer's research and development center, technical support service and the drilling contractor, the first sub-horizontal well on this licensed site has been successfully drilled.\u0000 The following main actions were developed and executed during the well construction process:\u0000 Maintained the hydraulic pressure (marginally) above the pore pressure through careful fluid management. The rheological properties of the drilling fluid were maintained to the developed (lab verified) specifications. Careful hydraulic pressure management during tripping. Extensive planning of the tripping operations included increasing the mud weight before tripping to create the necessary margin and optimization of the tripping rate. Ensuring effective drilling parameters and preparing the wellbore for the casing run according to hydraulic calculations. Recommended optimized drilling fluid parameters aimed at preventing barite sag under abnormally high pore pressure and high bottom hole temperatures (up to 110 deg C). Use of specialized pills to assist prevent the loss of circulation and wellbore instability.\u0000 This article is devoted to the development of drilling fluid solutions and practical techniques for effectively drilling wells in the area with challenging formations. This case study, as well as the lessons learned will be used for ongoing drilling projects in the area.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88096534","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. Kudryashov, Kiryl Karseka, D. Mityurich, V. Lompik, A. Cheremisin, Margarita Spivakova
The aim of the work is to create representative 1D- and 3D-models of surfactant-polymer flooding, considering the most significant physical and chemical phenomena that occur during this process, and further efficiency evaluation of the method. The paper describes approaches to reproduce and verify laboratory experiments results of recovery factor increase during surfactant-polymer flooding on core samples using 1D-model, as well as approaches to optimize the compositions and injection schemes of chemicals during the efficiency evaluation of the technology on a 3D-model of the pilot site.
{"title":"Experience of Surfactant-Polymer Flooding Simulation on a Sandstone Reservoir","authors":"A. Kudryashov, Kiryl Karseka, D. Mityurich, V. Lompik, A. Cheremisin, Margarita Spivakova","doi":"10.2118/206554-ms","DOIUrl":"https://doi.org/10.2118/206554-ms","url":null,"abstract":"\u0000 The aim of the work is to create representative 1D- and 3D-models of surfactant-polymer flooding, considering the most significant physical and chemical phenomena that occur during this process, and further efficiency evaluation of the method. The paper describes approaches to reproduce and verify laboratory experiments results of recovery factor increase during surfactant-polymer flooding on core samples using 1D-model, as well as approaches to optimize the compositions and injection schemes of chemicals during the efficiency evaluation of the technology on a 3D-model of the pilot site.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"110 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83437332","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. Tikhomirov, F. Bakharev, A. Groman, Alexander V. Kalyuzhnyuk, Yu. Petrova, A. Enin, K. Kalinin, N. Rastegaev
One of the motivations for EOR methods is the possible instability of the front between phases with high contrast of mobility. Highly viscous polymer slug partially solves the problem by stabilizing the front between water and oil. During further water displacement viscous fingers might appear on the rear end of the slug, and their breakthrough might reduce the oil recovery factor. In the paper we study the size of the mixing zone on the rear end of the slug and further the development of the graded viscosity banks technology (GVB or tapering) to reduce the volume of used polymer without loss of effectiveness.
{"title":"Calculation of Graded Viscosity Banks Profile on the Rear End of the Polymer Slug","authors":"S. Tikhomirov, F. Bakharev, A. Groman, Alexander V. Kalyuzhnyuk, Yu. Petrova, A. Enin, K. Kalinin, N. Rastegaev","doi":"10.2118/206426-ms","DOIUrl":"https://doi.org/10.2118/206426-ms","url":null,"abstract":"\u0000 One of the motivations for EOR methods is the possible instability of the front between phases with high contrast of mobility. Highly viscous polymer slug partially solves the problem by stabilizing the front between water and oil. During further water displacement viscous fingers might appear on the rear end of the slug, and their breakthrough might reduce the oil recovery factor. In the paper we study the size of the mixing zone on the rear end of the slug and further the development of the graded viscosity banks technology (GVB or tapering) to reduce the volume of used polymer without loss of effectiveness.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90155100","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. Kornilov, I. Tkachev, A. V. Fomkin, Andrey Mikhailovich Petrakov, D. Batrshin, G. Fursov, Denis Mikhailovich Ponomarenko, G. Fedorchenko, Geroge Vladimirovih Sansiev
The paper describes the process of evaluation of low salinity water composition to improve the development of hydrophobic carbonate formations of Central-Khoreiver Uplift (CKU) fields with relatively high oil viscosity (5-15 mPa·s) and average formation temperature 70°C. The sources of low salinity water were determined, prospective composition for water injection were analyzed. The efficiency of oil displacement by formation water and low salinity water are observed during the spontaneous imbibition experiments and coreflood tests to compare the efficiency of formation and low salinity water. The expected incremental displacement efficiency for the target carbonate formations can vary widely, from 1 to 10%. Linear models of the completed coreflood tests and a sector hydrodynamic model of the prospective trial injection are built, considering the basic chemical processes while mixing different types of water. We also review the prospects of joint application of low salinity water injection and chemical EOR methods.
{"title":"Injection of Low-Salinity Water as an Integral Part of Enhanced Oil Recovery Programmes for Carbonate Formations of the Central-Khoreiver Uplift Oilfields","authors":"A. Kornilov, I. Tkachev, A. V. Fomkin, Andrey Mikhailovich Petrakov, D. Batrshin, G. Fursov, Denis Mikhailovich Ponomarenko, G. Fedorchenko, Geroge Vladimirovih Sansiev","doi":"10.2118/206433-ms","DOIUrl":"https://doi.org/10.2118/206433-ms","url":null,"abstract":"\u0000 The paper describes the process of evaluation of low salinity water composition to improve the development of hydrophobic carbonate formations of Central-Khoreiver Uplift (CKU) fields with relatively high oil viscosity (5-15 mPa·s) and average formation temperature 70°C. The sources of low salinity water were determined, prospective composition for water injection were analyzed. The efficiency of oil displacement by formation water and low salinity water are observed during the spontaneous imbibition experiments and coreflood tests to compare the efficiency of formation and low salinity water. The expected incremental displacement efficiency for the target carbonate formations can vary widely, from 1 to 10%.\u0000 Linear models of the completed coreflood tests and a sector hydrodynamic model of the prospective trial injection are built, considering the basic chemical processes while mixing different types of water. We also review the prospects of joint application of low salinity water injection and chemical EOR methods.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90636618","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. Scerbacova, A. Ivanova, E. Mukhina, A. Ushakova, M. Bondar, A. Cheremisin
The gradual depletion of conventional oil reserves and the growing demand for hydrocarbon feedstock have led to shale deposits development necessity, which are characterized by high reservoir temperatures and very low permeabilites. One of the methods proposed for unconventional reservoirs development is surfactant injection in huff-n-puff mode. Unlike surfactant flooding, where the main effect is achieved through the displacement mechanism, the huff-n-puff method is based on capillary imbibition. Surfactant solutions decrease oil-water interfacial tension, change rock surface wettability to water-wet, lead to desorption of adsorbed hydrocarbons and increase relative permeability to water, thus increasing oil production. A number of commercially available anionic and nonionic surfactants were selected for laboratory investigation. Compatibility with reservoir fluids and thermal stability were tested for 14 days. For the stable compositions, the interfacial tension at the boundary with oil was measured with the spinning drop method. Special attention was paid to the study of initial reservoir wettability and the ability of the selected surfactants to shift it towards water-wet. Wettability at the macro level was determined by the "sessile" drop method. As a result of the screening, two surfactant compositions capable to alter the wettability of the rock surface to strictly water-wet were selected, as this is the key point when selecting surfactant compositions for low-permeable reservoirs. The optimum operating concentrations were selected to avoid the formation of a Winsor III microemulsion, which can lead to plugging of narrow channels and fluid flow blockage in the formation. Values of static adsorption onto crushed rock were also evaluated. The most effective composition was investigated in a huff-n-puff filtration experiment and positive results were obtained. Nanoparticles were also screened as potential components of surfactant compositions. It was found that nanoparticles forming stable dispersions in surfactant solutions improve their ability to change the wettability to a water-wet state. As a result of the laboratory work performed, it can be concluded that the huff-n-puff technology is applicable in unconventional reservoirs with very low permeabilities. The huff-n-puff mode for surfactant solutions injection is preferable due to lower surfactant consumption, targeted effect, and shortened well response time. Successful implementation of this technology on an industrial scale can improve the efficiency of shale oil production.
{"title":"Screening of Surfactants for Huff-N-Puff Injection into Unconventional Reservoirs","authors":"A. Scerbacova, A. Ivanova, E. Mukhina, A. Ushakova, M. Bondar, A. Cheremisin","doi":"10.2118/206431-ms","DOIUrl":"https://doi.org/10.2118/206431-ms","url":null,"abstract":"\u0000 The gradual depletion of conventional oil reserves and the growing demand for hydrocarbon feedstock have led to shale deposits development necessity, which are characterized by high reservoir temperatures and very low permeabilites. One of the methods proposed for unconventional reservoirs development is surfactant injection in huff-n-puff mode. Unlike surfactant flooding, where the main effect is achieved through the displacement mechanism, the huff-n-puff method is based on capillary imbibition. Surfactant solutions decrease oil-water interfacial tension, change rock surface wettability to water-wet, lead to desorption of adsorbed hydrocarbons and increase relative permeability to water, thus increasing oil production.\u0000 A number of commercially available anionic and nonionic surfactants were selected for laboratory investigation. Compatibility with reservoir fluids and thermal stability were tested for 14 days. For the stable compositions, the interfacial tension at the boundary with oil was measured with the spinning drop method. Special attention was paid to the study of initial reservoir wettability and the ability of the selected surfactants to shift it towards water-wet. Wettability at the macro level was determined by the \"sessile\" drop method.\u0000 As a result of the screening, two surfactant compositions capable to alter the wettability of the rock surface to strictly water-wet were selected, as this is the key point when selecting surfactant compositions for low-permeable reservoirs. The optimum operating concentrations were selected to avoid the formation of a Winsor III microemulsion, which can lead to plugging of narrow channels and fluid flow blockage in the formation. Values of static adsorption onto crushed rock were also evaluated. The most effective composition was investigated in a huff-n-puff filtration experiment and positive results were obtained.\u0000 Nanoparticles were also screened as potential components of surfactant compositions. It was found that nanoparticles forming stable dispersions in surfactant solutions improve their ability to change the wettability to a water-wet state.\u0000 As a result of the laboratory work performed, it can be concluded that the huff-n-puff technology is applicable in unconventional reservoirs with very low permeabilities. The huff-n-puff mode for surfactant solutions injection is preferable due to lower surfactant consumption, targeted effect, and shortened well response time. Successful implementation of this technology on an industrial scale can improve the efficiency of shale oil production.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84245500","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. Shtun, A. Senkov, O. Abramenko, Mickhail Rakitin, V. Nagimov, A. Trusov, A. Frolov
The monitoring of sustainable annulus pressure (SAP) in offshore wells plays an important role in the development of an oil reservoir with a massive gas cap. The method of spectral noise logging and high-precision temperature logging used to identify SAP source presented in work (Shtun 2020) proved to be good in determining the intervals of gas movement, however, the method is limited in answers. The most significant limitation of the spectral noise logging method is associated with the impossibility based on power spectrum to distinguish the zones of gas flow in the annular space and gas inflow zones from reservoir contributing SAP. This information is critical for proper workover planning to eliminate SAP. This limitation relates to the fact that the amplitude and frequency of the resulting signal depend on not only the aperture of space fluid flow through and depend on the turbulence of the fluid flow. The paper describes a novel technology of multisensory passive acoustics of radial location that is designed to differentiate far and near acoustic sources in wells to accurately define the sources of SAP. The results of laboratory and field cases in offshore oil wells were presented in this paper as well as the comparison between single sensor spectral noise logging and multisensory passive acoustics of radial location answers was given at the end of the paper based on real case studies. As shown in the paper the described technology provides a more accurate determination of the source of SAP and the geometry of fluid movement in the near-wellbore zone.
{"title":"Sustained Annulus Pressure Diagnostics in Offshore Wells by Multisensory Spectral Acoustics","authors":"S. Shtun, A. Senkov, O. Abramenko, Mickhail Rakitin, V. Nagimov, A. Trusov, A. Frolov","doi":"10.2118/206629-ms","DOIUrl":"https://doi.org/10.2118/206629-ms","url":null,"abstract":"\u0000 The monitoring of sustainable annulus pressure (SAP) in offshore wells plays an important role in the development of an oil reservoir with a massive gas cap. The method of spectral noise logging and high-precision temperature logging used to identify SAP source presented in work (Shtun 2020) proved to be good in determining the intervals of gas movement, however, the method is limited in answers. The most significant limitation of the spectral noise logging method is associated with the impossibility based on power spectrum to distinguish the zones of gas flow in the annular space and gas inflow zones from reservoir contributing SAP. This information is critical for proper workover planning to eliminate SAP. This limitation relates to the fact that the amplitude and frequency of the resulting signal depend on not only the aperture of space fluid flow through and depend on the turbulence of the fluid flow. The paper describes a novel technology of multisensory passive acoustics of radial location that is designed to differentiate far and near acoustic sources in wells to accurately define the sources of SAP. The results of laboratory and field cases in offshore oil wells were presented in this paper as well as the comparison between single sensor spectral noise logging and multisensory passive acoustics of radial location answers was given at the end of the paper based on real case studies. As shown in the paper the described technology provides a more accurate determination of the source of SAP and the geometry of fluid movement in the near-wellbore zone.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"100 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78280844","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}
E&P activities are the early stage of energy production and pivotal for generating and sustaining economic growth. However, negligence and evaluating the circumstances incorrectly during these operations can lead to calamities like blowouts. This paper discusses two such tragedies, the Pasarlapudi (Krishna-Godavari) Gas Well Blowout of 1995 & Baghjan (Assam-Arakan) Oil Field Blowout of 2020, and provides possible well control measures and lessons learned. Pasarlapudi blowout incident occurred during the drilling operations. The pipe stuck-up situation at 2727m MD (Measured Depth) was detected by conducting a stretch test. Further analysis could include circulating brine, checking lost circulation and identifying casing leaks by measuring Sustained Casing Pressure (SCP), Operator-imposed Pressure (OIP), and Thermal-induced Pressure (TIP). Baghjan's gas well at the depth 3870m was producing at 2.8-3.5 MMSCFD. The aim was to plug the lower producing zone and recomplete the well in the upper Lakadong+Therria sand zone. Well was killed using brine, cement plug was placed and BOP installed. BOP was removed after the plug was set to begin the process of moving the workover rig. Well blew gas profusely during this process. Simulating a blowout and facing one, are two completely different situations. In Pasarlapudi's case, the well blew with an enormous gas pressure of 281.2 ± 0.5 kg/cm2. While drilling the production hole (8.5 inch), either differential pressure sticking, presence of water-swelling clay formation or the partial collapse of wellbore formation caused the pipe stuck-up situation. By conducting stretch test along with circulating brine, root cause of this problem could be identified. If differential sticking occurred, lost circulation could be checked & cured, while keeping the hole full. Circulating brine should solve the problem of swelling clay formation while formation collapse could have occurred due to the presence of plastic formation like salt domes. In the case of Baghjan gas well blowout during workover operations, probable safety measures could include placement of 2 or 3 backup cement plugs along with kill fluid or going for squeeze cementing before placing the cement plug & kill fluid while abandoning the lower producing zone. Attempts were made to bring the well under control by adequate water spraying, installing BOP. Water was pumped through the casing valve and a water reservoir was dug near the well plinth for the placement of pumps of 2500 gallon capacity. Proper safety measures should be used even when they're not the cheapest to avoid repetition of treatments and detrimental situations. SCP, OIP and TIP should be measured periodically whenever possible and the root cause of situations like lost circulation, pipe stuck-ups, kicks, casing leaks should be identified before proceeding towards drastic remedial operations. Innovations in countering well-control situations should be promoted invariably.
{"title":"Managing Gas Well Blowouts: Case Studies from Assam-Arakan & Krishna-Godavari Basin","authors":"R. Bharadwaj, Bhavya Kumari, Astha Patel","doi":"10.2118/206602-ms","DOIUrl":"https://doi.org/10.2118/206602-ms","url":null,"abstract":"\u0000 E&P activities are the early stage of energy production and pivotal for generating and sustaining economic growth. However, negligence and evaluating the circumstances incorrectly during these operations can lead to calamities like blowouts. This paper discusses two such tragedies, the Pasarlapudi (Krishna-Godavari) Gas Well Blowout of 1995 & Baghjan (Assam-Arakan) Oil Field Blowout of 2020, and provides possible well control measures and lessons learned.\u0000 Pasarlapudi blowout incident occurred during the drilling operations. The pipe stuck-up situation at 2727m MD (Measured Depth) was detected by conducting a stretch test. Further analysis could include circulating brine, checking lost circulation and identifying casing leaks by measuring Sustained Casing Pressure (SCP), Operator-imposed Pressure (OIP), and Thermal-induced Pressure (TIP). Baghjan's gas well at the depth 3870m was producing at 2.8-3.5 MMSCFD. The aim was to plug the lower producing zone and recomplete the well in the upper Lakadong+Therria sand zone. Well was killed using brine, cement plug was placed and BOP installed. BOP was removed after the plug was set to begin the process of moving the workover rig. Well blew gas profusely during this process.\u0000 Simulating a blowout and facing one, are two completely different situations. In Pasarlapudi's case, the well blew with an enormous gas pressure of 281.2 ± 0.5 kg/cm2. While drilling the production hole (8.5 inch), either differential pressure sticking, presence of water-swelling clay formation or the partial collapse of wellbore formation caused the pipe stuck-up situation. By conducting stretch test along with circulating brine, root cause of this problem could be identified. If differential sticking occurred, lost circulation could be checked & cured, while keeping the hole full. Circulating brine should solve the problem of swelling clay formation while formation collapse could have occurred due to the presence of plastic formation like salt domes.\u0000 In the case of Baghjan gas well blowout during workover operations, probable safety measures could include placement of 2 or 3 backup cement plugs along with kill fluid or going for squeeze cementing before placing the cement plug & kill fluid while abandoning the lower producing zone. Attempts were made to bring the well under control by adequate water spraying, installing BOP. Water was pumped through the casing valve and a water reservoir was dug near the well plinth for the placement of pumps of 2500 gallon capacity.\u0000 Proper safety measures should be used even when they're not the cheapest to avoid repetition of treatments and detrimental situations. SCP, OIP and TIP should be measured periodically whenever possible and the root cause of situations like lost circulation, pipe stuck-ups, kicks, casing leaks should be identified before proceeding towards drastic remedial operations. Innovations in countering well-control situations should be promoted invariably.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91523071","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}
Petr Leonidovich Ryabtsev, S. Popov, A. Korolev, Samat Maratovich Urakov, A. Akvilev
This paper presents the results of laboratory studies and field application of a drilling fluid based on a new generation of polymer inhibitors. The summarized results of the application confirm the effectiveness of the new polymer type used. The body of the article is devoted to the experience of using an innovative drilling fluid system for drilling an exploration well in the Astrakhan gas condensate field. One of the features of the Astrakhan gas condensate field is a number of intervals of possible complications: lost circulation zones, prone to clay swelling and caving, and presence of salts and hydrogen sulfide in the reservoir. One of the solutions for ensuring trouble-free drilling in such conditions is using an oil-based drilling fluid (OBM). However, OBM is often avoided when drilling exploratory wells due to environmental and technological limitations. In this connection, the project team carried out work on selection and development of a water-based drilling fluid formulation, which would ensure the most trouble-free and cost-effective drilling operations. Considering these studies, a drilling fluid was selected based on a new generation of inhibitor polymers. The key feature of the proposed formulation is the use of a new polar inhibitor polymer. The selected formulation showed the best laboratory test results after which it was approved for application. The main risk of using the new drilling fluid formulation was lack of filed experience in using this system in similar geological conditions. At the same time, laboratory tests showed that the proposed alternative mud formulations did not provide the required level of contamination resistance and inhibiting ability. Over the period from April to September of 2020, the exploration well was successfully drilled at the Astrakhan gas condensate field using the selected drilling fluid based on a new polymer type. Using the same drilling fluid type, four intervals - from the surface pipe to the production liner, - were drilled.
{"title":"Successful Application of a New Generation of Clay Inhibitor Polymers While Drilling a Deep Exploration Well in the Astrakhan Region","authors":"Petr Leonidovich Ryabtsev, S. Popov, A. Korolev, Samat Maratovich Urakov, A. Akvilev","doi":"10.2118/206444-ms","DOIUrl":"https://doi.org/10.2118/206444-ms","url":null,"abstract":"\u0000 This paper presents the results of laboratory studies and field application of a drilling fluid based on a new generation of polymer inhibitors. The summarized results of the application confirm the effectiveness of the new polymer type used.\u0000 The body of the article is devoted to the experience of using an innovative drilling fluid system for drilling an exploration well in the Astrakhan gas condensate field. One of the features of the Astrakhan gas condensate field is a number of intervals of possible complications: lost circulation zones, prone to clay swelling and caving, and presence of salts and hydrogen sulfide in the reservoir. One of the solutions for ensuring trouble-free drilling in such conditions is using an oil-based drilling fluid (OBM). However, OBM is often avoided when drilling exploratory wells due to environmental and technological limitations. In this connection, the project team carried out work on selection and development of a water-based drilling fluid formulation, which would ensure the most trouble-free and cost-effective drilling operations.\u0000 Considering these studies, a drilling fluid was selected based on a new generation of inhibitor polymers. The key feature of the proposed formulation is the use of a new polar inhibitor polymer. The selected formulation showed the best laboratory test results after which it was approved for application. The main risk of using the new drilling fluid formulation was lack of filed experience in using this system in similar geological conditions. At the same time, laboratory tests showed that the proposed alternative mud formulations did not provide the required level of contamination resistance and inhibiting ability.\u0000 Over the period from April to September of 2020, the exploration well was successfully drilled at the Astrakhan gas condensate field using the selected drilling fluid based on a new polymer type. Using the same drilling fluid type, four intervals - from the surface pipe to the production liner, - were drilled.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83323814","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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