The aim of this work is to develop an analytical technique for characterizing formation damage. The oil reservoir of the East Siberian Yaraktinskoe field suffers from salt and organic scales precipitation leading to skin damage. Besides, injection water has sulfates, which precipitate as gypsum in the near wellbore area of production wells and at bottomhole. Historically pressure build-ups (PBU) were used to characterize the evolution and extent of the damage. The use of PBUs leads to the shut in of production. Additionally PBUs in the reservoir provide conclusive results in no more than 22% cases. Based on inconsistent results from PBUs and their cost in production losses, it was of interest to find a better and preferable technique for formation damage control using existing data. The result of that initiative is analytical technique that provides dimensionless productivity index (Jd) range monitoring over time, Jd range comparison to the technical potential and identification of the performance gap range. By identifying the performance gap range, stimulation actions are ordered reestablishing oil production, productivity index (PI) and Jd. The technique is based on transmissibility (kh/µB or T) model derived from Kamal and Pan study (2010) and reservoir pressure (Pres or P) model. Stochastic part of the technique is provided by T and Pres error functions. The functions are probability distribution functions (PDF) derived from comparison of the modeled T and Pres with well test measured historical values. Using this T and Pres models and historical data of liquid rates and bottomhole pressures (BHP), we can calculate current and historical Jd, Jd drop relative to historical performance or potential and oil rate potential increment with uncertainty margins (10th, 50th and 90th percentile or P10-50-90). The margins are calculated from 10000 stochastic iterations of T and Pres within the PDFs of their error. The technique has enabled to find 14 stimulation candidates during 6 month of use. Overall, 15 stimulations were implemented since one well was stimulated twice. Ten of 14 stimulations increased oil production rate by 4161 bbl/day. Five stimulations were economically unsuccessful due to inappropriate stimulation technology implementation. The technique shows acceptable uncertainty level to make efficient and appropriate decisions for the appropriately chosen stimulation technology. Modeled P50 PIs have good match with more than 85% correlation with well test measured PIs after economically successful stimulation. New analytical technique is presented here, which can be utilized as an automatic process without repeating well tests for routine generation of accurate stimulation plan with numerical assessment of success probability and anticipated oil rate increment uncertainty range. Realization of stimulation potential is simplified to the task of appropriate treatment technology selection and implementation for the candidates from the r
{"title":"Uncertainty Driven Formation Damage Control Using Analytical Technique","authors":"A. Andryushchenko, A. Ghalambor","doi":"10.2118/208837-ms","DOIUrl":"https://doi.org/10.2118/208837-ms","url":null,"abstract":"\u0000 The aim of this work is to develop an analytical technique for characterizing formation damage.\u0000 The oil reservoir of the East Siberian Yaraktinskoe field suffers from salt and organic scales precipitation leading to skin damage. Besides, injection water has sulfates, which precipitate as gypsum in the near wellbore area of production wells and at bottomhole. Historically pressure build-ups (PBU) were used to characterize the evolution and extent of the damage. The use of PBUs leads to the shut in of production. Additionally PBUs in the reservoir provide conclusive results in no more than 22% cases. Based on inconsistent results from PBUs and their cost in production losses, it was of interest to find a better and preferable technique for formation damage control using existing data.\u0000 The result of that initiative is analytical technique that provides dimensionless productivity index (Jd) range monitoring over time, Jd range comparison to the technical potential and identification of the performance gap range. By identifying the performance gap range, stimulation actions are ordered reestablishing oil production, productivity index (PI) and Jd.\u0000 The technique is based on transmissibility (kh/µB or T) model derived from Kamal and Pan study (2010) and reservoir pressure (Pres or P) model. Stochastic part of the technique is provided by T and Pres error functions. The functions are probability distribution functions (PDF) derived from comparison of the modeled T and Pres with well test measured historical values. Using this T and Pres models and historical data of liquid rates and bottomhole pressures (BHP), we can calculate current and historical Jd, Jd drop relative to historical performance or potential and oil rate potential increment with uncertainty margins (10th, 50th and 90th percentile or P10-50-90). The margins are calculated from 10000 stochastic iterations of T and Pres within the PDFs of their error.\u0000 The technique has enabled to find 14 stimulation candidates during 6 month of use. Overall, 15 stimulations were implemented since one well was stimulated twice. Ten of 14 stimulations increased oil production rate by 4161 bbl/day. Five stimulations were economically unsuccessful due to inappropriate stimulation technology implementation. The technique shows acceptable uncertainty level to make efficient and appropriate decisions for the appropriately chosen stimulation technology. Modeled P50 PIs have good match with more than 85% correlation with well test measured PIs after economically successful stimulation.\u0000 New analytical technique is presented here, which can be utilized as an automatic process without repeating well tests for routine generation of accurate stimulation plan with numerical assessment of success probability and anticipated oil rate increment uncertainty range. Realization of stimulation potential is simplified to the task of appropriate treatment technology selection and implementation for the candidates from the r","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"7 10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73809733","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 Gramin, Karthik Mahadev, Prashant Haldipur, M. Pietrobon
Matrix acidizing, stimulation and other aqueous or solvent based pumping treatments such as scale squeezes, sand consolidation and organic deposition removal techniques play an ever-increasing role in maximizing value of high margin, high rate Deepwater wells. Near wellbore permeability impairment due to aqueous fluids capillary trap is a well-studied phenomenon in low permeability reservoirs but has not received much attention in high permeability oil reservoirs. During the execution of some of these different pumping treatments, an apparent formation damage was observed during execution in the form of lower productivity index (PI) post-treatment. In most cases, the PI impairment did not recover after the wells were brought online. In one case, the PI impairment slowly improved over time and fully recovered after the equivalent of ~1000 PV of the oil flow back. This temporary damage, in turn, created issues in terms of treatment design and execution often blurring the cause of damage and thereby affecting chemical and diverter selection and placement design variables. A laboratory study was undertaken to understand the nature of the damage. The results obtained from laboratory experiments to understand the impact of brines on effective permeability to oil are presented in this work. The results of the study are outlined below: Pore throat size distribution and degree of heterogeneity are principal factors controlling initial, short-term damage. Effective permeability reduction is related to non-uniform displacement by an alternate phase (oil or water), leaving less connected pores unswept. Long term damage depends on the flow rate / capillary number (Nc): High Rate / High Capillary Number results in short-term damage becoming permanent, Low rate / Low Capillary Number leads to gradual recovery over a long oil flowback period. Mutual solvents were not effective in removing the observed damage.
{"title":"Formation Damage Due to Aqueous Phase Traps in High Permeability Reservoirs and its Impact on Production Enhancement – Experimental Study","authors":"Pavel Gramin, Karthik Mahadev, Prashant Haldipur, M. Pietrobon","doi":"10.2118/208832-ms","DOIUrl":"https://doi.org/10.2118/208832-ms","url":null,"abstract":"\u0000 Matrix acidizing, stimulation and other aqueous or solvent based pumping treatments such as scale squeezes, sand consolidation and organic deposition removal techniques play an ever-increasing role in maximizing value of high margin, high rate Deepwater wells. Near wellbore permeability impairment due to aqueous fluids capillary trap is a well-studied phenomenon in low permeability reservoirs but has not received much attention in high permeability oil reservoirs. During the execution of some of these different pumping treatments, an apparent formation damage was observed during execution in the form of lower productivity index (PI) post-treatment. In most cases, the PI impairment did not recover after the wells were brought online. In one case, the PI impairment slowly improved over time and fully recovered after the equivalent of ~1000 PV of the oil flow back. This temporary damage, in turn, created issues in terms of treatment design and execution often blurring the cause of damage and thereby affecting chemical and diverter selection and placement design variables.\u0000 A laboratory study was undertaken to understand the nature of the damage. The results obtained from laboratory experiments to understand the impact of brines on effective permeability to oil are presented in this work.\u0000 The results of the study are outlined below:\u0000 Pore throat size distribution and degree of heterogeneity are principal factors controlling initial, short-term damage. Effective permeability reduction is related to non-uniform displacement by an alternate phase (oil or water), leaving less connected pores unswept. Long term damage depends on the flow rate / capillary number (Nc): High Rate / High Capillary Number results in short-term damage becoming permanent, Low rate / Low Capillary Number leads to gradual recovery over a long oil flowback period. Mutual solvents were not effective in removing the observed damage.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75857904","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. Panait, M. Zecheru, A. Dragomir, Auribel Dos Santos, F. Lopez
Because of the challenges commonly associated with matrix acidizing, chelating agents are increasingly reinforcing their good reputation as standalone alternative treatments in oil and gas wells worldwide. Systems based on GLDA and DTPA have been extensively used in tens of limestone and sandstone Romanian reservoirs over the past decade. This paper offers useful insights, design criteria and best practices based on substantial field experience that led to remarkable productivity boost in more than 50 wells. From deep and high temperature sour-wells, to shallower heavy oil plays. From inland oil producing assets to offshore gas condensate fields. Field applications included wells in sandstone, limestone and dolomite and placement involved foam and plain injection both via coiled tubing and bull-heading. The different stimulation campaigns involved a comprehensive laboratory evaluation, structured damage assessment followed by detailed treatment designs and execution. Experiments included both core-flood tests through limestone cores at 120 deg. C and solubility evaluation of mineral deposition at downhole conditions after scale characterization showed presence of sulphate-rich minerals like CaSO4 and BaSO4. Results of experimental evaluation showed creation of highly conductive wormholes without signs of face dissolution despite low injectivity. Solubility of challenging scales achieved dissolution from 43% to 78% in formulations containing DTPA and GLDA. Fully compatible with well completion components including sensitive equipment and jewelry like ESP was found. Bottle tests using challenging heavy crude oil demonstrated not only complete compatibility without signs of sludge, emulsions or precipitates but it also exhibited unexpected benefits in viscosity reduction during lab evaluation and field implementation. Experimental evaluations were followed by field execution that covered over 60 matrix stimulation treatments across 10 fields using chelating agent-based formulations of Glutamic-Acid-Diacetic-Acid (GLDA) and Diethylene-Triamine-Pentaacetic-Acid (DTPA). The outcome was a substantial increase in wells productivity with 2-3 times of improvement (TOI) in average and 30 % reduction of downtime without safety, environmental or asset integrity issues. Field results achieved and summarized in this paper demonstrate the efficacy of the methodology employed for productivity diagnosis. In addition, the numerous benefits of using chelating agents as standalone stimulation systems were corroborated. Described criteria and lessons learned represent a concise and useful tool to facilitate fluid selection and matrix treatment design in challenging field conditions with multi-functioning, non-corrosive, biodegradable and safe chemicals.
{"title":"Matrix Stimulation Treatments Using Non-Corrosive and Environmentally Friendly Systems: A Decade of Experience Across a Variety of Romanian Fields","authors":"E. Panait, M. Zecheru, A. Dragomir, Auribel Dos Santos, F. Lopez","doi":"10.2118/208841-ms","DOIUrl":"https://doi.org/10.2118/208841-ms","url":null,"abstract":"\u0000 Because of the challenges commonly associated with matrix acidizing, chelating agents are increasingly reinforcing their good reputation as standalone alternative treatments in oil and gas wells worldwide. Systems based on GLDA and DTPA have been extensively used in tens of limestone and sandstone Romanian reservoirs over the past decade. This paper offers useful insights, design criteria and best practices based on substantial field experience that led to remarkable productivity boost in more than 50 wells.\u0000 From deep and high temperature sour-wells, to shallower heavy oil plays. From inland oil producing assets to offshore gas condensate fields. Field applications included wells in sandstone, limestone and dolomite and placement involved foam and plain injection both via coiled tubing and bull-heading. The different stimulation campaigns involved a comprehensive laboratory evaluation, structured damage assessment followed by detailed treatment designs and execution. Experiments included both core-flood tests through limestone cores at 120 deg. C and solubility evaluation of mineral deposition at downhole conditions after scale characterization showed presence of sulphate-rich minerals like CaSO4 and BaSO4.\u0000 Results of experimental evaluation showed creation of highly conductive wormholes without signs of face dissolution despite low injectivity. Solubility of challenging scales achieved dissolution from 43% to 78% in formulations containing DTPA and GLDA. Fully compatible with well completion components including sensitive equipment and jewelry like ESP was found. Bottle tests using challenging heavy crude oil demonstrated not only complete compatibility without signs of sludge, emulsions or precipitates but it also exhibited unexpected benefits in viscosity reduction during lab evaluation and field implementation. Experimental evaluations were followed by field execution that covered over 60 matrix stimulation treatments across 10 fields using chelating agent-based formulations of Glutamic-Acid-Diacetic-Acid (GLDA) and Diethylene-Triamine-Pentaacetic-Acid (DTPA). The outcome was a substantial increase in wells productivity with 2-3 times of improvement (TOI) in average and 30 % reduction of downtime without safety, environmental or asset integrity issues.\u0000 Field results achieved and summarized in this paper demonstrate the efficacy of the methodology employed for productivity diagnosis. In addition, the numerous benefits of using chelating agents as standalone stimulation systems were corroborated. Described criteria and lessons learned represent a concise and useful tool to facilitate fluid selection and matrix treatment design in challenging field conditions with multi-functioning, non-corrosive, biodegradable and safe chemicals.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"269 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77167763","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}
Novel retarded acids were designed and evaluated by measuring their dissolution and corrosion rates in the laboratory at a temperature of 250°F. Results indicate that depending on the type of the retarder, the acid solutions containing 15 wt% HCl react 1.2–10.7 slower than 15 wt% straight HCl. In addition, novel retarded acids pass the industry standard for corrosion rate of L80, P110, T95, and 13Cr steel grades even with no corrosion inhibitor added to the formulation. Field application of the novel acid systems will provide a series of benefits, including ease to mix and pump, operational safety, deep stimulation of target zone, etc. Presented results are integral for designing the stimulation operations in carbonate reservoirs and the removal of carbonate scales in the oil and gas or geothermal energy industries.
{"title":"Novel Class of Retarded, Newtonian, Single-Phase HCl-Based Stimulation Fluids: A Laboratory Characterization","authors":"H. Samouei, Igor B. Ivanishin, A. Orangi","doi":"10.2118/208813-ms","DOIUrl":"https://doi.org/10.2118/208813-ms","url":null,"abstract":"\u0000 Novel retarded acids were designed and evaluated by measuring their dissolution and corrosion rates in the laboratory at a temperature of 250°F. Results indicate that depending on the type of the retarder, the acid solutions containing 15 wt% HCl react 1.2–10.7 slower than 15 wt% straight HCl. In addition, novel retarded acids pass the industry standard for corrosion rate of L80, P110, T95, and 13Cr steel grades even with no corrosion inhibitor added to the formulation. Field application of the novel acid systems will provide a series of benefits, including ease to mix and pump, operational safety, deep stimulation of target zone, etc. Presented results are integral for designing the stimulation operations in carbonate reservoirs and the removal of carbonate scales in the oil and gas or geothermal energy industries.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81449847","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}
Kirsty Houston, N. Fleming, Julya Jennifer Bonkat, H. Kaarigstad, J. Barclay, R. Watson, P. Viste
The Mariner Field consists of two shallow heavy oil reservoir sections: the deeper Maureen Formation and the shallower Heimdal Reservoir. Produced water is re-injected through stand-alone screens providing pressure maintenance for the aquifer support and producer well life longevity. The challenge is to design a drill-in fluid for the injectors to allow matrix injection across the sand face. This improves the longevity of the lower completion screens by reducing hot spot completion damage created by the injection fluid (Yildiz, 2004). It also improves the pressure support for the producing wells. Equinor is committed to using sustainable, environmentally sound drilling fluid options. Therefore, the preference was to utilize a water-based drilling fluid with the application of a breaker after the lower completion was in place. A significant formation damage study was performed using various designs of water-based fluids. Each formulation utilized a biopolymer to provide viscosity and rheological support. The sands were unconsolidated and sand packs had to be created to mimic the reservoir characteristics of the Maureen reservoir. This potentially impacted the formation damage interpretation. From the formation damage study, biopolymer was highlighted as a limiting damage mechanism. This prompted both Equinor and Schlumberger to look at alternative ways to provide rheological support without using biopolymers. A mono-valent biopolymer free reservoir drill-in fluid was designed specifically for this challenging high Darcy reservoir to mitigate the formation damage seen from coreflooding. This paper will detail the design, testing, diagnostic analysis of the formation damage mechanism and the new biopolymer free fluid. Together they showed a step change improvement in the formation damage testing. In addition, the paper will also detail the deployment of the new fluid on Mariner. Furthermore, it will describe how the laboratory design translated into large scale plant mixing with deployment at the rig site.
{"title":"Innovative Water Based Mud Design to Improve Formation Damage Results on Mariner Field","authors":"Kirsty Houston, N. Fleming, Julya Jennifer Bonkat, H. Kaarigstad, J. Barclay, R. Watson, P. Viste","doi":"10.2118/208844-ms","DOIUrl":"https://doi.org/10.2118/208844-ms","url":null,"abstract":"\u0000 The Mariner Field consists of two shallow heavy oil reservoir sections: the deeper Maureen Formation and the shallower Heimdal Reservoir. Produced water is re-injected through stand-alone screens providing pressure maintenance for the aquifer support and producer well life longevity. The challenge is to design a drill-in fluid for the injectors to allow matrix injection across the sand face. This improves the longevity of the lower completion screens by reducing hot spot completion damage created by the injection fluid (Yildiz, 2004). It also improves the pressure support for the producing wells.\u0000 Equinor is committed to using sustainable, environmentally sound drilling fluid options. Therefore, the preference was to utilize a water-based drilling fluid with the application of a breaker after the lower completion was in place. A significant formation damage study was performed using various designs of water-based fluids. Each formulation utilized a biopolymer to provide viscosity and rheological support. The sands were unconsolidated and sand packs had to be created to mimic the reservoir characteristics of the Maureen reservoir. This potentially impacted the formation damage interpretation.\u0000 From the formation damage study, biopolymer was highlighted as a limiting damage mechanism. This prompted both Equinor and Schlumberger to look at alternative ways to provide rheological support without using biopolymers. A mono-valent biopolymer free reservoir drill-in fluid was designed specifically for this challenging high Darcy reservoir to mitigate the formation damage seen from coreflooding. This paper will detail the design, testing, diagnostic analysis of the formation damage mechanism and the new biopolymer free fluid. Together they showed a step change improvement in the formation damage testing. In addition, the paper will also detail the deployment of the new fluid on Mariner. Furthermore, it will describe how the laboratory design translated into large scale plant mixing with deployment at the rig site.","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":"85071258","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}
Kesavan Govinathan, J. Sallis, Samyak Jain, R. Tibbles, Mike Foster, Bart Waltman
High Rate Water Pack (HRWP) treatments are used in cased hole gravel packs with the intention of creating small fractures to bypass near wellbore damage and improve perforation packing. Despite their popularity as a sand control technique, there has never been a software model developed specifically for HRWP treatments, and so their design has been largely driven by trial-and-error based on local field experience. Often, local field experience is insufficient to achieve the desired results due to uncertainties in the fracture initiation, propagation and packing mechanisms. The ability to model the initiation and packing of the fracture provides a better understanding of the achievable perforation packing in a specific well and how to maximize it. Such a model must simultaneously simulate fluid hydraulics, wellbore packing, fracture initiation and propagation, and gravel placement. Models exist for gravel packing that can predict packing in the wellbore annulus and perforations, but they do not account for initiation, propagation and packing of the fractures. Multiple models are also available specifically for fracturing design, but most of these do not account for wellbore packing. These models are more suited for conventional hydraulic fracturing and frac pack treatments using highly viscous or crosslinked fluids. Such fracturing models tend to overpredict fluid leak-off in soft rock formations, especially with low viscosity fluids, and consequently predict premature screen-outs under conditions in which HRWP treatments are in practice successfully placed. This paper introduces the first software model that combines both wellbore and perforation packing, along with the initiation and packing of small fractures, to facilitate successful HRWP treatments. Examples of how the model can be used to optimize HRWP treatments are discussed and the various parameters that impact HRWP design are also assessed. Several case studies are presented comparing modelled and actual data to both validate the model and demonstrate how it can be used to optimize the designs for offset wells.
{"title":"An Integrated Approach to the Design and Modelling of High Rate Water Pack Treatments","authors":"Kesavan Govinathan, J. Sallis, Samyak Jain, R. Tibbles, Mike Foster, Bart Waltman","doi":"10.2118/208812-ms","DOIUrl":"https://doi.org/10.2118/208812-ms","url":null,"abstract":"\u0000 High Rate Water Pack (HRWP) treatments are used in cased hole gravel packs with the intention of creating small fractures to bypass near wellbore damage and improve perforation packing. Despite their popularity as a sand control technique, there has never been a software model developed specifically for HRWP treatments, and so their design has been largely driven by trial-and-error based on local field experience.\u0000 Often, local field experience is insufficient to achieve the desired results due to uncertainties in the fracture initiation, propagation and packing mechanisms. The ability to model the initiation and packing of the fracture provides a better understanding of the achievable perforation packing in a specific well and how to maximize it. Such a model must simultaneously simulate fluid hydraulics, wellbore packing, fracture initiation and propagation, and gravel placement.\u0000 Models exist for gravel packing that can predict packing in the wellbore annulus and perforations, but they do not account for initiation, propagation and packing of the fractures. Multiple models are also available specifically for fracturing design, but most of these do not account for wellbore packing. These models are more suited for conventional hydraulic fracturing and frac pack treatments using highly viscous or crosslinked fluids. Such fracturing models tend to overpredict fluid leak-off in soft rock formations, especially with low viscosity fluids, and consequently predict premature screen-outs under conditions in which HRWP treatments are in practice successfully placed.\u0000 This paper introduces the first software model that combines both wellbore and perforation packing, along with the initiation and packing of small fractures, to facilitate successful HRWP treatments. Examples of how the model can be used to optimize HRWP treatments are discussed and the various parameters that impact HRWP design are also assessed. Several case studies are presented comparing modelled and actual data to both validate the model and demonstrate how it can be used to optimize the designs for offset wells.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87073189","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Barradas, Donato Viegas, Antonio Cabuco, D. Staltari, C. D. Jesus, Osvaldo Cazeze, Nadia Eduardo, D. D. Gianvittorio, Gaetano Vescera, Emmanuel Chikezie, Aurelio Bernardone, Russell Stimatze, B. Reilly, R. Ilyasov
Gravel-packed wells in the "C" field located in offshore Angola are prone to damage by a variety of factors including scales, fines migration, paraffin and asphaltene deposition resulting in skin values of 45-95. This paper focuses on the approach used for 2 subsea open hole gravel packed wells located within "C" field. Rigless subsea stimulations in approximately 470 m of water using an intervention vessel with the downline deployed via the vessel moonpool. Additionally, a stimulation vessel was utilized to provide pumping and fluid capacity without disturbing the primary intervention operations. This paper documents the efforts made to restore the wells forecasted production by bullheading the acid stimulation treatment from the stimulation vessel through the open-water hydraulic access system installed on the intervention vessel. Well history attributes the impairment to fines migration accumulation and scale and paraffins deposition. The proposed stimulation fluids were designed to treat as many damage mechanisms as possible during a single intervention. The basis for design incorporated a primary solvent pre-flush to clean possible paraffin and asphaltene deposition as well as prepare the reservoir and proppant pack for further stimulation fluids by stripping away hydrocarbon residue. The preflush was followed by a second treatment fluid consisting of HCl acid to remove any carbonate-based damage. The final treatment fluid utilizing a combination of HCl acid and hydrofluoric acid (HF) was specifically designed to remove fines contained in the gravel pack and screens. Injectivity tests were performed to evaluate the reservoir prior to and after the acid treatment as well as to help understand the damage mechanism. Based on the bottomhole pressure response during acid-treatment stages, measurable improvements were evident on both wells, which supports the pre-treatment damage diagnosis. The efficient and cost-effective execution of the treatment campaign, combined with the conclusive post-stimulation production data, confirms the effectiveness of open-water hydraulic access by utilizing an intervention vessel and a stimulation vessel, allowing to provide pumping and fluid capacity without disturbing the primary intervention operations on complex subsea wells. Post-stimulation results after the successful removal of wellbore scale and formation damage in the two subsea wells showed an average increase in oil production of 60%. Skin damage was reduced by 66% on Well A and a complete removal of skin on Well B. The results confirm the effectiveness of cost-driven acid stimulations on complex subsea wells without the use of a drilling rig as well as demonstrating the ability to address multiple damage mechanisms from a single intervention.
{"title":"Effective Sandstone Acidizing of Horizontal Openhole Subsea Wells from Intervention Vessel: Challenges, Lessons Learned and Results","authors":"O. Barradas, Donato Viegas, Antonio Cabuco, D. Staltari, C. D. Jesus, Osvaldo Cazeze, Nadia Eduardo, D. D. Gianvittorio, Gaetano Vescera, Emmanuel Chikezie, Aurelio Bernardone, Russell Stimatze, B. Reilly, R. Ilyasov","doi":"10.2118/208825-ms","DOIUrl":"https://doi.org/10.2118/208825-ms","url":null,"abstract":"\u0000 Gravel-packed wells in the \"C\" field located in offshore Angola are prone to damage by a variety of factors including scales, fines migration, paraffin and asphaltene deposition resulting in skin values of 45-95. This paper focuses on the approach used for 2 subsea open hole gravel packed wells located within \"C\" field. Rigless subsea stimulations in approximately 470 m of water using an intervention vessel with the downline deployed via the vessel moonpool. Additionally, a stimulation vessel was utilized to provide pumping and fluid capacity without disturbing the primary intervention operations.\u0000 This paper documents the efforts made to restore the wells forecasted production by bullheading the acid stimulation treatment from the stimulation vessel through the open-water hydraulic access system installed on the intervention vessel. Well history attributes the impairment to fines migration accumulation and scale and paraffins deposition. The proposed stimulation fluids were designed to treat as many damage mechanisms as possible during a single intervention. The basis for design incorporated a primary solvent pre-flush to clean possible paraffin and asphaltene deposition as well as prepare the reservoir and proppant pack for further stimulation fluids by stripping away hydrocarbon residue. The preflush was followed by a second treatment fluid consisting of HCl acid to remove any carbonate-based damage. The final treatment fluid utilizing a combination of HCl acid and hydrofluoric acid (HF) was specifically designed to remove fines contained in the gravel pack and screens. Injectivity tests were performed to evaluate the reservoir prior to and after the acid treatment as well as to help understand the damage mechanism.\u0000 Based on the bottomhole pressure response during acid-treatment stages, measurable improvements were evident on both wells, which supports the pre-treatment damage diagnosis. The efficient and cost-effective execution of the treatment campaign, combined with the conclusive post-stimulation production data, confirms the effectiveness of open-water hydraulic access by utilizing an intervention vessel and a stimulation vessel, allowing to provide pumping and fluid capacity without disturbing the primary intervention operations on complex subsea wells.\u0000 Post-stimulation results after the successful removal of wellbore scale and formation damage in the two subsea wells showed an average increase in oil production of 60%. Skin damage was reduced by 66% on Well A and a complete removal of skin on Well B. The results confirm the effectiveness of cost-driven acid stimulations on complex subsea wells without the use of a drilling rig as well as demonstrating the ability to address multiple damage mechanisms from a single intervention.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90214470","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}
J. A. Barry, E. Esatyana, Karim Loutfy El Sayed, M. El-Husseiny, John Hagle
This study is focused on the application of novel pozzolans (superplasticizers) ahead of cement, prior to casing and while drilling to treat and prevent wellbore fracture due to overburden stresses. This study is a combination of quantitative and qualitative analysis based on laboratory and field applications of pozzolanic materials in the construction of wells. Pozzolans have long been applied to construction materials in order to improve lifespan and compressive strength. The application of pozzolanic materials goes back over 2000 years to the construction of Roman Aqueducts, buildings and roads known for their longevity and ability to resist corrosion and stress. These materials cover a broad range of naturally occurring and man-made materials. The most common pozzolanic materials used in drilling today include Bentonite, Kaolin, and Fly Ash. Pozzolans when combined with Portland Cement have been shown to increase the compressive strength and durability dramatically. Pozzolans are currently applied globally in cementing applications for HTHP, high loss zones and more. This paper will examine the application in the drilling phase as an applied treatment during drilling for the reinforcement of the wellbore as well as to treat induced losses. The study will review cases for use of Novel Pozzolans for drilling, pre-cement, casing and for production zones the application of Novel acid soluble pozzolans for similar purposes. These applications validate the application of these materials beyond cementing into the drilling phase and wellbore construction for reducing backside pressure, reducing days on losses, reducing sidetrack, increasing operational ECD while drilling and cementing and achieving top of cement without inducing losses due to overburden in tight ECD window environments. Deepwater environments provide a unique environment for the application of these novel materials as they offer some of the highest overburden environments with greatest operating costs and daily operating costs. Thusly this study has shown the applications have saved operators on multiple wells and over long periods many days and millions in operating costs with proven prevention of losses in field studies where wells were compared for offset value over a period of time. Multiple operators have adopted this technology as a result and there is a long track record of use while there are few papers on the subject. The purpose of this paper is to illustrate the best practices as well as new technologies and state of the art when it comes to the development of the latest in pozzolanics for these applications.
{"title":"Applications of Pozzolans to Treat Wellbore prior to Cement, Casing and While Drilling to Prevent Overburden Stress Fractures, Onshore US, Offshore Deepwater, and International Case Studies","authors":"J. A. Barry, E. Esatyana, Karim Loutfy El Sayed, M. El-Husseiny, John Hagle","doi":"10.2118/208866-ms","DOIUrl":"https://doi.org/10.2118/208866-ms","url":null,"abstract":"\u0000 This study is focused on the application of novel pozzolans (superplasticizers) ahead of cement, prior to casing and while drilling to treat and prevent wellbore fracture due to overburden stresses. This study is a combination of quantitative and qualitative analysis based on laboratory and field applications of pozzolanic materials in the construction of wells.\u0000 Pozzolans have long been applied to construction materials in order to improve lifespan and compressive strength. The application of pozzolanic materials goes back over 2000 years to the construction of Roman Aqueducts, buildings and roads known for their longevity and ability to resist corrosion and stress. These materials cover a broad range of naturally occurring and man-made materials. The most common pozzolanic materials used in drilling today include Bentonite, Kaolin, and Fly Ash. Pozzolans when combined with Portland Cement have been shown to increase the compressive strength and durability dramatically. Pozzolans are currently applied globally in cementing applications for HTHP, high loss zones and more.\u0000 This paper will examine the application in the drilling phase as an applied treatment during drilling for the reinforcement of the wellbore as well as to treat induced losses. The study will review cases for use of Novel Pozzolans for drilling, pre-cement, casing and for production zones the application of Novel acid soluble pozzolans for similar purposes. These applications validate the application of these materials beyond cementing into the drilling phase and wellbore construction for reducing backside pressure, reducing days on losses, reducing sidetrack, increasing operational ECD while drilling and cementing and achieving top of cement without inducing losses due to overburden in tight ECD window environments.\u0000 Deepwater environments provide a unique environment for the application of these novel materials as they offer some of the highest overburden environments with greatest operating costs and daily operating costs. Thusly this study has shown the applications have saved operators on multiple wells and over long periods many days and millions in operating costs with proven prevention of losses in field studies where wells were compared for offset value over a period of time. Multiple operators have adopted this technology as a result and there is a long track record of use while there are few papers on the subject. The purpose of this paper is to illustrate the best practices as well as new technologies and state of the art when it comes to the development of the latest in pozzolanics for these applications.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84917038","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. Wilson, Ewan Sheach, G. Graham, F. Azuddin, Y. A. Sazali, A. Sauri
Stimulation fluids are used for near-wellbore clean-up and either removal or bypass of formation damage or for improvement of the effective permeability. In carbonate reservoirs, typical formulations are most commonly based on HCl or organic acids, such as acetic or formic acid, which increase connectivity between the reservoir and wellbore by dissolving the rock matrix itself. However, how this occurs greatly influences the effectiveness of stimulation for a given amount of dissolution. By far the least effective stimulation mode is face dissolution, as this has very little benefit on inflow and can lead to deconsolidation and collapse of the near-wellbore area. This paper examines the selection of chemicals to reduce face dissolution and improve the efficiency of chemical treatments in carbonates via much more effective formation of conductive flow channels or wormholes. When acidizing carbonates, the morphology of the resultant wormholes is controlled by rock morphology, composition and heterogeneity, pump injection rate, temperature, and both physical and chemical properties of the stimulation fluid formulation. Effective fluids create long wormholes that penetrate away from the wellbore face, with only limited branching, thus (i) changing the inflow from simple radial flow to modified flow into the wormholes and (ii) bypassing near-wellbore formation damage if the dominant wormholes are sufficiently long. Reservoir condition Pore Volume to BreakThrough (PVBT) core flood tests were performed: initially applying a typical acid treatment at various injection rates and then comparing these with identical tests with a novel additive included. Fluid effectiveness was assessed based on measurement of PVBT. Micro Computed Tomography (CT) imaging and density difference mapping were used to visualize the wormholes formed. Rates of penetration were gained from differential pressure data combined with consideration of peak elution time of Ca2+ from the analysis of effluent samples. In tests performed on comparable outcrop limestone core samples, with the same injection flow rate, temperature, and acid concentration, the blended stimulation fluid performed very similarly in the presence and absence of the additive in terms of PVBT and Time to BreakThrough (TBT), showing that the stimulation fluid's performance was not hampered by the presence of the additive. However, while post-test micro-CT imaging of the core plugs revealed that the wormhole morphology was very similar in each case (as might be expected given the consistency in PVBT and TBT), there was a substantial reduction in the extent of undesirable face dissolution observed in presence of the additive. The effect was more pronounced at lower flow rates; poorer chemical transport typically leads to greater face dissolution problems. With the additive, there was also a substantially lower concentration of calcium ions in the effluent for a given set of conditions, despite the stimulation bein
{"title":"Stimulation Fluid Additives to Control Face Dissolution Tendency in Carbonate Reservoirs","authors":"S. Wilson, Ewan Sheach, G. Graham, F. Azuddin, Y. A. Sazali, A. Sauri","doi":"10.2118/208823-ms","DOIUrl":"https://doi.org/10.2118/208823-ms","url":null,"abstract":"\u0000 Stimulation fluids are used for near-wellbore clean-up and either removal or bypass of formation damage or for improvement of the effective permeability. In carbonate reservoirs, typical formulations are most commonly based on HCl or organic acids, such as acetic or formic acid, which increase connectivity between the reservoir and wellbore by dissolving the rock matrix itself. However, how this occurs greatly influences the effectiveness of stimulation for a given amount of dissolution. By far the least effective stimulation mode is face dissolution, as this has very little benefit on inflow and can lead to deconsolidation and collapse of the near-wellbore area. This paper examines the selection of chemicals to reduce face dissolution and improve the efficiency of chemical treatments in carbonates via much more effective formation of conductive flow channels or wormholes.\u0000 When acidizing carbonates, the morphology of the resultant wormholes is controlled by rock morphology, composition and heterogeneity, pump injection rate, temperature, and both physical and chemical properties of the stimulation fluid formulation. Effective fluids create long wormholes that penetrate away from the wellbore face, with only limited branching, thus (i) changing the inflow from simple radial flow to modified flow into the wormholes and (ii) bypassing near-wellbore formation damage if the dominant wormholes are sufficiently long.\u0000 Reservoir condition Pore Volume to BreakThrough (PVBT) core flood tests were performed: initially applying a typical acid treatment at various injection rates and then comparing these with identical tests with a novel additive included. Fluid effectiveness was assessed based on measurement of PVBT. Micro Computed Tomography (CT) imaging and density difference mapping were used to visualize the wormholes formed. Rates of penetration were gained from differential pressure data combined with consideration of peak elution time of Ca2+ from the analysis of effluent samples.\u0000 In tests performed on comparable outcrop limestone core samples, with the same injection flow rate, temperature, and acid concentration, the blended stimulation fluid performed very similarly in the presence and absence of the additive in terms of PVBT and Time to BreakThrough (TBT), showing that the stimulation fluid's performance was not hampered by the presence of the additive. However, while post-test micro-CT imaging of the core plugs revealed that the wormhole morphology was very similar in each case (as might be expected given the consistency in PVBT and TBT), there was a substantial reduction in the extent of undesirable face dissolution observed in presence of the additive. The effect was more pronounced at lower flow rates; poorer chemical transport typically leads to greater face dissolution problems. With the additive, there was also a substantially lower concentration of calcium ions in the effluent for a given set of conditions, despite the stimulation bein","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77583575","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}
Brittany Granger, J. Harton, Christopher Detiveaux
The Gulf of Mexico (GoM) presents an array of complex challenges, including ultra-deepwater depths, narrow pressure window environments, low permeability, and elevated temperature zones. Operators in the GoM frequently experience highly reactive, unstable shales while drilling long, heterogenous open hole lateral wells. While traditional Reservoir Drill-in Fluids (RDF) and breakers are well known for use in production wells, the filter cake cleanup can often be non-uniform, corrosive to completion assemblies, and result in variable drawdown. This disparity in pressure drawdown across the reservoir section can ultimately result in the creation of positive skin damage. Injector wells offer a more extreme scenario in comparison to production wells because no flowback occurs, which can make it more difficult to deliver sustainable uniform injection. The solution to these challenges lies in the development of RDF and breakers specifically tailored to provide uniform, time delayed coverage, minimal corrosivity, and effective removal of the RDF filter cake. In order to successfully maximize injection and maintain performance for the scope of the field life, an RDF was customized in tandem with an optimized, delayed-release filter cake breaker to limit formation damage and provide complete uniform filter cake removal. This paper will discuss how the learnings from Eastern Hemisphere operational activities directed at optimizing treatment designs for more difficult injector wells can be tailored for efficient use in the GoM. Results from laboratory testing and global field applications of the new RDF and breaker designs will be presented, as well.
{"title":"Specially Tailored Reservoir Drill-In Fluid and Acid Precursor Technology with Applicability in Ultra Deepwater Gulf of Mexico Wells","authors":"Brittany Granger, J. Harton, Christopher Detiveaux","doi":"10.2118/208855-ms","DOIUrl":"https://doi.org/10.2118/208855-ms","url":null,"abstract":"\u0000 The Gulf of Mexico (GoM) presents an array of complex challenges, including ultra-deepwater depths, narrow pressure window environments, low permeability, and elevated temperature zones. Operators in the GoM frequently experience highly reactive, unstable shales while drilling long, heterogenous open hole lateral wells. While traditional Reservoir Drill-in Fluids (RDF) and breakers are well known for use in production wells, the filter cake cleanup can often be non-uniform, corrosive to completion assemblies, and result in variable drawdown. This disparity in pressure drawdown across the reservoir section can ultimately result in the creation of positive skin damage. Injector wells offer a more extreme scenario in comparison to production wells because no flowback occurs, which can make it more difficult to deliver sustainable uniform injection. The solution to these challenges lies in the development of RDF and breakers specifically tailored to provide uniform, time delayed coverage, minimal corrosivity, and effective removal of the RDF filter cake. In order to successfully maximize injection and maintain performance for the scope of the field life, an RDF was customized in tandem with an optimized, delayed-release filter cake breaker to limit formation damage and provide complete uniform filter cake removal. This paper will discuss how the learnings from Eastern Hemisphere operational activities directed at optimizing treatment designs for more difficult injector wells can be tailored for efficient use in the GoM. Results from laboratory testing and global field applications of the new RDF and breaker designs will be presented, as well.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73475164","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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