The fluid flow dynamics of the matrix and fractures are significantly different from each other. Fractures are high-permeability flow channels that serve as the main flow units. On the other hand, the Matrix takes up the majority of the reservoir volume and is generally regarded as the main storage unit. The primary goal of this research is to investigate numerically the effects of fractures and polymer gel treatment on oil recovery during waterflooding of artificially fractured core plugs. In this study, the MATLAB Reservoir Simulation Toolbox (MRST) was used for the numerical solution. Different numerical models were developed using MRST to describe three main cases: non-fractured core plug, fractured core plug, and polymer gel treated core plug. Following the creation of the physical models, 2 PV water was introduced into all core plugs. Oil recovery and water saturation profiles vs. time plots were obtained. The standard Buckley-Leveret solution is utilized to evaluate the numerical model, and the fractures are modeled using the Embedded Discrete Fracture Model (EDFM). The results of the simulations were compared with the results of the experiments. In the experiments, results were recorded after 2 PV water injections. For the polymer gel treated core plugs, 2 PV more water was injected after the polymer gel operation. same injection volumes as used in the MRST model. For an artificially fractured core sample, initial oil recovery was measured as 28.57% experimentally and 28.87% with MRST. Then polymer gel was applied to the core plug, increasing the oil recovery to 42.85% experimentally and to 40.83% with MRST. Similarly, before and after polymer gel operation, mean water saturation was measured as 58.34% and 66.5%, respectively. MRST results showed mean water saturation of 58.38% and 65.45%. It is clear from both numerical and experimental models that the existence of fractures decreases the overall hydrocarbon recovery. Polymer gel treatment decreases fracture permeability, resulting in a more uniform sweep and increased overall recovery. Additional oil recovery was observed after polymer gel treatment. Besides, polymer gel treatment of the matrix is also efficient for increasing the recovery and leads to the same results. Moreover, the effects of the fracture aperture and fracture permeability on the recovery were also investigated. Fracture aperture directly impacts the recovery of the low aperture values when the permeability is constant. Similarly, permeability directly affects recovery for high values when the aperture is constant. Finally, the results showed that experimental and numerical findings are significantly close to each other for all non-fractured, fractured, and polymer gel-treated cases.
{"title":"Numerical Modeling of Waterflooding Experiments in Artificially Fractured and Gel Treated Core Plugs by Embedded Discrete Fracture Model of a Reservoir Simulation Toolbox","authors":"Onur Alp Kaya, I. Durgut, S. Canbolat","doi":"10.2118/208874-ms","DOIUrl":"https://doi.org/10.2118/208874-ms","url":null,"abstract":"\u0000 The fluid flow dynamics of the matrix and fractures are significantly different from each other. Fractures are high-permeability flow channels that serve as the main flow units. On the other hand, the Matrix takes up the majority of the reservoir volume and is generally regarded as the main storage unit. The primary goal of this research is to investigate numerically the effects of fractures and polymer gel treatment on oil recovery during waterflooding of artificially fractured core plugs. In this study, the MATLAB Reservoir Simulation Toolbox (MRST) was used for the numerical solution. Different numerical models were developed using MRST to describe three main cases: non-fractured core plug, fractured core plug, and polymer gel treated core plug. Following the creation of the physical models, 2 PV water was introduced into all core plugs. Oil recovery and water saturation profiles vs. time plots were obtained. The standard Buckley-Leveret solution is utilized to evaluate the numerical model, and the fractures are modeled using the Embedded Discrete Fracture Model (EDFM). The results of the simulations were compared with the results of the experiments. In the experiments, results were recorded after 2 PV water injections. For the polymer gel treated core plugs, 2 PV more water was injected after the polymer gel operation. same injection volumes as used in the MRST model. For an artificially fractured core sample, initial oil recovery was measured as 28.57% experimentally and 28.87% with MRST. Then polymer gel was applied to the core plug, increasing the oil recovery to 42.85% experimentally and to 40.83% with MRST. Similarly, before and after polymer gel operation, mean water saturation was measured as 58.34% and 66.5%, respectively. MRST results showed mean water saturation of 58.38% and 65.45%. It is clear from both numerical and experimental models that the existence of fractures decreases the overall hydrocarbon recovery. Polymer gel treatment decreases fracture permeability, resulting in a more uniform sweep and increased overall recovery. Additional oil recovery was observed after polymer gel treatment. Besides, polymer gel treatment of the matrix is also efficient for increasing the recovery and leads to the same results. Moreover, the effects of the fracture aperture and fracture permeability on the recovery were also investigated. Fracture aperture directly impacts the recovery of the low aperture values when the permeability is constant. Similarly, permeability directly affects recovery for high values when the aperture is constant. Finally, the results showed that experimental and numerical findings are significantly close to each other for all non-fractured, fractured, and polymer gel-treated cases.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88176415","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}
Nirupama A Vaidya, R. Prabhu, J. Santamaría, P. Abivin, Josh Susmarski
Sand production from unconsolidated sandstone reservoirs can adversely affect reservoir productivity and project profitability. Sand consolidation is a remedial technology that consists of injecting a fluid into the formation to bind the sand grains together and provide strong cohesion. Most existing consolidation technologies use solvent-based fluids, which increases the operational complexity of achieving successful treatment without compromising retained permeability and raises environmental concerns. A novel solvent-free resin system for sand consolidation addresses these challenges by using water-based fluids that are capable of providing high compressive strength while maintaining high permeability, thus simplifying operations and reducing environmental concerns. The new fluid system consists of a resin, a curing agent, and a surfactant dispersed in water. The consolidation mechanism is designed to be triggered downhole by temperature. The fluid system was fully characterized in terms of viscosity, stability at elevated temperature, and performance to provide operational control and reduce pumping risks in a wide range of reservoir applications. Regained permeability and compressive strength of the consolidated sand were quantified for clean sand and sand with different amounts of clays. The consolidation fluid uses limited resin with the balance being predominantly water. The large volume fraction of water acts as a spacer, resulting in high retained permeability (greater than 75%) after the resin has set. Once mixed, the fluid has very low viscosity (less than 5 cP at ambient temperature and 170 s-1) and is stable for at least 24 hours. Additionally, the consolidation mechanism is uniquely triggered by temperature, providing more control and reducing operational risks. This mechanism allows all required components to be mixed together and the treatment to be single stage, thus drastically improving operational efficiency. The new consolidation fluid functions well over a wide temperature range (104°F to 230°F) yielding an unconfined compressive strength of up to 2800 lbf/in2 while maintaining regained permeability of over 75%. It is also compatible with significant amounts of clays, thereby enabling its use in challenging reservoir conditions. The new consolidation fluid system introduces more sustainability into the oilfield. It performs well over wide reservoir permeabilities and temperature ranges and is also compatible with clays and oils. The operational simplicity and efficiency gains offered make this fluid an attractive alternate to existing resin-based sand consolidation products.
{"title":"A Sustainable Fluid System for Sand Consolidation","authors":"Nirupama A Vaidya, R. Prabhu, J. Santamaría, P. Abivin, Josh Susmarski","doi":"10.2118/208808-ms","DOIUrl":"https://doi.org/10.2118/208808-ms","url":null,"abstract":"\u0000 Sand production from unconsolidated sandstone reservoirs can adversely affect reservoir productivity and project profitability. Sand consolidation is a remedial technology that consists of injecting a fluid into the formation to bind the sand grains together and provide strong cohesion. Most existing consolidation technologies use solvent-based fluids, which increases the operational complexity of achieving successful treatment without compromising retained permeability and raises environmental concerns. A novel solvent-free resin system for sand consolidation addresses these challenges by using water-based fluids that are capable of providing high compressive strength while maintaining high permeability, thus simplifying operations and reducing environmental concerns.\u0000 The new fluid system consists of a resin, a curing agent, and a surfactant dispersed in water. The consolidation mechanism is designed to be triggered downhole by temperature. The fluid system was fully characterized in terms of viscosity, stability at elevated temperature, and performance to provide operational control and reduce pumping risks in a wide range of reservoir applications. Regained permeability and compressive strength of the consolidated sand were quantified for clean sand and sand with different amounts of clays.\u0000 The consolidation fluid uses limited resin with the balance being predominantly water. The large volume fraction of water acts as a spacer, resulting in high retained permeability (greater than 75%) after the resin has set. Once mixed, the fluid has very low viscosity (less than 5 cP at ambient temperature and 170 s-1) and is stable for at least 24 hours. Additionally, the consolidation mechanism is uniquely triggered by temperature, providing more control and reducing operational risks. This mechanism allows all required components to be mixed together and the treatment to be single stage, thus drastically improving operational efficiency. The new consolidation fluid functions well over a wide temperature range (104°F to 230°F) yielding an unconfined compressive strength of up to 2800 lbf/in2 while maintaining regained permeability of over 75%. It is also compatible with significant amounts of clays, thereby enabling its use in challenging reservoir conditions.\u0000 The new consolidation fluid system introduces more sustainability into the oilfield. It performs well over wide reservoir permeabilities and temperature ranges and is also compatible with clays and oils. The operational simplicity and efficiency gains offered make this fluid an attractive alternate to existing resin-based sand consolidation products.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84108667","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}
N. Fleming, K. Taugbøl, A. Mathisen, Ove Braadland, H. Kaarigstad
Formation damage has received significant attention over many years as one of the primary reasons for well productivity impairment, to the detriment of completion damage. The objective of this paper is to redress this imbalance and to focus on the central role that completion damage has on well productivity. Formation damage is a reduction in inflow performance due to damage of the near wellbore, while completion damage is an increased pressure drop effecting the lower completion, e.g., plugging of sand screens. A completion damage classification system is presented for the first time that relates this damage type to lower completion design throughout well lifetime. In addition, a review of some of the fluid qualification tests has been performed. Fluid compatibility. Computational fluid dynamics (CFD) was used to determine the displacement efficiency from drilling to completion fluid in a candidate well, and hence the mixing ratio of drilling fluid to completion fluid to be used in compatibility tests. Furthermore, CFD simulations provided an indication of the likely shear rates occurring during displacement that were later used in the testing. Fluid stability. To determine the influence of sag on fluid displacement efficiency, CFD was used to model the worst-case situation where all the weighting agent came out of suspension. Using the displacement efficiency and shear rates obtained, a new dynamic completion damage test was devised to determine the potential for screen plugging. Finally, an overview will be presented of how Equinor's approach to completion damage has changed because of this study, with increased focus on achieving a better balance in the evaluation of formation and completion damage.
{"title":"Completion Damage","authors":"N. Fleming, K. Taugbøl, A. Mathisen, Ove Braadland, H. Kaarigstad","doi":"10.2118/208843-ms","DOIUrl":"https://doi.org/10.2118/208843-ms","url":null,"abstract":"\u0000 Formation damage has received significant attention over many years as one of the primary reasons for well productivity impairment, to the detriment of completion damage. The objective of this paper is to redress this imbalance and to focus on the central role that completion damage has on well productivity. Formation damage is a reduction in inflow performance due to damage of the near wellbore, while completion damage is an increased pressure drop effecting the lower completion, e.g., plugging of sand screens. A completion damage classification system is presented for the first time that relates this damage type to lower completion design throughout well lifetime. In addition, a review of some of the fluid qualification tests has been performed.\u0000 Fluid compatibility. Computational fluid dynamics (CFD) was used to determine the displacement efficiency from drilling to completion fluid in a candidate well, and hence the mixing ratio of drilling fluid to completion fluid to be used in compatibility tests. Furthermore, CFD simulations provided an indication of the likely shear rates occurring during displacement that were later used in the testing. Fluid stability. To determine the influence of sag on fluid displacement efficiency, CFD was used to model the worst-case situation where all the weighting agent came out of suspension.\u0000 Using the displacement efficiency and shear rates obtained, a new dynamic completion damage test was devised to determine the potential for screen plugging. Finally, an overview will be presented of how Equinor's approach to completion damage has changed because of this study, with increased focus on achieving a better balance in the evaluation of formation and completion damage.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73585456","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. Asadi, Tyler Blair, Ben Kuiper, Bruce Cunningham, Tim Shamburger, Brendan Looyenga, Rogelio Morales
A new and robust tracer technology, based on Nano-sized encapsulated silica DNA sequences is presented. This cutting-edge technology enables a bond of each DNA sequence to a magnetic core particle and encapsulates it with silica. Therefore, one can have infinite sequences of DNA tracers. Each DNA tracer, with its identity signature, can be easily identified and characterized with no interferences. Unique chemistry makes these DNA tracers, either water-wet or oil-wet. The water-wet tracers can be used in hydraulic fracturing to precisely and accurately analyze flowback, both qualitatively and quantitatively. The oil-wet tracers can be used in evaluating the source and quantity of oil production in hydraulic fracturing. In-depth laboratory testing indicates that these tracers, unlike current industry used chemical tracers, are stable at high temperature, do not react with formation mineralogy to form reservoir rock plating, do not partition, and do not disintegrate over time. These tracers are injected in the liquid-laden slurry at very low concentrations and can be detected at parts per trillion.
{"title":"DNA Tracer Technology Applications in Hydraulic Fracturing Flowback Analyses","authors":"M. Asadi, Tyler Blair, Ben Kuiper, Bruce Cunningham, Tim Shamburger, Brendan Looyenga, Rogelio Morales","doi":"10.2118/208865-ms","DOIUrl":"https://doi.org/10.2118/208865-ms","url":null,"abstract":"\u0000 A new and robust tracer technology, based on Nano-sized encapsulated silica DNA sequences is presented. This cutting-edge technology enables a bond of each DNA sequence to a magnetic core particle and encapsulates it with silica. Therefore, one can have infinite sequences of DNA tracers. Each DNA tracer, with its identity signature, can be easily identified and characterized with no interferences. Unique chemistry makes these DNA tracers, either water-wet or oil-wet. The water-wet tracers can be used in hydraulic fracturing to precisely and accurately analyze flowback, both qualitatively and quantitatively. The oil-wet tracers can be used in evaluating the source and quantity of oil production in hydraulic fracturing. In-depth laboratory testing indicates that these tracers, unlike current industry used chemical tracers, are stable at high temperature, do not react with formation mineralogy to form reservoir rock plating, do not partition, and do not disintegrate over time. These tracers are injected in the liquid-laden slurry at very low concentrations and can be detected at parts per trillion.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83983905","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}
Clotaire-Marie Eyaa Allogo, Benoit Allias, Redda Tayebi, Antoine Baraque, Jean-Yves Lansot, J. Diogo
Lessons learned in Moho-Nord field Congo improved well productivity and injectivity, from Miocene formation. Due to the type of drill-in fluid used in the initial development phase of the field, the skin factor showed extremely high values, above 150. The values dropped to near 50 after remediation and stimulation operations. Productivity and injectivity rates were significantly poor and did not meet the targets. To mitigate these issues, the most suitable fluids for drilling, completion and removing the filtercake for a horizontal open hole standalone completion were required. Fluids were identified by an extensive laboratory study. The selection was based on the reservoir characteristics and sand control completion type. It was also based on review of past experiences from the original project phase, and continuous discussion between operator and the fluids provider. Changes were made to improve practices during the field implementation. One reservoir drill-in fluid (RDF), a reversible invert emulsion (RIE) non-aqueous base mud (NABM) system and two filtercake breaker systems were selected and implemented in the field. The RIE showed suitable properties required for NABM drilling. It also demonstrated properties of easier filtercake destruction when exposed to lower pH breaker fluids. Its filtercake did not need surfactant/solvent pills to change the wettability of the solids in the filtercake which notably simplified the borehole cleanup operation. The improvement occurred throughout the second and third phases of the field development. The ameliorations were measured through skin value, production and injectivity rates and initial flow initiation pressure. Values were compared against initial targets. As an example, the skin value went from 150 in phase one to less than 5 in phase three. No acid stimulation was required in any of these wells, providing a huge cost saving for the operator. The combination of the fluids selected, and improved drilling and completion practices led to skin values for most between 0 and 3. The productivity and injectivity outperformed and surpassed expectations. Knowledge gained from the study re-established the importance of selecting the suitable fluids systems and using best in class drilling and completion practices. This paper summarizes upfront fluid design requirements and fluids management procedures implemented during drilling, completion and filtercake breaker placement to ensure safe and successful open hole completions.
{"title":"Reversible Fluids and Mud Breaker Technology Outperforms Productivity and Injectivity in West Africa–Fit to Purpose and Designed for Success","authors":"Clotaire-Marie Eyaa Allogo, Benoit Allias, Redda Tayebi, Antoine Baraque, Jean-Yves Lansot, J. Diogo","doi":"10.2118/208861-ms","DOIUrl":"https://doi.org/10.2118/208861-ms","url":null,"abstract":"\u0000 Lessons learned in Moho-Nord field Congo improved well productivity and injectivity, from Miocene formation. Due to the type of drill-in fluid used in the initial development phase of the field, the skin factor showed extremely high values, above 150. The values dropped to near 50 after remediation and stimulation operations. Productivity and injectivity rates were significantly poor and did not meet the targets.\u0000 To mitigate these issues, the most suitable fluids for drilling, completion and removing the filtercake for a horizontal open hole standalone completion were required. Fluids were identified by an extensive laboratory study. The selection was based on the reservoir characteristics and sand control completion type. It was also based on review of past experiences from the original project phase, and continuous discussion between operator and the fluids provider. Changes were made to improve practices during the field implementation.\u0000 One reservoir drill-in fluid (RDF), a reversible invert emulsion (RIE) non-aqueous base mud (NABM) system and two filtercake breaker systems were selected and implemented in the field. The RIE showed suitable properties required for NABM drilling. It also demonstrated properties of easier filtercake destruction when exposed to lower pH breaker fluids. Its filtercake did not need surfactant/solvent pills to change the wettability of the solids in the filtercake which notably simplified the borehole cleanup operation. The improvement occurred throughout the second and third phases of the field development. The ameliorations were measured through skin value, production and injectivity rates and initial flow initiation pressure. Values were compared against initial targets. As an example, the skin value went from 150 in phase one to less than 5 in phase three. No acid stimulation was required in any of these wells, providing a huge cost saving for the operator. The combination of the fluids selected, and improved drilling and completion practices led to skin values for most between 0 and 3. The productivity and injectivity outperformed and surpassed expectations.\u0000 Knowledge gained from the study re-established the importance of selecting the suitable fluids systems and using best in class drilling and completion practices. This paper summarizes upfront fluid design requirements and fluids management procedures implemented during drilling, completion and filtercake breaker placement to ensure safe and successful open hole completions.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77954807","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}
Raden Yoliandri Susilo, Narmina Yahyayeva, Luis Saavedra, S. Loboguerrero, Gumru Akhundova, Ali Rasul-zade, K. Whaley
Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations with oil column up-to 1000m, and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. Development began in 1997 and to date more than 130 high rate OHGPs have been installed. Once existing wells has been uneconomically to be produced, a Sidetrack or Up-Hole Recompletion (UHRC) will be performed. The standard 9-5/8" sidetrack technique will be done by drilling new section, installing and cemented a 7-5/8" liner, then drilling 6.5"x8" hole in pay zone followed by running 4" Shunted Screen and gravel packing. Previously C&P technique has been used for UHRC option but it was producing at limited drawdown and quickly sand up when water break through. Cased Hole Gravel Pack (CHGP) technique has been trialed as UHRC option in the past 2 years but has limitation of the number zone & length can be perforated which resulted in leaving some zones unperforated behind casing. A new concept of UHRC has been designed and successfully tested. This concept consists of sidetracking into the overburden, drilling to TD and removing 7-5/8" liner section. Shunted screen then deployed into open hole through a cased milled window followed by gravel pack operation. While standalone screens have been deployed through cased milled windows before, deploying shunted screens through a cased milled window followed by an OHGP is an industry 1st. This technique delivers the well 20 days earlier compare to standard Sidetrack OHGP well due to removal 7-5/8" production liner section. This technique is also give advantage over stacked CHGP option because can provide higher k*h access, can handle high levels of differential depletion within the completed interval and has the potential to unlock up lot more well candidates to allow and deplete the reserves from overlying reservoirs. This paper will also describe window and well design to deliver successful Shunt Tubes OHGP installation with this technique.
{"title":"Industry First: Shunt Tubes Open Hole Gravel Pack Completion Through 9-5/8\" Milled Casing Window in ACG Field, Azerbaijan","authors":"Raden Yoliandri Susilo, Narmina Yahyayeva, Luis Saavedra, S. Loboguerrero, Gumru Akhundova, Ali Rasul-zade, K. Whaley","doi":"10.2118/208859-ms","DOIUrl":"https://doi.org/10.2118/208859-ms","url":null,"abstract":"\u0000 Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations with oil column up-to 1000m, and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. Development began in 1997 and to date more than 130 high rate OHGPs have been installed.\u0000 Once existing wells has been uneconomically to be produced, a Sidetrack or Up-Hole Recompletion (UHRC) will be performed. The standard 9-5/8\" sidetrack technique will be done by drilling new section, installing and cemented a 7-5/8\" liner, then drilling 6.5\"x8\" hole in pay zone followed by running 4\" Shunted Screen and gravel packing. Previously C&P technique has been used for UHRC option but it was producing at limited drawdown and quickly sand up when water break through. Cased Hole Gravel Pack (CHGP) technique has been trialed as UHRC option in the past 2 years but has limitation of the number zone & length can be perforated which resulted in leaving some zones unperforated behind casing.\u0000 A new concept of UHRC has been designed and successfully tested. This concept consists of sidetracking into the overburden, drilling to TD and removing 7-5/8\" liner section. Shunted screen then deployed into open hole through a cased milled window followed by gravel pack operation. While standalone screens have been deployed through cased milled windows before, deploying shunted screens through a cased milled window followed by an OHGP is an industry 1st. This technique delivers the well 20 days earlier compare to standard Sidetrack OHGP well due to removal 7-5/8\" production liner section. This technique is also give advantage over stacked CHGP option because can provide higher k*h access, can handle high levels of differential depletion within the completed interval and has the potential to unlock up lot more well candidates to allow and deplete the reserves from overlying reservoirs.\u0000 This paper will also describe window and well design to deliver successful Shunt Tubes OHGP installation with this technique.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"189 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87214701","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}
Oil production is accompanied by water production in various ratios. This poses additional challenges to the industry as oftentimes the typically immiscible liquids form stable emulsions that need to be broken further and the two phases separated, incurring supplemental production costs. In stimulation operations such as hydraulic fracturing or acidizing, emulsions can form due to the presence of aromatic and naphthenic compounds in the crude oil along with surfactants present in the pumped fluid. Additional complications arise in the acidizing treatments since the acids used can further stabilize the emulsion with crude oil, making the phase separation even more difficult. This paper discusses simple 3- and 4-component formulations based on non-ionic surfactants and solvent/co-solvent that were successfully used as demulsifiers (DE), non-emulsifiers (NE) and weakly emulsifiers (WE) over a range of medium and heavy crude oils. A range of 3 medium and heavy crude oils were emulsified in a 1:1 ratio with either synthetic seawater or with 15-20% HCl. A composition analysis was run on the selected crude oils to determine the likelihood of the best formulation candidates to maintain their effectiveness in other crude oils. A comprehensive solvent/surfactant screening was performed aiming to find the best formulation that would work in each case. The best performers from the screening were further optimized and tested against commercial demulsifiers and their performance evaluated and discussed. The study resulted in the design of a few successful formulations that showed great performance over the range of crude oils utilized. The top candidates consisted of a 4-component formulation for the high brine and a 3-component formulation for the acidizing application and they worked well both as NE and as DE. Other formulations showed good performance as WE. The NE/DE compositions met the general performance criteria of providing complete phase separation within 5 minutes and with no emulsification. The WE formulations provided similar performance with the only difference that some emulsification occurred, as evidenced by the water layer taking up a slight color. The formulations discussed in this paper provide the operator with a series of benefits, among which: on par or better performance with similar commercial products, do not involve use of polymers that can have adverse effects on the downhole formation or pose supplemental challenges during downstream processing and have a better environmental profile, as they are not based on phenol, amine or sulfonate derivatives.
{"title":"Performant Non-Emulsifiers for High-Brine and Acidizing Applications","authors":"C. Stanciu, Jorge Fernandez, Khatere Sokhanvarian","doi":"10.2118/208805-ms","DOIUrl":"https://doi.org/10.2118/208805-ms","url":null,"abstract":"\u0000 Oil production is accompanied by water production in various ratios. This poses additional challenges to the industry as oftentimes the typically immiscible liquids form stable emulsions that need to be broken further and the two phases separated, incurring supplemental production costs. In stimulation operations such as hydraulic fracturing or acidizing, emulsions can form due to the presence of aromatic and naphthenic compounds in the crude oil along with surfactants present in the pumped fluid. Additional complications arise in the acidizing treatments since the acids used can further stabilize the emulsion with crude oil, making the phase separation even more difficult. This paper discusses simple 3- and 4-component formulations based on non-ionic surfactants and solvent/co-solvent that were successfully used as demulsifiers (DE), non-emulsifiers (NE) and weakly emulsifiers (WE) over a range of medium and heavy crude oils.\u0000 A range of 3 medium and heavy crude oils were emulsified in a 1:1 ratio with either synthetic seawater or with 15-20% HCl. A composition analysis was run on the selected crude oils to determine the likelihood of the best formulation candidates to maintain their effectiveness in other crude oils. A comprehensive solvent/surfactant screening was performed aiming to find the best formulation that would work in each case. The best performers from the screening were further optimized and tested against commercial demulsifiers and their performance evaluated and discussed.\u0000 The study resulted in the design of a few successful formulations that showed great performance over the range of crude oils utilized. The top candidates consisted of a 4-component formulation for the high brine and a 3-component formulation for the acidizing application and they worked well both as NE and as DE. Other formulations showed good performance as WE. The NE/DE compositions met the general performance criteria of providing complete phase separation within 5 minutes and with no emulsification. The WE formulations provided similar performance with the only difference that some emulsification occurred, as evidenced by the water layer taking up a slight color.\u0000 The formulations discussed in this paper provide the operator with a series of benefits, among which: on par or better performance with similar commercial products, do not involve use of polymers that can have adverse effects on the downhole formation or pose supplemental challenges during downstream processing and have a better environmental profile, as they are not based on phenol, amine or sulfonate derivatives.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86691425","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}
Rahman Ashena, Hossein Bahreini, A. Ghalambor, E. Sahraei, Majid Ahmad Loi Darab
In Managed Pressure Drilling (MPD), it is possible to drill holes that simultaneously expose formations with narrow safe mud windows and with pore pressures close to the fracture pressures of other exposed formations with minimal formation influx or mud losses, and also minimal future formation damage during production. In Continuous Circulation Systems (CCS), as a sub-class of MPD, the dynamic or circulating pressure is adjusted to control formation pressures. Therefore, the key factor in success of CCS and prevention of unprecedented formation damage is Equivalent Circulating Density (ECD). This is because a small error in calculation of the ECD can cause a kick influx or drilling fluid loss. Therefore, there is a strong need to investigate the effects of various parameters affecting ECD, which is the objective of this work. In this study, a section of a vertical annulus was simulated using Computational Fluid Dynamics (CFD) in 3-D and 2D to determine the effects of different affecting parameters on ECD. The seven investigated parameters in this section consist of DP rotational speed, eccentricity, rate of penetration (ROP), cuttings size, drilling fluid density, rheological parameters, and radius ratio (of drill-pipe OD to wellbore diameter). The CFD simulation results show that the ECD of MPD may be significantly affected by the aforementioned parameters. The ECD shows to change due to unprecedented change of the aforementioned affecting parameters. This can potentially jeopardize the MPD drilling operation success. Among the parameters, in laminar flow, radius ratio Yield Point and ROP showed the greatest effect on ECD whereas in turbulent flow radius ratio, PV and mud density showed to have the greatest effect with the other parameters to have minimal effects.
{"title":"Investigation of Parameters Controlling Equivalent Circulating Density ECD in Managed Pressure Drilling MPD","authors":"Rahman Ashena, Hossein Bahreini, A. Ghalambor, E. Sahraei, Majid Ahmad Loi Darab","doi":"10.2118/208869-ms","DOIUrl":"https://doi.org/10.2118/208869-ms","url":null,"abstract":"\u0000 In Managed Pressure Drilling (MPD), it is possible to drill holes that simultaneously expose formations with narrow safe mud windows and with pore pressures close to the fracture pressures of other exposed formations with minimal formation influx or mud losses, and also minimal future formation damage during production. In Continuous Circulation Systems (CCS), as a sub-class of MPD, the dynamic or circulating pressure is adjusted to control formation pressures. Therefore, the key factor in success of CCS and prevention of unprecedented formation damage is Equivalent Circulating Density (ECD). This is because a small error in calculation of the ECD can cause a kick influx or drilling fluid loss. Therefore, there is a strong need to investigate the effects of various parameters affecting ECD, which is the objective of this work.\u0000 In this study, a section of a vertical annulus was simulated using Computational Fluid Dynamics (CFD) in 3-D and 2D to determine the effects of different affecting parameters on ECD. The seven investigated parameters in this section consist of DP rotational speed, eccentricity, rate of penetration (ROP), cuttings size, drilling fluid density, rheological parameters, and radius ratio (of drill-pipe OD to wellbore diameter).\u0000 The CFD simulation results show that the ECD of MPD may be significantly affected by the aforementioned parameters. The ECD shows to change due to unprecedented change of the aforementioned affecting parameters. This can potentially jeopardize the MPD drilling operation success. Among the parameters, in laminar flow, radius ratio Yield Point and ROP showed the greatest effect on ECD whereas in turbulent flow radius ratio, PV and mud density showed to have the greatest effect with the other parameters to have minimal effects.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"58 5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83558060","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. Fuller, Sandra Gomez-Nava, Wade Williams, Lanre Olabinjo
For nearly every producing field worldwide, acid stimulation is a type of intervention that is critical to longevity in production (or injection) for those wells. However, compared to other completions/intervention operations (e.g., cementing and hydraulic fracturing), several deficiencies have been identified in the historical training curriculum for acid stimulation. Legacy acid stimulation training is largely focused on the basic aspects of matrix stimulation, excluding many practical and contemporary topics. The current work details the development of an innovative, operations-focused training program for acid stimulation intended to augment historical training. To commission the development of new stimulation training curriculum, stakeholders from operations, management, and the technical function (subject matter experts) brainstormed the most critical needs for practical training that would add value to operations beyond current internal/external training material. From this, customized training material was built that includes new focus areas including a) Mature well stimulation: workflows were developed to prioritize likely types of damage that cause productivity/injectivity decline based on existing well data. These workflows led to further training regarding damage-focused stimulation design (rather than pure matrix/mineralogy-based design), to optimize stimulation/fluid selection to target specific damage in mature producers. b) Complex well stimulation: this includes customized training material related to stimulation of existing sand control completions, infant wells (unproduced), and laminated carbonate/sandstone pay zones. c) Operational considerations: this new training material addressed operational best practices including topics on specialized placement methods; on-site QA; and interpretation of pressure data (during stimulation). d) Practical experience: the last aspect of the new training material includes students designing acid stimulation treatments for real candidate wells. The new operations-focused training material was piloted with several operations teams in 1-week intensive sessions, following the first week of (existing) basic acid stimulation training. This training (deployed both in-person and remotely) was well received by both the operations management and the students, who noted the enhanced relevance of the new curriculum to the production enhancement plans for the wells for which they are responsible. Additionally, the interactive team-activities to design stimulation programs for challenging wells (challenging mineralogy and existing sand control completions, multiple damage mechanisms, and wellbore mechanical obstructions) helped to improve acidizing designs for actual candidate wells through feedback from other students and class mentors. This work highlights the development and implementation of new training curriculum for acid stimulation design and execution, developed to improve the practical ski
{"title":"Development of Practical, Operations-Focused Training Curriculum for Acid Stimulation","authors":"M. Fuller, Sandra Gomez-Nava, Wade Williams, Lanre Olabinjo","doi":"10.2118/208863-ms","DOIUrl":"https://doi.org/10.2118/208863-ms","url":null,"abstract":"For nearly every producing field worldwide, acid stimulation is a type of intervention that is critical to longevity in production (or injection) for those wells. However, compared to other completions/intervention operations (e.g., cementing and hydraulic fracturing), several deficiencies have been identified in the historical training curriculum for acid stimulation. Legacy acid stimulation training is largely focused on the basic aspects of matrix stimulation, excluding many practical and contemporary topics. The current work details the development of an innovative, operations-focused training program for acid stimulation intended to augment historical training. To commission the development of new stimulation training curriculum, stakeholders from operations, management, and the technical function (subject matter experts) brainstormed the most critical needs for practical training that would add value to operations beyond current internal/external training material. From this, customized training material was built that includes new focus areas including a) Mature well stimulation: workflows were developed to prioritize likely types of damage that cause productivity/injectivity decline based on existing well data. These workflows led to further training regarding damage-focused stimulation design (rather than pure matrix/mineralogy-based design), to optimize stimulation/fluid selection to target specific damage in mature producers. b) Complex well stimulation: this includes customized training material related to stimulation of existing sand control completions, infant wells (unproduced), and laminated carbonate/sandstone pay zones. c) Operational considerations: this new training material addressed operational best practices including topics on specialized placement methods; on-site QA; and interpretation of pressure data (during stimulation). d) Practical experience: the last aspect of the new training material includes students designing acid stimulation treatments for real candidate wells. The new operations-focused training material was piloted with several operations teams in 1-week intensive sessions, following the first week of (existing) basic acid stimulation training. This training (deployed both in-person and remotely) was well received by both the operations management and the students, who noted the enhanced relevance of the new curriculum to the production enhancement plans for the wells for which they are responsible. Additionally, the interactive team-activities to design stimulation programs for challenging wells (challenging mineralogy and existing sand control completions, multiple damage mechanisms, and wellbore mechanical obstructions) helped to improve acidizing designs for actual candidate wells through feedback from other students and class mentors. This work highlights the development and implementation of new training curriculum for acid stimulation design and execution, developed to improve the practical ski","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79195463","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}
Abolfazl Hashemi, S. Borazjani, B. Dang-Le, Grace Yin Loi, Cuong Nguyen Cao, A. Badalyan, P. Bedrikovetsky
Fines migration is one of the most drastic causes for formation damage - the detached clays migrate and impairs well productivity. Two types of damaging clays are encountered in petroleum reservoirs: authigenic clays that grew on the grain surfaces during geological times, and detrital clays that have been broken off the grains by local stresses. Detailed laboratory and mathematical modelling have been carried out for detrital-clay formation damage. The theory for formation damage by authigenic clays is not available. The aim of this work is the development of a laboratory procedure to estimate formation damage by authigenic clays and the derivation of a mathematical model for core scale. We performed two test of corefloods using Castlegate core samples. In the first test, injection rate increased in a stepwise manner up to 100 mL/min and in the second one up to a 200mL/min to make sure both detrital and authigenic particles are detached. The pressure drop across the overall core and the concentration of the fine in the produced fluid have been measured. We have derived equations for authigenic-fines detachment using the beam theory and the von Mises failure criteria to obtain analytical solutions for linear system of equations. Matching the laboratory data by the analytical model allows determining the percentage of authigenic and detrital clays in the cores. The laboratory data exhibit a good match with the mathematical model for the two coreflood tests. The non-monotonic change of the concentration of the detached fine, with the initial and final risings, determines the type curve that evidence the mobilization of both, authigenic and detrital clays. The treatment of the measured data in test#2 shows that 82% of the initial attached particles are authigenic. The model parameters in order of decrease of their sensitivity are contact-bond radius, pore radius, particle size, lever-arm ratio, tensile strength and aspect ratio. A novel experimental procedure to determine fines-migration formation damage by authigenic and detrital clays was developed. A newly derived mathematical model allows determining the model coefficients from the laboratory tests and predict future detachment rate of authigenic and detrital particles.
{"title":"Formation Damage by Fines Breakage and Migration","authors":"Abolfazl Hashemi, S. Borazjani, B. Dang-Le, Grace Yin Loi, Cuong Nguyen Cao, A. Badalyan, P. Bedrikovetsky","doi":"10.2118/208810-ms","DOIUrl":"https://doi.org/10.2118/208810-ms","url":null,"abstract":"\u0000 Fines migration is one of the most drastic causes for formation damage - the detached clays migrate and impairs well productivity. Two types of damaging clays are encountered in petroleum reservoirs: authigenic clays that grew on the grain surfaces during geological times, and detrital clays that have been broken off the grains by local stresses. Detailed laboratory and mathematical modelling have been carried out for detrital-clay formation damage. The theory for formation damage by authigenic clays is not available. The aim of this work is the development of a laboratory procedure to estimate formation damage by authigenic clays and the derivation of a mathematical model for core scale. We performed two test of corefloods using Castlegate core samples. In the first test, injection rate increased in a stepwise manner up to 100 mL/min and in the second one up to a 200mL/min to make sure both detrital and authigenic particles are detached. The pressure drop across the overall core and the concentration of the fine in the produced fluid have been measured. We have derived equations for authigenic-fines detachment using the beam theory and the von Mises failure criteria to obtain analytical solutions for linear system of equations. Matching the laboratory data by the analytical model allows determining the percentage of authigenic and detrital clays in the cores. The laboratory data exhibit a good match with the mathematical model for the two coreflood tests. The non-monotonic change of the concentration of the detached fine, with the initial and final risings, determines the type curve that evidence the mobilization of both, authigenic and detrital clays. The treatment of the measured data in test#2 shows that 82% of the initial attached particles are authigenic. The model parameters in order of decrease of their sensitivity are contact-bond radius, pore radius, particle size, lever-arm ratio, tensile strength and aspect ratio. A novel experimental procedure to determine fines-migration formation damage by authigenic and detrital clays was developed. A newly derived mathematical model allows determining the model coefficients from the laboratory tests and predict future detachment rate of authigenic and detrital particles.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78877448","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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