Pressure transient analysis (PTA) has been used as one of the important reservoir surveillance tools for tight condensate-rich gas fields in Sultanate of Oman. The main objectives of PTA in those fields were to define the dynamic permeability of such tight formations, to define actual total Skin factors for such heavily fractured wells, and to assess impairment due to condensate banking around wellbores. After long production, more objectives became also necessary like assessing impairment due to poor clean-up of fractures placed in depleted layers, assessing newly proposed Massive fracturing strategy, assessing well-design and fracture strategies of newly drilled Horizontal wells, targeting the un-depleted tight layers, and impairment due to halite scaling. Therefore, the main objective of this paper is to address all the above complications to improve well and reservoir modeling for better development planning. In order to realize most of the above objectives, about 21 PTA acquisitions have been done in one of the mature gas fields in Oman, developed by more than 200 fractured wells, and on production for 25 years. In this study, an extensive PTA revision was done to address main issues of this field. Most of the actual fracture dynamic parameters (i.e. frac half-length, frac width, frac conductivity, etc.) have been estimated and compared with designed parameters. In addition, overall wells fracturing responses have been defined, categorized into strong and weak frac performances, proposing suitable interpretation and modeling workflow for each case. In this study, more reasonable permeability values have been estimated for individual layers, improving the dynamic modeling significantly. In addition, it is found that late hook-up of fractured wells leads to very poor fractures clean out in pressure-depleted layers, causing the weak frac performance. In addition, the actual frac parameters (i.e. frac-half-length) found to be much lower than designed/expected before implementation. This helped to improve well and fracturing design and implementation for next vertical and horizontal wells, improving their performances. All the observed PTA responses (fracturing, condensate-banking, Halite-scaling, wells interference) have been matched and proved using sophisticated single and sector numerical simulation models, which have been incorporated into full-field models, causing significant improvements in field production forecasts and field development planning (FDP).
{"title":"Revision of Pressure Transient Analysis in Mature Condensate-Rich Tight Gas Fields in Sultanate of Oman","authors":"A. Hegazy, M. Rashdi","doi":"10.2118/205271-ms","DOIUrl":"https://doi.org/10.2118/205271-ms","url":null,"abstract":"\u0000 Pressure transient analysis (PTA) has been used as one of the important reservoir surveillance tools for tight condensate-rich gas fields in Sultanate of Oman. The main objectives of PTA in those fields were to define the dynamic permeability of such tight formations, to define actual total Skin factors for such heavily fractured wells, and to assess impairment due to condensate banking around wellbores. After long production, more objectives became also necessary like assessing impairment due to poor clean-up of fractures placed in depleted layers, assessing newly proposed Massive fracturing strategy, assessing well-design and fracture strategies of newly drilled Horizontal wells, targeting the un-depleted tight layers, and impairment due to halite scaling. Therefore, the main objective of this paper is to address all the above complications to improve well and reservoir modeling for better development planning.\u0000 In order to realize most of the above objectives, about 21 PTA acquisitions have been done in one of the mature gas fields in Oman, developed by more than 200 fractured wells, and on production for 25 years. In this study, an extensive PTA revision was done to address main issues of this field. Most of the actual fracture dynamic parameters (i.e. frac half-length, frac width, frac conductivity, etc.) have been estimated and compared with designed parameters. In addition, overall wells fracturing responses have been defined, categorized into strong and weak frac performances, proposing suitable interpretation and modeling workflow for each case.\u0000 In this study, more reasonable permeability values have been estimated for individual layers, improving the dynamic modeling significantly. In addition, it is found that late hook-up of fractured wells leads to very poor fractures clean out in pressure-depleted layers, causing the weak frac performance. In addition, the actual frac parameters (i.e. frac-half-length) found to be much lower than designed/expected before implementation. This helped to improve well and fracturing design and implementation for next vertical and horizontal wells, improving their performances. All the observed PTA responses (fracturing, condensate-banking, Halite-scaling, wells interference) have been matched and proved using sophisticated single and sector numerical simulation models, which have been incorporated into full-field models, causing significant improvements in field production forecasts and field development planning (FDP).","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88422139","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}
John E. Busteed, J. Arroyo, F. Morales, M. Omer, F. Fragachán
Uniformly distributing proppant inside fractures with low damage on fracture conductivity is the most important index of successful fracturing fluids. However, due to very low proppant suspension capacity of slickwater and friction reducers fracturing fluids and longer fracture closure time in nano & pico darcies formations, proppants settles quickly and accumulates near wellbore resulting in worse-than-expected well performance, as the fracture full capacity is not open and contributing to production. Traditionally, cross-linked polymer fluid systems are capable to suspend and transport high loading of proppants into a hydraulically generated fracture. Nevertheless, amount of unbroken cross-linked polymers is usually left in fractures causing damage to fracture proppant conductivity, depending on polymer loading. To mitigate these challenges, a low viscosity-engineered-fluid with excellent proppantcarrying capacity and suspension-in excess of 30 hours at static formation temperature conditions - has been designed, enhancing proppant placement and distribution within developed fractures, with a 98% plus retained conductivity. In this work experimental and numerical tests are presented together with the path followed in developing a network of packed structures from polymer associations providing low viscosity and maximum proppant suspension. Challenges encountered during field injection with friction are discussed together with the problem understanding characterized via extensive friction loop tests. Suspension tests performed with up to 8-10 PPA of proppant concentration at temperature conditions are shared, together with slot tests performed. Physics-based model results from a 3D Discrete Fracture Network simulator that computes viscosity, and elastic parameters based on shear rate, allows to estimate pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture. This work will demonstrate the advanced capabilities and performance of the engineered fluid over conventional fracturing fluids and its benefits. Additionally, this paper will present field injection pressure analysis performed during the development of this fluid, together with a field case including production results after 8 months of treatment. The field case production decline observed after fracture treatment demonstrates the value of this system in sustaining well production and adding additional reserves.
{"title":"Is High Viscosity a Requirement for Fracturing Fluids?","authors":"John E. Busteed, J. Arroyo, F. Morales, M. Omer, F. Fragachán","doi":"10.2118/205244-ms","DOIUrl":"https://doi.org/10.2118/205244-ms","url":null,"abstract":"\u0000 Uniformly distributing proppant inside fractures with low damage on fracture conductivity is the most important index of successful fracturing fluids. However, due to very low proppant suspension capacity of slickwater and friction reducers fracturing fluids and longer fracture closure time in nano & pico darcies formations, proppants settles quickly and accumulates near wellbore resulting in worse-than-expected well performance, as the fracture full capacity is not open and contributing to production. Traditionally, cross-linked polymer fluid systems are capable to suspend and transport high loading of proppants into a hydraulically generated fracture. Nevertheless, amount of unbroken cross-linked polymers is usually left in fractures causing damage to fracture proppant conductivity, depending on polymer loading. To mitigate these challenges, a low viscosity-engineered-fluid with excellent proppantcarrying capacity and suspension-in excess of 30 hours at static formation temperature conditions - has been designed, enhancing proppant placement and distribution within developed fractures, with a 98% plus retained conductivity.\u0000 In this work experimental and numerical tests are presented together with the path followed in developing a network of packed structures from polymer associations providing low viscosity and maximum proppant suspension. Challenges encountered during field injection with friction are discussed together with the problem understanding characterized via extensive friction loop tests. Suspension tests performed with up to 8-10 PPA of proppant concentration at temperature conditions are shared, together with slot tests performed.\u0000 Physics-based model results from a 3D Discrete Fracture Network simulator that computes viscosity, and elastic parameters based on shear rate, allows to estimate pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture. This work will demonstrate the advanced capabilities and performance of the engineered fluid over conventional fracturing fluids and its benefits. Additionally, this paper will present field injection pressure analysis performed during the development of this fluid, together with a field case including production results after 8 months of treatment. The field case production decline observed after fracture treatment demonstrates the value of this system in sustaining well production and adding additional reserves.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87635267","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}
This paper further develops an analysis of proppant distribution patterns in hydraulically fractured wells initially presented in SPE-199693-MS. A significantly enlarged database of in-situ perforation erosion measurements provides a more rigorous statistical basis allowing some previously reported trends to be updated, but the main objective of the paper is to present additional insights identified since the original paper was published. Measurements of the eroded area of individual perforations derived from downhole camera images again provide the input for this study. Entry hole enlargement during limited entry hydraulic fracturing provides strong and direct evidence that proppant was successfully placed into individual perforations. This provides a straightforward evaluation of cluster efficiency. Perhaps more importantly the volume of proppant placed into a perforation can also be inferred from the degree of erosion. Summing individual perforation erosion at cluster level allows patterns and biases to be identified and an understanding of proppant distribution across stages has been developed. Outcomes from an analysis of a database that now exceeds 50,000 eroded perforations are presented. Uniform reservoir stimulation is a key objective of fracture treatments but remains challenging to measure and report. The study therefore focused on understanding how uniformly proppant is distributed across more than 1,800 measured stages. Results demonstrate how proppant distribution within stages is influenced when treatment parameters change. Our approach was to vary one parameter, for example the stage length, while all other parameters were maintained at a consistent value. We investigated multiple parameters that can be readily controlled during treatment design and show how these can be manipulated to improve proppant distribution. These included stage length, cluster spacing, perforation count per cluster and perforation phase. Hydraulic fracturing is a complex, high energy process with numerous input parameters. At individual cluster and stage level outcomes can be unpredictable and diagnostic results are often quite variable. The approach taken here was to complete a statistical analysis of a sufficiently large dataset of in-situ measurements. This allowed common trends and patterns to be confidently identified and conclusions reached on how proppant distribution is affected by varying specific design parameters. This should be of interest and value to those designing hydraulic fracture treatments.
{"title":"An Expanded Study of Proppant Distribution Trends from a Database of Eroded Perforation Images","authors":"Glyn Roberts, Souvick Saha, Johanna Waldheim","doi":"10.2118/205314-ms","DOIUrl":"https://doi.org/10.2118/205314-ms","url":null,"abstract":"\u0000 This paper further develops an analysis of proppant distribution patterns in hydraulically fractured wells initially presented in SPE-199693-MS. A significantly enlarged database of in-situ perforation erosion measurements provides a more rigorous statistical basis allowing some previously reported trends to be updated, but the main objective of the paper is to present additional insights identified since the original paper was published.\u0000 Measurements of the eroded area of individual perforations derived from downhole camera images again provide the input for this study. Entry hole enlargement during limited entry hydraulic fracturing provides strong and direct evidence that proppant was successfully placed into individual perforations. This provides a straightforward evaluation of cluster efficiency. Perhaps more importantly the volume of proppant placed into a perforation can also be inferred from the degree of erosion. Summing individual perforation erosion at cluster level allows patterns and biases to be identified and an understanding of proppant distribution across stages has been developed.\u0000 Outcomes from an analysis of a database that now exceeds 50,000 eroded perforations are presented. Uniform reservoir stimulation is a key objective of fracture treatments but remains challenging to measure and report. The study therefore focused on understanding how uniformly proppant is distributed across more than 1,800 measured stages.\u0000 Results demonstrate how proppant distribution within stages is influenced when treatment parameters change. Our approach was to vary one parameter, for example the stage length, while all other parameters were maintained at a consistent value. We investigated multiple parameters that can be readily controlled during treatment design and show how these can be manipulated to improve proppant distribution. These included stage length, cluster spacing, perforation count per cluster and perforation phase.\u0000 Hydraulic fracturing is a complex, high energy process with numerous input parameters. At individual cluster and stage level outcomes can be unpredictable and diagnostic results are often quite variable. The approach taken here was to complete a statistical analysis of a sufficiently large dataset of in-situ measurements. This allowed common trends and patterns to be confidently identified and conclusions reached on how proppant distribution is affected by varying specific design parameters. This should be of interest and value to those designing hydraulic fracture treatments.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"56 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90687294","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}
G. Grubac, J. Conrad, P. Janiczek, Dragomir Alexandru, Sean Mcgarvey
This paper presents an analysis of the stimulation treatment design and operational efficiencies in the Black Sea. In greater detail, the paper focuses on how the stimulation design and each operational step has been optimized to save time, money and ensure an HSE driven completion methodology. An analysis was performed on the stimulation design and implementation approach looking at its evolution through a knowledge building and lesson learning process. The principal goal was to determine the most economical way to stimulate an offshore well without making any concessions to the reservoirs’ production or ultimate recovery. From the basics of well and frac design to completion optimization, effort was applied in analyzing ball launching procedures, frac spacing, logistical arrangements on the stimulation vessel and all other areas where there was potential to make improvements. Ultimately, an analysis of fluid displacements during flush was performed and deductions inferred. Past stimulation treatments were analyzed in an effort of better understanding the advantages and disadvantages in terms of production output of the wells. Similarly, an analysis of the completion approach and operational efficiencies showed the ability of pumping three stimulation stages a day. Considering that horizontal wells in the area are usually completed in six stages, a stimulation campaign would effectively be completed in 2 pumping days, 4 days total if no weather or operational delays are faced. Further improvements of this approach have been implemented in 2021 when six stimulation stages have been pumped in a single vessel ride. Applying the ball drop procedure offshore showed optimal results, as it is efficient in reducing downtime in between fracturing stages and in achieving proper isolation between stimulation zones. Likewise, with over flush being a concern throughout most of the stimulation population, certain cases in the Black Sea showed that over flushing did not adversely affect production of the wells with the production exhibiting ~15% above expected production rates post stimulation. In conclusion, the authors believe that the operational efficiencies achieved in the Black Sea are transposable in other offshore environments and successful cost cutting can be achieved by sound engineering and logistical decisions. The approach and results are beneficial in understanding where the economics are positively impacted in multistage stimulation treatments in the offshore environments, hence ultimately improving the rate of return.
{"title":"Maximizing Stimulation Efficiencies in Offshore Multistage Completions, Black Sea, Romania","authors":"G. Grubac, J. Conrad, P. Janiczek, Dragomir Alexandru, Sean Mcgarvey","doi":"10.2118/205243-ms","DOIUrl":"https://doi.org/10.2118/205243-ms","url":null,"abstract":"\u0000 This paper presents an analysis of the stimulation treatment design and operational efficiencies in the Black Sea. In greater detail, the paper focuses on how the stimulation design and each operational step has been optimized to save time, money and ensure an HSE driven completion methodology.\u0000 An analysis was performed on the stimulation design and implementation approach looking at its evolution through a knowledge building and lesson learning process. The principal goal was to determine the most economical way to stimulate an offshore well without making any concessions to the reservoirs’ production or ultimate recovery. From the basics of well and frac design to completion optimization, effort was applied in analyzing ball launching procedures, frac spacing, logistical arrangements on the stimulation vessel and all other areas where there was potential to make improvements. Ultimately, an analysis of fluid displacements during flush was performed and deductions inferred.\u0000 Past stimulation treatments were analyzed in an effort of better understanding the advantages and disadvantages in terms of production output of the wells. Similarly, an analysis of the completion approach and operational efficiencies showed the ability of pumping three stimulation stages a day. Considering that horizontal wells in the area are usually completed in six stages, a stimulation campaign would effectively be completed in 2 pumping days, 4 days total if no weather or operational delays are faced. Further improvements of this approach have been implemented in 2021 when six stimulation stages have been pumped in a single vessel ride. Applying the ball drop procedure offshore showed optimal results, as it is efficient in reducing downtime in between fracturing stages and in achieving proper isolation between stimulation zones. Likewise, with over flush being a concern throughout most of the stimulation population, certain cases in the Black Sea showed that over flushing did not adversely affect production of the wells with the production exhibiting ~15% above expected production rates post stimulation. In conclusion, the authors believe that the operational efficiencies achieved in the Black Sea are transposable in other offshore environments and successful cost cutting can be achieved by sound engineering and logistical decisions.\u0000 The approach and results are beneficial in understanding where the economics are positively impacted in multistage stimulation treatments in the offshore environments, hence ultimately improving the rate of return.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"136 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86353434","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}
Dmitrii Smirnov, O. Isaee, A. Moiseenkov, A. Al Hadhrami, Hilal Shabibi, Saqer Kaabi, E. Sayapov
Pre-Cambrian South Oman tight silicilyte reservoirs are very challenging for the development due to poor permeability less than 0.1 mD and laminated texture. Successful hydraulic fracturing is a key for the long commercial production. One of the main parameter for frac planning and optimization is fracture geometry. The objective of this study was summarizing results comparison from different logging methods and recommended best practices for logging program targeting fracture geometry evaluation. The novel method in the region for hydraulic fracture height and orientation evaluation is cross-dipole cased hole acoustic logging. The method allows to evaluate fracture geometry based on the acoustic anisotropy changes after frac operations in the near wellbore area. The memory sonic log combined with the Gyro was acquired before and after frac operations in the cased hole. The acoustic data was compared with Spectral Noise log, Chemical and Radioactive tracers, Production Logging and pre-frac model. Extensive logging program allow to complete integrated evaluation, define methods limitations and advantages, summarize best practices and optimum logging program for the future wells. The challenges in combining memory cross-dipole sonic log and gyro in cased hole were effectively resolved. The acoustic anisotropy analysis successfully confirms stresses and predominant hydraulic fractures orientation. Fracture height was confirmed based on results from different logging methods. Tracers are well known method for the fracture height evaluation after hydraulic frac operations. The Spectral Noise log is perfect tool to evaluate hydraulically active fracture height in the near wellbore area. The combination of cased hole acoustic and noise logging methods is a powerful complex for hydraulic fracture geometry evaluation. The main limitations and challenges for sonic log are cement bond quality and hole conditions after frac operations. Noise log has limited depth of investigation. However, in combination with production and temperature logging provides reliable fit for purpose capabilities. The abilities of sonic anisotropy analysis for fracture height and hydraulic fracture orientation were confirmed. The optimum logging program for fracture geometry evaluation was defined and recommended for replication in projects were fracture geometry evaluation is required for hydraulic fracturing optimization.
{"title":"Integrated Hydraulic Fracture Geometry Evaluation Based on Pre-Cambrian Tight Silicylate Reservoir in South Oman Salt Basin","authors":"Dmitrii Smirnov, O. Isaee, A. Moiseenkov, A. Al Hadhrami, Hilal Shabibi, Saqer Kaabi, E. Sayapov","doi":"10.2118/205276-ms","DOIUrl":"https://doi.org/10.2118/205276-ms","url":null,"abstract":"\u0000 Pre-Cambrian South Oman tight silicilyte reservoirs are very challenging for the development due to poor permeability less than 0.1 mD and laminated texture. Successful hydraulic fracturing is a key for the long commercial production. One of the main parameter for frac planning and optimization is fracture geometry. The objective of this study was summarizing results comparison from different logging methods and recommended best practices for logging program targeting fracture geometry evaluation.\u0000 The novel method in the region for hydraulic fracture height and orientation evaluation is cross-dipole cased hole acoustic logging. The method allows to evaluate fracture geometry based on the acoustic anisotropy changes after frac operations in the near wellbore area. The memory sonic log combined with the Gyro was acquired before and after frac operations in the cased hole. The acoustic data was compared with Spectral Noise log, Chemical and Radioactive tracers, Production Logging and pre-frac model. Extensive logging program allow to complete integrated evaluation, define methods limitations and advantages, summarize best practices and optimum logging program for the future wells.\u0000 The challenges in combining memory cross-dipole sonic log and gyro in cased hole were effectively resolved. The acoustic anisotropy analysis successfully confirms stresses and predominant hydraulic fractures orientation. Fracture height was confirmed based on results from different logging methods. Tracers are well known method for the fracture height evaluation after hydraulic frac operations. The Spectral Noise log is perfect tool to evaluate hydraulically active fracture height in the near wellbore area. The combination of cased hole acoustic and noise logging methods is a powerful complex for hydraulic fracture geometry evaluation. The main limitations and challenges for sonic log are cement bond quality and hole conditions after frac operations. Noise log has limited depth of investigation. However, in combination with production and temperature logging provides reliable fit for purpose capabilities.\u0000 The abilities of sonic anisotropy analysis for fracture height and hydraulic fracture orientation were confirmed. The optimum logging program for fracture geometry evaluation was defined and recommended for replication in projects were fracture geometry evaluation is required for hydraulic fracturing optimization.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"498 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75209112","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. S. Magna Detto Calcaterra, Pierluigi Sedda, Giacomo Fulceri, S. Luppina, L. Mauri, V. Mittiga, Sabino Parziale, Gabriele Restuccia
Primary production mechanism of a clean sandstone reservoir in a brownfield for oil production has been recently changed from natural depletion to waterflooding. Despite the apparently moderate petro-physical properties of the formation, injector wells performances were observed to be extremely poor, mainly due to: high drilling-induced formation damage and Fluids interaction within the reservoir (injection across the oil rim section). Several stimulation technologies have been applied to improve wells injection capability for pressure support optimization. Re-perforation via abrasive jetting, perforations wash through coiled tubing and various acid formulations via bullheading were attempted without achieving any significant increase in injectivity. Considering the modest rock permeability, the need to access a wider formation area to improve oil sweep efficiency and the crucial requirement to re-pressurize the reservoir, an additional card was played as last resort: hydraulic fracturing. This technique was not new to the area and already experimented by different operators. Several producer wells in different layers were hydraulic fracturing stimulated with proppant and/or acid in the past with a good rate of success. Why not to try then? Given the past experience on the same field with hydraulic fracturing in oil producers and accounting for well integrity and potential injectivity, one was chosen as suitable candidate. Offset wells hystorical data were used to build a hydraulic fracturing reservoir model and plan for the activity in details; operator and service providers engaged in a Frac Well On Paper activity in order to reduce any margin of error during field operations. An approach that proved successful. From there, the first trial well was planned and performed successfully. 4 other hydraulic fracturing jobs on 4 wells followed at close distance in time with different, but steadily comforting, results. Injection was improved from negligible initial values up to 2000 mc/day for the post-stimulation condition, exceeding the preliminary expectations. This paper introduces the steps taken to start the hydraulic fracturing campaign, the decision process that led to the design of the treatment, an overview of the execution phases, results well by well and lessons learned to optimize future campaigns.
{"title":"Hydraulic Fracturing as Game Changer to Maximize Waterflooding Efficiency in a Brownfield","authors":"M. S. Magna Detto Calcaterra, Pierluigi Sedda, Giacomo Fulceri, S. Luppina, L. Mauri, V. Mittiga, Sabino Parziale, Gabriele Restuccia","doi":"10.2118/205332-ms","DOIUrl":"https://doi.org/10.2118/205332-ms","url":null,"abstract":"\u0000 Primary production mechanism of a clean sandstone reservoir in a brownfield for oil production has been recently changed from natural depletion to waterflooding. Despite the apparently moderate petro-physical properties of the formation, injector wells performances were observed to be extremely poor, mainly due to: high drilling-induced formation damage and Fluids interaction within the reservoir (injection across the oil rim section). Several stimulation technologies have been applied to improve wells injection capability for pressure support optimization. Re-perforation via abrasive jetting, perforations wash through coiled tubing and various acid formulations via bullheading were attempted without achieving any significant increase in injectivity. Considering the modest rock permeability, the need to access a wider formation area to improve oil sweep efficiency and the crucial requirement to re-pressurize the reservoir, an additional card was played as last resort: hydraulic fracturing.\u0000 This technique was not new to the area and already experimented by different operators. Several producer wells in different layers were hydraulic fracturing stimulated with proppant and/or acid in the past with a good rate of success. Why not to try then?\u0000 Given the past experience on the same field with hydraulic fracturing in oil producers and accounting for well integrity and potential injectivity, one was chosen as suitable candidate. Offset wells hystorical data were used to build a hydraulic fracturing reservoir model and plan for the activity in details; operator and service providers engaged in a Frac Well On Paper activity in order to reduce any margin of error during field operations. An approach that proved successful.\u0000 From there, the first trial well was planned and performed successfully. 4 other hydraulic fracturing jobs on 4 wells followed at close distance in time with different, but steadily comforting, results. Injection was improved from negligible initial values up to 2000 mc/day for the post-stimulation condition, exceeding the preliminary expectations.\u0000 This paper introduces the steps taken to start the hydraulic fracturing campaign, the decision process that led to the design of the treatment, an overview of the execution phases, results well by well and lessons learned to optimize future campaigns.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89807698","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}
Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to "creep" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial. A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and "controlled" flowback programs to establish inflow from Kerogen without "creep". Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver "clean inflow". A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. "Controlled" flowback carried out in January 2020 achieved the strategically critical "clean inflow" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed. Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconve
{"title":"Achieving Productivity and Clean Inflow from an Unconventional Reservoir in North Kuwait","authors":"Z. Ahmed, A. Salem, L. Wu, Ben Mowad","doi":"10.2118/205253-ms","DOIUrl":"https://doi.org/10.2118/205253-ms","url":null,"abstract":"\u0000 Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to \"creep\" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial.\u0000 A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and \"controlled\" flowback programs to establish inflow from Kerogen without \"creep\".\u0000 Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver \"clean inflow\".\u0000 A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. \"Controlled\" flowback carried out in January 2020 achieved the strategically critical \"clean inflow\" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed.\u0000 Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconve","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73986768","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}
Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.
{"title":"Case Study of Condensate Dropout Effect in Unconventional Gas/Condensate Reservoirs with Hydraulically Fractured Wells","authors":"Ali Alsultan, J. Shaoul, Jason Park, P. Zitha","doi":"10.2118/205252-ms","DOIUrl":"https://doi.org/10.2118/205252-ms","url":null,"abstract":"\u0000 Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation.\u0000 A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in \"unconventional\" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation.\u0000 The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80001073","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}
For as long as we have been performing hydraulic fracturing, we have been trying to ensure that we stay out of undesirable horizons, potentially containing water and/or gas. The holy grail of hydraulic fracturing, an absolute control of created fracture height, has eluded the industry for more than 70 years. Of course, there have been many that have claimed solutions, but all the marketed approaches have at best merely created a delay to the inevitable growth and at worst been a snake-oil approach with little actual merit. Fundamentally, the applied techniques have attempted to delay or influence the underlying equations of net-pressure and stress variation; but having to ultimately honour them and by doing so then condemned themselves to limited success or outright failure. Fast forward to 2020, and a reassessment of the relative importance of height-growth constraint and what may have changed to help us achieve this. The development of unconventionals are focused on creating as much surface area as possible in micro/nano-Darcy environments, across almost any phase, but with typically poor line of sight to profit. However, the more valuable business of conventional oil and gas is working in thinner and thinner reservoirs with an often-deteriorating permeability, but with a significantly higher potential economic return. What unconventional has successfully delivered however, is a rapid deployment and acceleration in a range of completion technologies that were unavailable just a few years ago. We will demonstrate that these technologies potentially offer the capability of finally being able to control fracture height-growth. Consideration of a range of previously applied height-growth approaches will demonstrate how they attempted to fool or fudge height growth creation mechanisms. With this clarity, we can consider what advances in completion technology may offer in terms of delivering height growth control. We suggest that with the technology and approaches that are currently available today, that height-growth control is finally within reach. We will go on to describe a multi-well Pilot program, in deployment and execution in 2020/021 in Western Siberia; where billions of barrels remain to be recovered in thin oil-rim, low permeability sandstone reservoirs below gas or above water. A comprehensive assessment of the myriad of height-growth approaches that have been utilized over the last 70 years was performed, but in each case demonstrated the fallibility and limitations of each of these. However, rather than the interpretation that such control is not achievable, instead we will show a mathematically sound approach, along with field data and evidence that this is possible. The presentation will demonstrate that completion advances over the last 10 - 15 years make this approach a reality in the present day; and that broader field implementation is finally within reach.
{"title":"Fracturing Technology - Can We Finally Control Fracture Height?","authors":"M. Rylance, Y. Korovaychuk","doi":"10.2118/205320-ms","DOIUrl":"https://doi.org/10.2118/205320-ms","url":null,"abstract":"\u0000 For as long as we have been performing hydraulic fracturing, we have been trying to ensure that we stay out of undesirable horizons, potentially containing water and/or gas. The holy grail of hydraulic fracturing, an absolute control of created fracture height, has eluded the industry for more than 70 years. Of course, there have been many that have claimed solutions, but all the marketed approaches have at best merely created a delay to the inevitable growth and at worst been a snake-oil approach with little actual merit. Fundamentally, the applied techniques have attempted to delay or influence the underlying equations of net-pressure and stress variation; but having to ultimately honour them and by doing so then condemned themselves to limited success or outright failure.\u0000 Fast forward to 2020, and a reassessment of the relative importance of height-growth constraint and what may have changed to help us achieve this. The development of unconventionals are focused on creating as much surface area as possible in micro/nano-Darcy environments, across almost any phase, but with typically poor line of sight to profit. However, the more valuable business of conventional oil and gas is working in thinner and thinner reservoirs with an often-deteriorating permeability, but with a significantly higher potential economic return. What unconventional has successfully delivered however, is a rapid deployment and acceleration in a range of completion technologies that were unavailable just a few years ago. We will demonstrate that these technologies potentially offer the capability of finally being able to control fracture height-growth.\u0000 Consideration of a range of previously applied height-growth approaches will demonstrate how they attempted to fool or fudge height growth creation mechanisms. With this clarity, we can consider what advances in completion technology may offer in terms of delivering height growth control. We suggest that with the technology and approaches that are currently available today, that height-growth control is finally within reach. We will go on to describe a multi-well Pilot program, in deployment and execution in 2020/021 in Western Siberia; where billions of barrels remain to be recovered in thin oil-rim, low permeability sandstone reservoirs below gas or above water.\u0000 A comprehensive assessment of the myriad of height-growth approaches that have been utilized over the last 70 years was performed, but in each case demonstrated the fallibility and limitations of each of these. However, rather than the interpretation that such control is not achievable, instead we will show a mathematically sound approach, along with field data and evidence that this is possible. The presentation will demonstrate that completion advances over the last 10 - 15 years make this approach a reality in the present day; and that broader field implementation is finally within reach.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88319409","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}
Sultan Salim Al Shoaibi, J. Florez, S. Farsi, A. Hinai, Alvaro Nunez, Petrus In ‘T Panhuis, A. Taha, Melis Van der Horst, Derrick Melanson, M. Wojtaszek, Evert Moes, K. Mccoy
This paper discusses the first fiber-optic (FO) installation in a vertical high-pressure high-temperature deep gas well in PDO, Oman. A specially designed fiber-optic cable was successfully installed and cemented behind the production casing, which was subsequently perforated in an oriented manner without damaging the cable. This paper also describes how the fiber-optic cable was used afterwards to acquire Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data for the purpose of hydraulic fracturing diagnostics. Fiber-optic surveillance is becoming an increasingly important activity for well and reservoir surveillance. The added complexity of the fiber-optic installation will affect the well design, which is one of the elements that requires focused attention, especially when the fiber is installed behind casing. The impact on casing design, wellhead design, perforation strategy, and logging requirements will all be discussed. In order for a well to be completed with a permanent fiber-optic cable, a few critical procedures need to be followed, including: –modifying the wellhead design to include feedthrough ports for the cable;–optimizing the cement design;–imposing strict procedures to ensure the cable is installed behind the casing without getting stuck;–changing the perforation phasing to avoid damaging the cable;–mapping the location of the cable to allow the gun string to be oriented away from the cable. The fiber-optic cable itself needed to be designed to be protected in such a way that it would not be damaged during installation and completion (perf/frac) activities. Furthermore, the cable was also optimized to improve its detectability, to aid the oriented perforation. In deep gas wells, much more than in conventional shallow water injectors or oil producers, the well integrity aspect should be given special attention. Specifically, any risks related to unwanted gas leaks, either through the control line, poor cement, or because of other design errors should be avoided. In deep gas wells, high temperature and pressure will also play a big role in the expected lifespan of the cable. Finally, the well was hydraulically fractured in four stages, using the "plug-and-perf" technique, during which DAS and DTS data were acquired continuously and across all depths of the well. The data provided valuable information on the effectiveness of each of the frac stages, it could be used to analyze screen-outs and detect out-of-zone injection, and recommendations for the optimizations of future hydraulic frac designs could be derived. The fiber-optic data were also integrated with other open-hole data for improved understanding of the reservoir performance. The next step will be to acquire repeated time-lapse DAS and DTS data for production profiling, to gain more insights of how the long-term production performance is affected by the hydraulic frac operations.
{"title":"The First Behind-Casing Fiber-Optic Installation in a High-Pressure High-Temperature Deep Gas Well in Oman","authors":"Sultan Salim Al Shoaibi, J. Florez, S. Farsi, A. Hinai, Alvaro Nunez, Petrus In ‘T Panhuis, A. Taha, Melis Van der Horst, Derrick Melanson, M. Wojtaszek, Evert Moes, K. Mccoy","doi":"10.2118/205275-ms","DOIUrl":"https://doi.org/10.2118/205275-ms","url":null,"abstract":"\u0000 This paper discusses the first fiber-optic (FO) installation in a vertical high-pressure high-temperature deep gas well in PDO, Oman. A specially designed fiber-optic cable was successfully installed and cemented behind the production casing, which was subsequently perforated in an oriented manner without damaging the cable. This paper also describes how the fiber-optic cable was used afterwards to acquire Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data for the purpose of hydraulic fracturing diagnostics.\u0000 Fiber-optic surveillance is becoming an increasingly important activity for well and reservoir surveillance. The added complexity of the fiber-optic installation will affect the well design, which is one of the elements that requires focused attention, especially when the fiber is installed behind casing. The impact on casing design, wellhead design, perforation strategy, and logging requirements will all be discussed.\u0000 In order for a well to be completed with a permanent fiber-optic cable, a few critical procedures need to be followed, including: –modifying the wellhead design to include feedthrough ports for the cable;–optimizing the cement design;–imposing strict procedures to ensure the cable is installed behind the casing without getting stuck;–changing the perforation phasing to avoid damaging the cable;–mapping the location of the cable to allow the gun string to be oriented away from the cable.\u0000 The fiber-optic cable itself needed to be designed to be protected in such a way that it would not be damaged during installation and completion (perf/frac) activities. Furthermore, the cable was also optimized to improve its detectability, to aid the oriented perforation.\u0000 In deep gas wells, much more than in conventional shallow water injectors or oil producers, the well integrity aspect should be given special attention. Specifically, any risks related to unwanted gas leaks, either through the control line, poor cement, or because of other design errors should be avoided. In deep gas wells, high temperature and pressure will also play a big role in the expected lifespan of the cable.\u0000 Finally, the well was hydraulically fractured in four stages, using the \"plug-and-perf\" technique, during which DAS and DTS data were acquired continuously and across all depths of the well. The data provided valuable information on the effectiveness of each of the frac stages, it could be used to analyze screen-outs and detect out-of-zone injection, and recommendations for the optimizations of future hydraulic frac designs could be derived. The fiber-optic data were also integrated with other open-hole data for improved understanding of the reservoir performance. The next step will be to acquire repeated time-lapse DAS and DTS data for production profiling, to gain more insights of how the long-term production performance is affected by the hydraulic frac operations.","PeriodicalId":10917,"journal":{"name":"Day 2 Wed, January 12, 2022","volume":"47 12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72618794","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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