Temperature logs have been used to monitor producing wells since the early 1930s. Normally, analysis of the temperature log is viewed as secondary to that of the spinner flowmeter, which gives flow velocity directly, and temperature is conventionally used only as an indicator of fluid entry/exit with the production logging tool (PLT). The main disadvantage of the PLT is that if spinner flowmeter data are not good due to tool problems, then flow quantification is jeopardized. Additionally, in recent years, the cost of production logging has increased considerably because many wells are now drilled horizontally through the reservoir, and the PLTs must be conveyed on coiled tubing or well tractors, and, in some cases (subsea wells), even this may not be possible. Consequently, alternative technologies become viable if they can be used for flow quantification using just temperature data. This paper presents a new flow quantification model using temperature data acquired using production logging or a distributed temperature sensor (DTS) system. The model presented in this paper can handle multiple production zones with their zonal fluid properties as input to give corresponding zonal flow rates as output. The said model is applicable for single-phase oil and gas producer wells as well as water injection wells in both onshore and offshore environments. There are two modes of flow calculation for each answer product-steady state or transient. The model is integrated into easy-to-use software, and it has options for forward simulation as well as optimization. The forward simulation calculates temperature distribution along the wellbore for any given production profile, which is critical for model calibration for any reservoir. After the model has been validated for a reservoir, it can be used for zonal flow quantification using any temperature survey. The objective of the optimization option is to allow the user to fit the model output temperature curve to a selected temperature curve by means of a genetic fitting algorithm that will adjust one or two user-selected reservoir parameters, such as permeability, pressure, skin, gas-oil ratio (GOR), temperature, or water-cut, until a fit is achieved. The model has been extensively tested against synthetic, literature and field examples and good agreements have been obtained, confirming the robustness of this novel approach.
{"title":"Exploring the Capability of Temperature-Only Analysis for Zonal Flow Quantification","authors":"Shaktim Dutta, Apoorva Kumar, Siddhartha Mishra","doi":"10.2118/194583-MS","DOIUrl":"https://doi.org/10.2118/194583-MS","url":null,"abstract":"\u0000 Temperature logs have been used to monitor producing wells since the early 1930s. Normally, analysis of the temperature log is viewed as secondary to that of the spinner flowmeter, which gives flow velocity directly, and temperature is conventionally used only as an indicator of fluid entry/exit with the production logging tool (PLT). The main disadvantage of the PLT is that if spinner flowmeter data are not good due to tool problems, then flow quantification is jeopardized. Additionally, in recent years, the cost of production logging has increased considerably because many wells are now drilled horizontally through the reservoir, and the PLTs must be conveyed on coiled tubing or well tractors, and, in some cases (subsea wells), even this may not be possible. Consequently, alternative technologies become viable if they can be used for flow quantification using just temperature data. This paper presents a new flow quantification model using temperature data acquired using production logging or a distributed temperature sensor (DTS) system.\u0000 The model presented in this paper can handle multiple production zones with their zonal fluid properties as input to give corresponding zonal flow rates as output. The said model is applicable for single-phase oil and gas producer wells as well as water injection wells in both onshore and offshore environments. There are two modes of flow calculation for each answer product-steady state or transient. The model is integrated into easy-to-use software, and it has options for forward simulation as well as optimization. The forward simulation calculates temperature distribution along the wellbore for any given production profile, which is critical for model calibration for any reservoir. After the model has been validated for a reservoir, it can be used for zonal flow quantification using any temperature survey. The objective of the optimization option is to allow the user to fit the model output temperature curve to a selected temperature curve by means of a genetic fitting algorithm that will adjust one or two user-selected reservoir parameters, such as permeability, pressure, skin, gas-oil ratio (GOR), temperature, or water-cut, until a fit is achieved.\u0000 The model has been extensively tested against synthetic, literature and field examples and good agreements have been obtained, confirming the robustness of this novel approach.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73433681","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}
Unconventional oil and gas reservoirs are being explored significantly around the globe nowadays. The economical production of hydrocarbons from these unconventional oil and gas reservoirs like CBM requires very advanced and cost effective technologies. Hydraulic fracturing is such a technology which is being used in the oil and gas industry for many decades to create highly conductive channels in the formations having very low permeability values. Multistage hydraulic fracturing has been proved to be a great achievement in oil and gas industry to enhance the production from unconventional reservoirs. An effective hydraulic fracturing planning & execution is a key to achieve the expected results in terms of production from unconventional reservoirs such as tight gas, shale gas, coal bed methane or other very low permeability reservoirs. Unconventional reservoirs such as Shale & CBM require large scale hydraulic fracturing operations, where multiple frac fleets, wire-line units, coiled tubing units; work-over rigs & ancillary services are mobilized. A scheduling software based project management approach was followed at CBM Raniganj for planning & modeling of operations. This paper aims to study how the operational resource deployed in Raniganj field for hydraulic fracturing was optimized in terms of time, cost & load for fracturing operations. The approach of modeling & planning the hydraulic fracturing operations is based on project management & scheduling software. Assumptions were finalized based on experience. The loopholes, possible schedule slippages and other deterrents which could cause a lag in the hydro fracturing campaign aimed to pump over 1,600 frac jobs in CBM Raniganj field, over a period of 30 rig months, were identified clearly. The scope, time, budget & quality standards were clearly defined and a schedule was prepared with the help of the scheduling software to run the fleets in a clockwork manner. Activities like perforation, Acidizing, data fracturing, main fracturing, flowback, sand plug and finally sand cleanout were defined as series & simultaneous operation.
{"title":"A Blueprint to Manage Large Scale Unconventional Multistage Fracturing Operations: A Case Study of Raniganj CBM Field.","authors":"Anjani Kumar, Rishiraj Goswami","doi":"10.2118/194690-MS","DOIUrl":"https://doi.org/10.2118/194690-MS","url":null,"abstract":"\u0000 Unconventional oil and gas reservoirs are being explored significantly around the globe nowadays. The economical production of hydrocarbons from these unconventional oil and gas reservoirs like CBM requires very advanced and cost effective technologies. Hydraulic fracturing is such a technology which is being used in the oil and gas industry for many decades to create highly conductive channels in the formations having very low permeability values. Multistage hydraulic fracturing has been proved to be a great achievement in oil and gas industry to enhance the production from unconventional reservoirs. An effective hydraulic fracturing planning & execution is a key to achieve the expected results in terms of production from unconventional reservoirs such as tight gas, shale gas, coal bed methane or other very low permeability reservoirs.\u0000 Unconventional reservoirs such as Shale & CBM require large scale hydraulic fracturing operations, where multiple frac fleets, wire-line units, coiled tubing units; work-over rigs & ancillary services are mobilized. A scheduling software based project management approach was followed at CBM Raniganj for planning & modeling of operations. This paper aims to study how the operational resource deployed in Raniganj field for hydraulic fracturing was optimized in terms of time, cost & load for fracturing operations.\u0000 The approach of modeling & planning the hydraulic fracturing operations is based on project management & scheduling software. Assumptions were finalized based on experience. The loopholes, possible schedule slippages and other deterrents which could cause a lag in the hydro fracturing campaign aimed to pump over 1,600 frac jobs in CBM Raniganj field, over a period of 30 rig months, were identified clearly. The scope, time, budget & quality standards were clearly defined and a schedule was prepared with the help of the scheduling software to run the fleets in a clockwork manner. Activities like perforation, Acidizing, data fracturing, main fracturing, flowback, sand plug and finally sand cleanout were defined as series & simultaneous operation.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82199799","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}
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention. To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount. The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system. The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
{"title":"Numerical Study on Casing Integrity During Hydraulic Fracturing Shale Formation","authors":"Xiaye Wu, Lihong Han, Shang-yu Yang, Fei Yin, C. Teodoriu, Xingru Wu","doi":"10.2118/195203-MS","DOIUrl":"https://doi.org/10.2118/195203-MS","url":null,"abstract":"\u0000 Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.\u0000 To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.\u0000 The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.\u0000 The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.","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":"81887632","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}
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems. The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
{"title":"A Critical Review of Using High Viscosity Friction Reducers as Fracturing Fluids for Hydraulic Fracturing Applications","authors":"M. B. Geri, Abdulmohsin Imqam, R. Flori","doi":"10.2118/195191-MS","DOIUrl":"https://doi.org/10.2118/195191-MS","url":null,"abstract":"\u0000 The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.\u0000 The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90441254","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}
C. Bhardwaj, V. Ranjan, S. Jetley, S. Tiwari, A. Ghosh, Swapnil Sharma, A. Bohra, Abhishek Kumar, Abhudai Beohar, Sidharth Sharma
The Raageshwari Deep Gas (RDG) field, situated within Barmer Basin in the State of Rajasthan, India, was discovered in 2003. The field is a tight gas condensate reservoir, with excellent gas quality of approximately 80% methane, low CO2 and no H2S. Since the permeability (0.01 - 1 md) is low in this reservoir, hydraulic fracturing is required to get substantial recovery from the wells. The field has been under production since 2010. The development of this field has been carried out in three phases and more than 150 fracturing treatments have been pumped in this reservoir till date to achieve sustained economical production. This paper deals with the lessons learnt and changes implemented in choke design through various development phases of the field. In the initial phase of field development, chokes with a low Flow Coefficient (Cv) were installed to meet the requirement of controlling the wells at low flow rates and high differential pressure. Later as the surface handling capacity increased, the chokes had to be de-bottlenecked, requiring additional Capex for new chokes. To avoid a similar scenario in the future, a comprehensive approach has been followed to envisage Cv requirement, considering well wise production profiles and surface handling capacities throughout the life of field. Since a single trim can't operate over the complete life-cycle of a well, trim interchangeability has been included in the choke design such that low and high Cv trims are interchangeable. Pre-mature failures of trims were observed in initial phase and a root cause analysis was done to ascertain the reason. Based on the analysis, trim metallurgy has been changed from Tungsten Carbide to ASTM A276 Specific Stainless Steel Grade 440C. Trims with newly selected mettalurgy have been installed in the existing chokes. The introduction of trim interchangeability has saved MMUSD 0.3 in the future Opex as the requirement of procuring altogether new chokes for late life period of wells is avoided. Initially failures in the trim bodies were observed as early as two months of commissioning but with the change in metallurgy zero failures have been observed with operational life of chokes being higher than four years. This has avoided significant downtime on wells and expenditure on regular trim changeovers. Although Tungsten Carbide is one of the most common materials used for constructing trims world over, there could be specific cases where-in other metallurgy may add better value. The workflow followed in this paper will help select a suitable metallurgy and can impart a significant value to the industry.
{"title":"Case Study: Metallurgy Selection and Choke Design Incorporating Trim Interchangeability to Cater to the Entire Production Lifecycle of Raageshwari Deep Gas Field","authors":"C. Bhardwaj, V. Ranjan, S. Jetley, S. Tiwari, A. Ghosh, Swapnil Sharma, A. Bohra, Abhishek Kumar, Abhudai Beohar, Sidharth Sharma","doi":"10.2118/194562-MS","DOIUrl":"https://doi.org/10.2118/194562-MS","url":null,"abstract":"\u0000 The Raageshwari Deep Gas (RDG) field, situated within Barmer Basin in the State of Rajasthan, India, was discovered in 2003. The field is a tight gas condensate reservoir, with excellent gas quality of approximately 80% methane, low CO2 and no H2S. Since the permeability (0.01 - 1 md) is low in this reservoir, hydraulic fracturing is required to get substantial recovery from the wells. The field has been under production since 2010. The development of this field has been carried out in three phases and more than 150 fracturing treatments have been pumped in this reservoir till date to achieve sustained economical production. This paper deals with the lessons learnt and changes implemented in choke design through various development phases of the field.\u0000 In the initial phase of field development, chokes with a low Flow Coefficient (Cv) were installed to meet the requirement of controlling the wells at low flow rates and high differential pressure. Later as the surface handling capacity increased, the chokes had to be de-bottlenecked, requiring additional Capex for new chokes. To avoid a similar scenario in the future, a comprehensive approach has been followed to envisage Cv requirement, considering well wise production profiles and surface handling capacities throughout the life of field. Since a single trim can't operate over the complete life-cycle of a well, trim interchangeability has been included in the choke design such that low and high Cv trims are interchangeable.\u0000 Pre-mature failures of trims were observed in initial phase and a root cause analysis was done to ascertain the reason. Based on the analysis, trim metallurgy has been changed from Tungsten Carbide to ASTM A276 Specific Stainless Steel Grade 440C. Trims with newly selected mettalurgy have been installed in the existing chokes.\u0000 The introduction of trim interchangeability has saved MMUSD 0.3 in the future Opex as the requirement of procuring altogether new chokes for late life period of wells is avoided. Initially failures in the trim bodies were observed as early as two months of commissioning but with the change in metallurgy zero failures have been observed with operational life of chokes being higher than four years. This has avoided significant downtime on wells and expenditure on regular trim changeovers.\u0000 Although Tungsten Carbide is one of the most common materials used for constructing trims world over, there could be specific cases where-in other metallurgy may add better value. The workflow followed in this paper will help select a suitable metallurgy and can impart a significant value to the industry.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"244 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91470631","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. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, A. Amer
Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated non-productive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood. In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors – solid contents (SC), yield point (Yp), and plastic viscosity (PV) – on ECD. Data from over 1000 wells drilled in thirteen oilfields in Iraq were collected, tested for outliers, and examined for normality to appropriately select the method of the analysis. The results showed that all three parameters have a direct relationship with ECD, or in other words, increasing the values of these parameters will lead to increasing ECD values. However, the plastic viscosity effect showed the highest magnitude, or strongest relationship to ECD, while the yield point resulted in the lowest effect, or weakest relationship with ECD from among these three parameters. Therefore, it is crucial to pay close attention to the magnitude of PV and alter it accordingly. Understanding the relationship between the drilling fluid rheological properties and ECD is vital for better ECD management in order to minimize the non-productive time and cost associated with ECD-related drilling problems.
{"title":"Insights into the Relationship between Equivalent Circulation Density and Drilling Fluid Rheological Properties","authors":"A. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, A. Amer","doi":"10.2118/194623-MS","DOIUrl":"https://doi.org/10.2118/194623-MS","url":null,"abstract":"\u0000 Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated non-productive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood.\u0000 In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors – solid contents (SC), yield point (Yp), and plastic viscosity (PV) – on ECD. Data from over 1000 wells drilled in thirteen oilfields in Iraq were collected, tested for outliers, and examined for normality to appropriately select the method of the analysis.\u0000 The results showed that all three parameters have a direct relationship with ECD, or in other words, increasing the values of these parameters will lead to increasing ECD values. However, the plastic viscosity effect showed the highest magnitude, or strongest relationship to ECD, while the yield point resulted in the lowest effect, or weakest relationship with ECD from among these three parameters. Therefore, it is crucial to pay close attention to the magnitude of PV and alter it accordingly.\u0000 Understanding the relationship between the drilling fluid rheological properties and ECD is vital for better ECD management in order to minimize the non-productive time and cost associated with ECD-related drilling problems.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82827280","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}
Olzhas Zhandayev, Gaukharbek Ungaliyev, Biju James
Historically underreaming while drilling (UWD) operations were implemented in offshore field in Azerbaijan to decrease Equivalent Circulating Density (ECD) and have better hole quality for casing running. Lithology in this UWD, 8.5 × 10.25-inch section consists of sand and shales with 3-5kpsi Unconfined Compressive Strength (UCS). Well trajectory has planned dogleg severity up to 3-3.5 deg/30m. In such a condition underreaming operations are known to be more challenging and complex compared to conventional drilling with bit only. In the offset well, an operator had fatigue related twist off at the reamer's lower sub connection which contributed to 58 hours of NPT. Our challenge was to come up with the root cause of the twist off and then suggest changes in BHA to avoid this and prove that the modified BHA performs as expected. Our finite element analysis (FEA) based 4D modeling software can identify different vibrations (axial, lateral, stick slip), bending stresses and bending moment of each component in the BHA. Using this software, we were able to come up with the root cause of the twist off, which was due to high bending stress. In UWD there are two cutting structures in the BHA, so optimizing both cutting structures has a significant impact on the overall performance. Successful run key points are to analyze the underreamer placement in BHA, operating parameters selection for different scenarios (when both bit and undereamer are in the same rocks or when the bit is in soft and undereamer is in hard rock), lateral vibrations and whirling phenomenon which can potentially damage and develop fatigue on BHA components. Multiple BHA's were simulated and based on the results the most stable BHA was recommended for the upcoming well. The operator implemented the recommended BHA and a total of 1200m was successfully drilled and opened in one run without any NPT. All directional requirements were achieved and both bit and underreamer came out in good condition which confirmed that the new optimized BHA was stable in the downhole drilling conditions. The liner was also run without any issue confirming the borehole quality. This paper will review the results of analysis and how modeling prediction was validated in the field.
{"title":"How to Avoid Bottom Hole Assembly Twist Off Challenges in Underreaming While Drilling Operations Using 4D Finite Element Analysis Modelling","authors":"Olzhas Zhandayev, Gaukharbek Ungaliyev, Biju James","doi":"10.2118/195213-MS","DOIUrl":"https://doi.org/10.2118/195213-MS","url":null,"abstract":"\u0000 Historically underreaming while drilling (UWD) operations were implemented in offshore field in Azerbaijan to decrease Equivalent Circulating Density (ECD) and have better hole quality for casing running. Lithology in this UWD, 8.5 × 10.25-inch section consists of sand and shales with 3-5kpsi Unconfined Compressive Strength (UCS). Well trajectory has planned dogleg severity up to 3-3.5 deg/30m. In such a condition underreaming operations are known to be more challenging and complex compared to conventional drilling with bit only. In the offset well, an operator had fatigue related twist off at the reamer's lower sub connection which contributed to 58 hours of NPT.\u0000 Our challenge was to come up with the root cause of the twist off and then suggest changes in BHA to avoid this and prove that the modified BHA performs as expected. Our finite element analysis (FEA) based 4D modeling software can identify different vibrations (axial, lateral, stick slip), bending stresses and bending moment of each component in the BHA. Using this software, we were able to come up with the root cause of the twist off, which was due to high bending stress.\u0000 In UWD there are two cutting structures in the BHA, so optimizing both cutting structures has a significant impact on the overall performance. Successful run key points are to analyze the underreamer placement in BHA, operating parameters selection for different scenarios (when both bit and undereamer are in the same rocks or when the bit is in soft and undereamer is in hard rock), lateral vibrations and whirling phenomenon which can potentially damage and develop fatigue on BHA components. Multiple BHA's were simulated and based on the results the most stable BHA was recommended for the upcoming well.\u0000 The operator implemented the recommended BHA and a total of 1200m was successfully drilled and opened in one run without any NPT. All directional requirements were achieved and both bit and underreamer came out in good condition which confirmed that the new optimized BHA was stable in the downhole drilling conditions. The liner was also run without any issue confirming the borehole quality.\u0000 This paper will review the results of analysis and how modeling prediction was validated in the field.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90432982","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}
In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN). In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.
{"title":"Leveraging Improvements in Unitization to Reduce Mobilization Costs for Land Drilling Rigs","authors":"Cole Carpenter, L. Richards","doi":"10.2118/195233-MS","DOIUrl":"https://doi.org/10.2118/195233-MS","url":null,"abstract":"\u0000 In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN).\u0000 In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"263 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77151646","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}
P. Saikia, U. Dutta, Ranjit Tumung, S. Verma, A. Ahmed, A. Mukerjee
Radial jet drilling is a widely used environment friendly technique to improve well productivity in tight reservoirs, accelerate production in low-to-medium permeability wells, revamp production in mature wells with formation damage. This technique has helped to enhance production from mature field by bypassing skin, extend the connectivity of the wellbore beyond the near well bore area by drilling laterals using high pressure water jet, and thereby alleviate production restrictions caused by near well bore damage and extend the reach of the wellbore far into the formation. Production, being dependent on reservoir contact of the well bore is therefore increased as average reservoir contact is enhanced by the drain holes. However, selection is equally important as all wells cannot be considered as a suitable candidate and unsuitable candidate selection can show detrimental outcomes. The technology was applied in a sandstone reservoir where a 22 mm hole was created in the casing at the target depth and then 50 mm OD lateral of length 100m was drilled in the reservoir using high pressure hydraulic jet. The accurate placement and orientation of downhole tool plays a significant role in the success of this technology and is found to be always challenging. Preventing casing milling in undesired azimuths, eliminating chances of lateral overlapping are some challenges that essential to be addressed for gaining optimum advantages. One of the promising technologies to address these challenges was the application of Surface Recording Gyro System. The application of surface recording gyroscopic well bore navigation system provides accurate placement of tool for lateral exit in the down hole and thus enable creation of lateral in the desired direction. This paper discusses candidate selection and execution carried out in 7 nos. of wells in OIL INDIA LIMITED utilizing surface read out gyro system, which was done for the first time in INDIA. This paper also discusses about a post job analysis and lesson learnt with depths varying from 2414m to 3472m, the deepest well in India where radial drilling was carried out successfully. Post radial drilling on wells which had no/poor production prior to radial drilling showed very encouraging results. It also details about criteria of well selection, step by step procedure of the process, bottom hole tool selection, jetting and milling fluid used along with function, application, advantages of surface read out gyro system. As stimulations and well preparation in complicated wells are capital intensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to design and creation of the horizontal laterals in desired azimuth utilizing the surface readout gyro system along with radial jet drilling for maximizing oil recovery.
径向射流钻井是一种广泛应用的环境友好型钻井技术，可以提高致密储层的产能，加快中低渗透井的生产，改善有地层损害的成熟井的产量。该技术通过绕过表皮，帮助成熟油田提高了产量，通过使用高压水射流钻水平段，将井筒的连通性扩展到近井眼区域之外，从而缓解了近井眼损害造成的生产限制，并将井筒延伸到地层中。因此，由于产油依赖于井筒与储层的接触，因此随着平均储层接触的增加，排水孔也会增加。然而，选择同样重要，因为并非所有井都是合适的候选者，而不合适的候选者选择可能会产生不利的结果。该技术应用于砂岩储层，在目标深度的套管上钻了一个22mm的孔，然后使用高压水力射流在储层中钻了50mm外径、长度为100m的分支。井下工具的精确定位和定向对该技术的成功起着至关重要的作用，但始终具有挑战性。为了获得最佳优势，防止套管在不理想的方位角磨铣，消除横向重叠的可能性是必须解决的一些挑战。其中一个有前途的技术，以解决这些挑战是地面记录陀螺仪系统的应用。地面记录陀螺仪井筒导航系统的应用，可以在井下精确定位分支出口工具，从而实现在期望的方向上创建分支出口。本文讨论了OIL INDIA LIMITED公司在印度首次采用地面读出陀螺仪系统进行的7口井的备选井选择和执行。本文还讨论了作业后的分析和经验教训，深度从2414m到3472m不等，这是印度最深井，在该井中成功进行了径向钻井。在进行径向钻井之前，对那些没有或产量很差的井进行了后径向钻井，结果非常令人鼓舞。详细介绍了井壁读数陀螺仪的选井标准、分步工艺流程、井底工具的选择、使用的喷磨液、喷磨液以及地面读数陀螺仪的功能、应用和优点。由于复杂井的增产和准备是资本密集型的，因此在准备井和进一步采油之前，利用现有数据集确定最合适的候选井是至关重要的。通过定制的工作流程，利用地面读数陀螺仪系统和径向射流钻井，设计和创建所需方位的水平分支，以最大限度地提高石油采收率。
{"title":"Application of Radial Jet Drilling Technique with Gyro System to Enhance Reservoir Potential in Mature Sand Stone Reservoir in Assam-Arakan Basin Candidate Selection to Execution: A Detailed Case Study","authors":"P. Saikia, U. Dutta, Ranjit Tumung, S. Verma, A. Ahmed, A. Mukerjee","doi":"10.2118/194595-MS","DOIUrl":"https://doi.org/10.2118/194595-MS","url":null,"abstract":"\u0000 Radial jet drilling is a widely used environment friendly technique to improve well productivity in tight reservoirs, accelerate production in low-to-medium permeability wells, revamp production in mature wells with formation damage. This technique has helped to enhance production from mature field by bypassing skin, extend the connectivity of the wellbore beyond the near well bore area by drilling laterals using high pressure water jet, and thereby alleviate production restrictions caused by near well bore damage and extend the reach of the wellbore far into the formation. Production, being dependent on reservoir contact of the well bore is therefore increased as average reservoir contact is enhanced by the drain holes. However, selection is equally important as all wells cannot be considered as a suitable candidate and unsuitable candidate selection can show detrimental outcomes.\u0000 The technology was applied in a sandstone reservoir where a 22 mm hole was created in the casing at the target depth and then 50 mm OD lateral of length 100m was drilled in the reservoir using high pressure hydraulic jet. The accurate placement and orientation of downhole tool plays a significant role in the success of this technology and is found to be always challenging. Preventing casing milling in undesired azimuths, eliminating chances of lateral overlapping are some challenges that essential to be addressed for gaining optimum advantages. One of the promising technologies to address these challenges was the application of Surface Recording Gyro System. The application of surface recording gyroscopic well bore navigation system provides accurate placement of tool for lateral exit in the down hole and thus enable creation of lateral in the desired direction.\u0000 This paper discusses candidate selection and execution carried out in 7 nos. of wells in OIL INDIA LIMITED utilizing surface read out gyro system, which was done for the first time in INDIA. This paper also discusses about a post job analysis and lesson learnt with depths varying from 2414m to 3472m, the deepest well in India where radial drilling was carried out successfully. Post radial drilling on wells which had no/poor production prior to radial drilling showed very encouraging results. It also details about criteria of well selection, step by step procedure of the process, bottom hole tool selection, jetting and milling fluid used along with function, application, advantages of surface read out gyro system.\u0000 As stimulations and well preparation in complicated wells are capital intensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to design and creation of the horizontal laterals in desired azimuth utilizing the surface readout gyro system along with radial jet drilling for maximizing oil recovery.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74139634","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. Torres, Wei Yu, Reza Ganjdanesh, E. Kerr, K. Sepehrnoori, J. Miao, R. Ambrose
Optimizing spacing of infill wells and fractures can lead to large rewards for shale field operators, and these considerations have influences on primary and tertiary development of the field. Although several studies have been employed to show the existence of well interference, few models have also implemented Huff-n-Puff and injection containment methods to optimize further hydraulic fracture designs and pressure containment to improve the efficiency of Enhanced Oil Recovery (EOR). This study has performed a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of interwell interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial compositional reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching to propose profitable opportunities for Huff-n-Puff application. First, based on a robust understanding of fracture properties, updated production data and multi-pad wellbore image logging data from Eagle Ford, the model was constructed to perform nine wells sector model history matching. Later, inter-well connecting fractures were employed for enhanced history matching where results varied significantly from unmeasured fracture sensitivities. The result is the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthened the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation and ductility to be represented in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest. The model has become a valuable template to inform the impacts on well location and spacing, completion design, initial huff-n-puff decisions, subsequent containment strategies (e.g. to improve cycle timing and efficiency), and to expand to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiency.
{"title":"Modeling Interwell Fracture Interference and Huff-N-Puff Pressure Containment in Eagle Ford Using EDFM","authors":"M. Torres, Wei Yu, Reza Ganjdanesh, E. Kerr, K. Sepehrnoori, J. Miao, R. Ambrose","doi":"10.2118/195240-MS","DOIUrl":"https://doi.org/10.2118/195240-MS","url":null,"abstract":"\u0000 Optimizing spacing of infill wells and fractures can lead to large rewards for shale field operators, and these considerations have influences on primary and tertiary development of the field. Although several studies have been employed to show the existence of well interference, few models have also implemented Huff-n-Puff and injection containment methods to optimize further hydraulic fracture designs and pressure containment to improve the efficiency of Enhanced Oil Recovery (EOR). This study has performed a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of interwell interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial compositional reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching to propose profitable opportunities for Huff-n-Puff application. First, based on a robust understanding of fracture properties, updated production data and multi-pad wellbore image logging data from Eagle Ford, the model was constructed to perform nine wells sector model history matching. Later, inter-well connecting fractures were employed for enhanced history matching where results varied significantly from unmeasured fracture sensitivities. The result is the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthened the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation and ductility to be represented in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest.\u0000 The model has become a valuable template to inform the impacts on well location and spacing, completion design, initial huff-n-puff decisions, subsequent containment strategies (e.g. to improve cycle timing and efficiency), and to expand to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiency.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81202809","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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