S. Khare, Rahul Baid, J. Prusty, Nitesh Agrawal, A. Gupta
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study. Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously. The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction. The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost. Novel Technique: No standard industry software can help model such dual lift systems with ease. The in-house developed workflow allows engineers to successfully model such complex lift scenario for routine production optimization and well surveillance activities.
{"title":"Modelling and Implementation of Dual Artificial Lift System for Production Enhancement: A Successful Case Study of Aishwariya Field","authors":"S. Khare, Rahul Baid, J. Prusty, Nitesh Agrawal, A. Gupta","doi":"10.2118/194632-MS","DOIUrl":"https://doi.org/10.2118/194632-MS","url":null,"abstract":"\u0000 The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.\u0000 Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.\u0000 The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.\u0000 The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.\u0000 Novel Technique: No standard industry software can help model such dual lift systems with ease. The in-house developed workflow allows engineers to successfully model such complex lift scenario for routine production optimization and well surveillance activities.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81813951","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}
Krishna Bordeori, Vaibhav Gupta, Lovely Sharma, S. Narayan, Dhurba Talukdar, Tshering Lama
Cased hole gravel pack (CHGP) is the most popular method for controlling production of formation sand in oil or gas cased hole wells. CHGP involves the packing of screen and casing annulus, and perforations to inhibit production of formation sand. Success of a CHGP depends on various factors such as perforation packing, cleanliness of completion brine, perforation strategy and minimizing drawdown. Quality of perforation packing aids in minimizing drawdown of gravel pack completions. This led to popularization of high-rate water packs (HRWPs), an evolved sand control method for cased hole wells. HRWPs involve pumping above fracture extension rate and placing gravels outside casing into the critical matrix. This paper discusses maturation process in design, execution, and evaluation methodology devised from a campaign of 16 HRWPs, which included two formation breakdown acid injections, one slim hole completion, two re-stresses and one top-off. Naharkatiya fields of Oil India Limited, in Assam-Arakan basin are characterized with high degrees of unconsolidated formation sand. Elements of heterogeneity like formation sand ingression rate, PSD, mineralogy and well-profile in these two fields, where most of the HRWP treatments were executed, demanded case-specific pre-gravel-pack workover operations. Installation of screens and pumping of HRWP treatment presented many challenges, such as formation sand ingression, high circulation pressures, uneven slack/pull weights and issues in tool operations. All these challenges were tackled in unique ways and successful HRWP treatments were completed. A holistic approach was developed towards execution of a High Rate Water Pack treatment, by analyzing all interlinked elements such as perforations, cores, cement bond, reservoir saturation, water cut and offset well history. Post-treatment evaluation of HRWPs using bottomhole gauges identified a sequence of downhole events and potential issues during execution phase. Correlating each new HRWP candidate with learnings from previous ones allowed the operator to better plan workover steps towards execution of the sand control treatment. Contingency plans were devised to tackle issues learned from previous wells, and many were successfully tested in the campaign. Production rates and choke strategies were optimized by analysis of offset wells. This paper presents data analysis of wells while correlating with their offsets. Post-treatment analysis has been discussed and correlations between suspected issues during execution with signatures in bottom-hole gauge data have been presented. Recommendation are further provided for drilling and completion operations. Evolution in design and execution process for case wells has been presented, which can be used as a reference literature for designing case specific sand control treatment program.
{"title":"Evolution of High Rate Water Pack Pumping Methodology During Sand Control Campaign: A Case Study from India","authors":"Krishna Bordeori, Vaibhav Gupta, Lovely Sharma, S. Narayan, Dhurba Talukdar, Tshering Lama","doi":"10.2118/194560-MS","DOIUrl":"https://doi.org/10.2118/194560-MS","url":null,"abstract":"\u0000 Cased hole gravel pack (CHGP) is the most popular method for controlling production of formation sand in oil or gas cased hole wells. CHGP involves the packing of screen and casing annulus, and perforations to inhibit production of formation sand. Success of a CHGP depends on various factors such as perforation packing, cleanliness of completion brine, perforation strategy and minimizing drawdown. Quality of perforation packing aids in minimizing drawdown of gravel pack completions. This led to popularization of high-rate water packs (HRWPs), an evolved sand control method for cased hole wells. HRWPs involve pumping above fracture extension rate and placing gravels outside casing into the critical matrix. This paper discusses maturation process in design, execution, and evaluation methodology devised from a campaign of 16 HRWPs, which included two formation breakdown acid injections, one slim hole completion, two re-stresses and one top-off.\u0000 Naharkatiya fields of Oil India Limited, in Assam-Arakan basin are characterized with high degrees of unconsolidated formation sand. Elements of heterogeneity like formation sand ingression rate, PSD, mineralogy and well-profile in these two fields, where most of the HRWP treatments were executed, demanded case-specific pre-gravel-pack workover operations. Installation of screens and pumping of HRWP treatment presented many challenges, such as formation sand ingression, high circulation pressures, uneven slack/pull weights and issues in tool operations. All these challenges were tackled in unique ways and successful HRWP treatments were completed. A holistic approach was developed towards execution of a High Rate Water Pack treatment, by analyzing all interlinked elements such as perforations, cores, cement bond, reservoir saturation, water cut and offset well history. Post-treatment evaluation of HRWPs using bottomhole gauges identified a sequence of downhole events and potential issues during execution phase. Correlating each new HRWP candidate with learnings from previous ones allowed the operator to better plan workover steps towards execution of the sand control treatment. Contingency plans were devised to tackle issues learned from previous wells, and many were successfully tested in the campaign. Production rates and choke strategies were optimized by analysis of offset wells.\u0000 This paper presents data analysis of wells while correlating with their offsets. Post-treatment analysis has been discussed and correlations between suspected issues during execution with signatures in bottom-hole gauge data have been presented. Recommendation are further provided for drilling and completion operations. Evolution in design and execution process for case wells has been presented, which can be used as a reference literature for designing case specific sand control treatment program.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"173 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84181281","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. Gupta, J. Sukanandan, V. Singh, A. S. Pawar, B. Deuri
In one of the offshore complex of ONGC, Carryover of liquid have been observed leading to tripping of gas compressors resulting a loss of significant amount of production. It was established that separation capacity of existing separators even at present operating conditions were not sufficient to process present production. Further an increase of 60% of present gas production is envisaged as per long term production profile. Hence, handling the present and envisaged increased production in the existing separators was explored. To handle the envisaged enhanced production rate and to avoid carryover issue in existing separators, options such as feed nozzles enhancement and installation of inlet device was explored. Changing feed nozzles is a tedious job, require hot job and longer shut down period and requires complete integrity test of separators as recommended by ASME SEC-VIII, pressure vessel guidelines followed by R-stamping. Therefore modifications in separator internal was suggested which will enhance the separation capacity and can accommodate in the present and envisaged increase of future production. The analysis revealed that even though the diameter and length of the separators are adequate to handle the load, it was established that the inlet nozzle of the separators are not adequate. Hence, considering many factors such as minimum pressure drop, ensuring good gas distribution, suppression of re-entrainment, momentum reduction and erosion velocity ratio of less than one, modifications in separator internal was suggested which will enhance the separation capacity and can accommodate the present and future envisaged increase of production of more than 60%. It was established in the study that this options of installation of inlet device can be done with minimum modifications and require minimum shutdown period. This option has been recommended and is under field implementation. Hence this work will provide a significant help to oil and gas personal to accommodate higher than design feed quantities in existing separators with minimum modifications and minimum shutdown period.
{"title":"A Case Study on Enhancement of Separation Capacity at an Offshore Process Complex","authors":"M. Gupta, J. Sukanandan, V. Singh, A. S. Pawar, B. Deuri","doi":"10.2118/194645-MS","DOIUrl":"https://doi.org/10.2118/194645-MS","url":null,"abstract":"\u0000 In one of the offshore complex of ONGC, Carryover of liquid have been observed leading to tripping of gas compressors resulting a loss of significant amount of production. It was established that separation capacity of existing separators even at present operating conditions were not sufficient to process present production. Further an increase of 60% of present gas production is envisaged as per long term production profile. Hence, handling the present and envisaged increased production in the existing separators was explored.\u0000 To handle the envisaged enhanced production rate and to avoid carryover issue in existing separators, options such as feed nozzles enhancement and installation of inlet device was explored. Changing feed nozzles is a tedious job, require hot job and longer shut down period and requires complete integrity test of separators as recommended by ASME SEC-VIII, pressure vessel guidelines followed by R-stamping. Therefore modifications in separator internal was suggested which will enhance the separation capacity and can accommodate in the present and envisaged increase of future production.\u0000 The analysis revealed that even though the diameter and length of the separators are adequate to handle the load, it was established that the inlet nozzle of the separators are not adequate. Hence, considering many factors such as minimum pressure drop, ensuring good gas distribution, suppression of re-entrainment, momentum reduction and erosion velocity ratio of less than one, modifications in separator internal was suggested which will enhance the separation capacity and can accommodate the present and future envisaged increase of production of more than 60%. It was established in the study that this options of installation of inlet device can be done with minimum modifications and require minimum shutdown period. This option has been recommended and is under field implementation. Hence this work will provide a significant help to oil and gas personal to accommodate higher than design feed quantities in existing separators with minimum modifications and minimum shutdown period.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78351362","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. Maghrabi, Delores Smith, A. Engel, Jennifer Henry, Joseph Fandel
Commonly used fluid loss additives (FLAs) in today's invert emulsion drilling fluids include materials with various attributes. The unmet needs of existing materials may include: Environmental restrictions due to ecotoxicity or biodegradability concernsPerformance issues at high temperaturesOverdosing at high temperaturesHigh costsFormation damage To address these challenges, a FLA was developed for invert emulsion drilling fluids that is made from a renewable raw material and performs at high temperature and high pressure. The renewable raw material used to make this novel FLA is a biopolymer byproduct of the paper pulping process, and was chemically modified under controlled conditions to create a high-performing FLA. Detailed testing was done to determine the additive's performance in different base oils (mineral and diesel), at various mud weights (12 to 16 ppg), at elevated temperatures and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. The novel FLA was compared to other commercially available FLAs for fluid loss performance. The novel FLA outperformed or was on par with the industry available FLAs tested in this study. The novel FLA realized comparable fluid loss performance of less than 10 ml at 375 F at lower concentrations as compared to the industry FLAs. In some cases, the novel FLA performed at higher temperatures, whereas some of the industry available FLAs did not. The novel FLA also boosted the electrical stability (ES) of the emulsion in certain fluid systems. The novel FLA showed minimum change in the rheology of the oil-based fluids as compared to the industry available FLAs. The novel FLA demonstrated reasonable performance in different mud weights, base oils and fluid systems. Since this novel FLA is derived from a renewable raw material, it may have less of an environmental impact compared to other FLAs utilized today. The novel FLA: Was developed from a renewable raw material for invert emulsion drilling fluids;Performed on par or outperformed industry available FLAs; andBoosted the ES of the emulsion for certain fluid systems.
{"title":"Design and Development of a Novel Fluid Loss Additive for Invert Emulsion Drilling Fluids from a Renewable Raw Material","authors":"S. Maghrabi, Delores Smith, A. Engel, Jennifer Henry, Joseph Fandel","doi":"10.2118/195182-MS","DOIUrl":"https://doi.org/10.2118/195182-MS","url":null,"abstract":"\u0000 Commonly used fluid loss additives (FLAs) in today's invert emulsion drilling fluids include materials with various attributes. The unmet needs of existing materials may include: Environmental restrictions due to ecotoxicity or biodegradability concernsPerformance issues at high temperaturesOverdosing at high temperaturesHigh costsFormation damage\u0000 To address these challenges, a FLA was developed for invert emulsion drilling fluids that is made from a renewable raw material and performs at high temperature and high pressure. The renewable raw material used to make this novel FLA is a biopolymer byproduct of the paper pulping process, and was chemically modified under controlled conditions to create a high-performing FLA. Detailed testing was done to determine the additive's performance in different base oils (mineral and diesel), at various mud weights (12 to 16 ppg), at elevated temperatures and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. The novel FLA was compared to other commercially available FLAs for fluid loss performance.\u0000 The novel FLA outperformed or was on par with the industry available FLAs tested in this study. The novel FLA realized comparable fluid loss performance of less than 10 ml at 375 F at lower concentrations as compared to the industry FLAs. In some cases, the novel FLA performed at higher temperatures, whereas some of the industry available FLAs did not. The novel FLA also boosted the electrical stability (ES) of the emulsion in certain fluid systems. The novel FLA showed minimum change in the rheology of the oil-based fluids as compared to the industry available FLAs. The novel FLA demonstrated reasonable performance in different mud weights, base oils and fluid systems. Since this novel FLA is derived from a renewable raw material, it may have less of an environmental impact compared to other FLAs utilized today.\u0000 The novel FLA: Was developed from a renewable raw material for invert emulsion drilling fluids;Performed on par or outperformed industry available FLAs; andBoosted the ES of the emulsion for certain fluid systems.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88286942","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}
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity. In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance. The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant. This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible t
{"title":"Identifying Well Treatment Candidates and Strategies for Enhancing Hydraulic Fractures System Complexity","authors":"B. Jamaloei","doi":"10.2118/195212-MS","DOIUrl":"https://doi.org/10.2118/195212-MS","url":null,"abstract":"\u0000 One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity.\u0000 In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance.\u0000 The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant.\u0000 This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible t","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83147225","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}
Julian Hernandez, M. Arnone, Juan C. Valecillos, Javier Vives, R. vanNoort, D. Groves, A. Hawthorn
Managed Pressure Drilling (MPD) technology was used to successfully drill challenging hole sections, and to run and cement casing strings for a deepwater campaign in the Gulf of Mexico. Because this technology offered the advantages of precisely manipulating the annular pressure using a statically underbalanced mud weight within a narrow pressure window, MPD was also employed along with real-time downhole measurements (from XACT), to run the lower completion assembly into the drilled production interval and perform downhole operations. For this specific case, the prognosed pressure operating window was around 100 psi, however; the actual window was found to be 50 psi when losses were encountered while drilling the openhole section through the target reservoir. Consequently, the completions operations required the most accurate modeling and planning to keep losses at an acceptable rate while avoiding an influx or formation collapse. MPD was utilized to precisely manage downhole pressures while running the lower completions assembly, displacing the drilling mud with completions fluids in the openhole section, and monitoring losses during the breaker acid job. A complex pump schedule was created by analyzing the pressure at several critical points in the open hole. Through back pressure management and high-resolution losses rate seen through the Coriolis flow meter, these losses were kept at a reasonable level to avoid breaching the pore pressure gradient and the wellbore stability limit. This paper describes the planning and execution processes that made this deepwater managed pressure completion job a success.
{"title":"Using Managed Pressure Drilling and Early Kick/Loss Detection System to Execute a Challenging Deepwater Completions Job in the Gulf of Mexico","authors":"Julian Hernandez, M. Arnone, Juan C. Valecillos, Javier Vives, R. vanNoort, D. Groves, A. Hawthorn","doi":"10.2118/194554-MS","DOIUrl":"https://doi.org/10.2118/194554-MS","url":null,"abstract":"\u0000 Managed Pressure Drilling (MPD) technology was used to successfully drill challenging hole sections, and to run and cement casing strings for a deepwater campaign in the Gulf of Mexico. Because this technology offered the advantages of precisely manipulating the annular pressure using a statically underbalanced mud weight within a narrow pressure window, MPD was also employed along with real-time downhole measurements (from XACT), to run the lower completion assembly into the drilled production interval and perform downhole operations.\u0000 For this specific case, the prognosed pressure operating window was around 100 psi, however; the actual window was found to be 50 psi when losses were encountered while drilling the openhole section through the target reservoir. Consequently, the completions operations required the most accurate modeling and planning to keep losses at an acceptable rate while avoiding an influx or formation collapse. MPD was utilized to precisely manage downhole pressures while running the lower completions assembly, displacing the drilling mud with completions fluids in the openhole section, and monitoring losses during the breaker acid job.\u0000 A complex pump schedule was created by analyzing the pressure at several critical points in the open hole. Through back pressure management and high-resolution losses rate seen through the Coriolis flow meter, these losses were kept at a reasonable level to avoid breaching the pore pressure gradient and the wellbore stability limit. This paper describes the planning and execution processes that made this deepwater managed pressure completion job a success.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85339790","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Sarmah, Ahmed Farid Ibrahim, H. Nasr-El-Din, J. Jackson
In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs. Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods. The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F. The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
{"title":"A Novel Cationic Polymer System That Improves Acid Diversion in Heterogeneous Carbonate Reservoirs","authors":"A. Sarmah, Ahmed Farid Ibrahim, H. Nasr-El-Din, J. Jackson","doi":"10.2118/194647-MS","DOIUrl":"https://doi.org/10.2118/194647-MS","url":null,"abstract":"\u0000 In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.\u0000 Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G\") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.\u0000 The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.\u0000 The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90507926","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}
Arvind Kumar, Arjit Gidwani, Suraj Singh, T. Wydiabhakti, Siddhartha Mishra
Vertical Interference tests (VIT) are used to determine the hydraulic connectivity between the formation sand intervals. This paper showcases an innovative workflow of using the petrophysical log attributes to characterize a heterogeneous reservoir sand by making use of ANN (Artificial Neural Net) and SMLP (Stratigraphic Modified Lorentz) based rock typing techniques as well as image based advanced sand layer computation techniques. Vertical interference test is either performed using a wireline formation testing tool with multiple flow probes deployed in a vertical sequence at desired depth points on the borehole wall or using a drill stem test configuration. Based on the test design, flow rates are changed using downhole pumps, which induces pressure transients in the formation. The measured pressure response is then compared with a numerical model to derive the reservoir parameters such as vertical permeability, hydraulic connectivity etc. The conventional way of model generation is to consider a section of reservoir sand as homogenous, which generally leads to over estimation or underestimation of vertical permeabilities. The technique proposed in this paper utilizes advanced logs such as image logs; magnetic resonance logs, water saturation and other advanced lithology logs to obey heterogeneity in the reservoir model by utilizing ANN/SMLP based rock-typing techniques. These rock types would be helpful in making a multi layer formation model for the VIT modeling and regression approach. The vertical interference test model is then used to determine the vertical permeability values for each of the individual rock types. The paper displays the workflow to utilize the rock type based layered formation model in vertical interference test modeling for a channel sand scenario.
{"title":"Utilizing Advanced Logs for Flow Unit Classification in Vertical Interference Test Modeling","authors":"Arvind Kumar, Arjit Gidwani, Suraj Singh, T. Wydiabhakti, Siddhartha Mishra","doi":"10.2118/194688-MS","DOIUrl":"https://doi.org/10.2118/194688-MS","url":null,"abstract":"\u0000 Vertical Interference tests (VIT) are used to determine the hydraulic connectivity between the formation sand intervals. This paper showcases an innovative workflow of using the petrophysical log attributes to characterize a heterogeneous reservoir sand by making use of ANN (Artificial Neural Net) and SMLP (Stratigraphic Modified Lorentz) based rock typing techniques as well as image based advanced sand layer computation techniques.\u0000 Vertical interference test is either performed using a wireline formation testing tool with multiple flow probes deployed in a vertical sequence at desired depth points on the borehole wall or using a drill stem test configuration. Based on the test design, flow rates are changed using downhole pumps, which induces pressure transients in the formation. The measured pressure response is then compared with a numerical model to derive the reservoir parameters such as vertical permeability, hydraulic connectivity etc. The conventional way of model generation is to consider a section of reservoir sand as homogenous, which generally leads to over estimation or underestimation of vertical permeabilities. The technique proposed in this paper utilizes advanced logs such as image logs; magnetic resonance logs, water saturation and other advanced lithology logs to obey heterogeneity in the reservoir model by utilizing ANN/SMLP based rock-typing techniques. These rock types would be helpful in making a multi layer formation model for the VIT modeling and regression approach. The vertical interference test model is then used to determine the vertical permeability values for each of the individual rock types. The paper displays the workflow to utilize the rock type based layered formation model in vertical interference test modeling for a channel sand scenario.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"131 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76712845","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Seismic attributes play an important role during reservoir characterization and three-dimensional (3D) lithofacies modeling by providing indirect insight of the subsurface. Using seismic attributes for such studies has always been challenging because it is difficult to determine a realistic relationship between hard data points (i.e., well information) and a 3D volume of seismic attributes. However, a probability-based approach for 3D seismic attribute calibration with well data provides better results of lithofacies modeling and spatial distribution of reservoir properties. This paper presents a probability-based seismic attribute calibration technique that has been described for 3D lithofacies modeling and distribution. This approach helps in subsurface reservoir characterization and provides a realistic lithofacies distribution model. This approach also helps reduce uncertainty of lithofacies prediction compared to conventional methods of simply using geostatistical algorithms.
{"title":"Three-Dimensional 3D Lithofacies Identification and Modeling Using 3D Seismic Attribute and Well Data Calibration","authors":"S. Roy, Kalyan Saikia","doi":"10.2118/194599-MS","DOIUrl":"https://doi.org/10.2118/194599-MS","url":null,"abstract":"\u0000 Seismic attributes play an important role during reservoir characterization and three-dimensional (3D) lithofacies modeling by providing indirect insight of the subsurface. Using seismic attributes for such studies has always been challenging because it is difficult to determine a realistic relationship between hard data points (i.e., well information) and a 3D volume of seismic attributes. However, a probability-based approach for 3D seismic attribute calibration with well data provides better results of lithofacies modeling and spatial distribution of reservoir properties. This paper presents a probability-based seismic attribute calibration technique that has been described for 3D lithofacies modeling and distribution. This approach helps in subsurface reservoir characterization and provides a realistic lithofacies distribution model. This approach also helps reduce uncertainty of lithofacies prediction compared to conventional methods of simply using geostatistical algorithms.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"179 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76765346","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}
F. A. Khan, Tomas Sierra, R. Imbrea, Michael Robin Edwards, Ali Mussaed Al-Rushoud, Fahad Al-Abdulhadi, Abdulaziz Shehab, F. Al-Ajeel
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: Equipment logisticsGravel foundation preparationsConcrete foundation installationsUnit Pre-assemblyPre-assembled units dispatchesFinal unit installations Daily output targets were set for each process prior to the commencement of operations. Heavy machinery, manpower and tooling requirements were defined for each process to meet the daily output targets. Progress was monitored daily and subsequently resources were scheduled and utilized to achieve the daily output targets. Setting up of a temporary operations base at the remote field along with daily coordination of resources resulted in reducing equipment’s offloading, transportation and installation cycle times, which led to increased operational efficiency and reduced logistics and operations costs. Division of operations into parallel processes helped in tracking the progress of each operation individually, thereby providing over all control in management of operations. By pre-assembling the beam pumping units at the operations base before dispatching the individual unit, installation time was reduced by 50% when compared to a typical beam pumping unit installation. Daily output target setting helped in defining the resources required to meet these targets. As the operations progressed, daily monitoring of all processes resulted in identifying opportunities to improvise operations and subsequently the daily targets were revised to increase output for each process without exceeding the resources which resulted in time and cost savings. Adopting this execution strategy concluded in successful and efficient completion of the project deliverables as follows:Gravel foundation preparations were completed in 133 work daysConcrete foundation installations were completed in 121 work daysBeam pumping unit installations were completed in 103 work days This field operations strategy for installing conventional beam pumping units at 660 production wells within six months can be considered as a reference for successfully and efficiently completing future large-scale beam pumping unit installation projects at remote locations in a limited time frame.
{"title":"Field Operations Strategy for Installing Beam Pumping Units at 660 Wells in Just six Months","authors":"F. A. Khan, Tomas Sierra, R. Imbrea, Michael Robin Edwards, Ali Mussaed Al-Rushoud, Fahad Al-Abdulhadi, Abdulaziz Shehab, F. Al-Ajeel","doi":"10.2118/194644-MS","DOIUrl":"https://doi.org/10.2118/194644-MS","url":null,"abstract":"\u0000 Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline.\u0000 A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches.\u0000 Operations were divided into six parallel processes as follows: Equipment logisticsGravel foundation preparationsConcrete foundation installationsUnit Pre-assemblyPre-assembled units dispatchesFinal unit installations\u0000 Daily output targets were set for each process prior to the commencement of operations. Heavy machinery, manpower and tooling requirements were defined for each process to meet the daily output targets. Progress was monitored daily and subsequently resources were scheduled and utilized to achieve the daily output targets.\u0000 Setting up of a temporary operations base at the remote field along with daily coordination of resources resulted in reducing equipment’s offloading, transportation and installation cycle times, which led to increased operational efficiency and reduced logistics and operations costs.\u0000 Division of operations into parallel processes helped in tracking the progress of each operation individually, thereby providing over all control in management of operations.\u0000 By pre-assembling the beam pumping units at the operations base before dispatching the individual unit, installation time was reduced by 50% when compared to a typical beam pumping unit installation.\u0000 Daily output target setting helped in defining the resources required to meet these targets. As the operations progressed, daily monitoring of all processes resulted in identifying opportunities to improvise operations and subsequently the daily targets were revised to increase output for each process without exceeding the resources which resulted in time and cost savings.\u0000 Adopting this execution strategy concluded in successful and efficient completion of the project deliverables as follows:Gravel foundation preparations were completed in 133 work daysConcrete foundation installations were completed in 121 work daysBeam pumping unit installations were completed in 103 work days\u0000 This field operations strategy for installing conventional beam pumping units at 660 production wells within six months can be considered as a reference for successfully and efficiently completing future large-scale beam pumping unit installation projects at remote locations in a limited time frame.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73965496","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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