Arfan Ali, Azimah Jofri, Norshah Zamikhan, Jahnabi Borah, Mohd Noor Isa Yahya, Erik van den Heuvel, Igor Kim, N. Hardikar, S. Coskun
Since the advancement of Focused Sampling techniques, wireline formation fluid sampling has undergone a dramatic change. This has primarily been due to the promise of acquiring representative formation fluid samples with minimal mud filtrate contamination and large sample volumes, thereby adding value to the PVT laboratory studies as well as reducing the fluid sampling time, thus aiding significantly to the cost savings. This paper demonstrates the contribution of focused sampling technology for reservoir fluid mapping in numerous exploration and development wells in South East (SE) Asia, by optimized selection of different packer types based on varying reservoir properties. For the exploration wells, the primary objective was to determine the non-hydrocarbon (non-HC) content (CO2 and H2S in this case) of the single-phase reservoir fluid samples, which were expected to be close to the saturation pressures. Following the 3D near-wellbore simulations, an elongated and an extra-elongated focused packer were selected due to expected low permeabilities, reservoir thickness and wellbore conditions. The wells were drilled in managed pressure drilling (MPD) conditions, with overbalance ranging from 900 to 4,300 psi. The development campaign consisted of five producers with key objectives of determining fluid type and the non-HC (CO2 in this case) content along with assessing the reservoir/block connectivity. The concentration and uncertainty in CO2 distribution would have a major impact in developing the production strategy of the area. A standard focused packer was selected for the sampling jobs which were carried out on pipe due to high overbalance conditions (~2,400 psi). In the exploration wells, 30+ samples (gas, oil and water) were collected with the time-on-wall ranging between 1.5 and 7 hours. In the development campaign, 50+ samples (gas and oil) were collected with the time-on-wall ranging between 45 minutes and 2.5 hours. Given the depths and low permeabilities of the reservoirs with high overbalance, this resulted in significant time savings. The larger flow area of the elongated and extra-elongated focused packers ensured minimal contamination in the collected samples given the challenging sampling conditions, where restrictions to pressure drawdown existed. The PVT laboratory results showed ‘insignificant’ oil-based mud filtrate contamination in the samples. In addition, the large sample volumes provided flexibility for additional PVT studies and improved resource assessment. The focused sampling technology was successfully applied in both exploration and development campaigns in the SE Asia region. The pre-job simulations ensured optimal packer selection between the three focused packer types. The comparison between the actual sampling results and the 3D near-wellbore simulation would help optimize future sampling operations in the area. In addition, the two campaigns have reiterated a clear value of information in saving cost, reduci
{"title":"Bringing the Best to Downhole Fluid Sampling by Evaluating the Focused Sampling Technique with Multiple Packer Types in Exploration and Development Wells – Case Studies from South East Asia","authors":"Arfan Ali, Azimah Jofri, Norshah Zamikhan, Jahnabi Borah, Mohd Noor Isa Yahya, Erik van den Heuvel, Igor Kim, N. Hardikar, S. Coskun","doi":"10.2118/197326-ms","DOIUrl":"https://doi.org/10.2118/197326-ms","url":null,"abstract":"\u0000 Since the advancement of Focused Sampling techniques, wireline formation fluid sampling has undergone a dramatic change. This has primarily been due to the promise of acquiring representative formation fluid samples with minimal mud filtrate contamination and large sample volumes, thereby adding value to the PVT laboratory studies as well as reducing the fluid sampling time, thus aiding significantly to the cost savings. This paper demonstrates the contribution of focused sampling technology for reservoir fluid mapping in numerous exploration and development wells in South East (SE) Asia, by optimized selection of different packer types based on varying reservoir properties.\u0000 For the exploration wells, the primary objective was to determine the non-hydrocarbon (non-HC) content (CO2 and H2S in this case) of the single-phase reservoir fluid samples, which were expected to be close to the saturation pressures. Following the 3D near-wellbore simulations, an elongated and an extra-elongated focused packer were selected due to expected low permeabilities, reservoir thickness and wellbore conditions. The wells were drilled in managed pressure drilling (MPD) conditions, with overbalance ranging from 900 to 4,300 psi. The development campaign consisted of five producers with key objectives of determining fluid type and the non-HC (CO2 in this case) content along with assessing the reservoir/block connectivity. The concentration and uncertainty in CO2 distribution would have a major impact in developing the production strategy of the area. A standard focused packer was selected for the sampling jobs which were carried out on pipe due to high overbalance conditions (~2,400 psi).\u0000 In the exploration wells, 30+ samples (gas, oil and water) were collected with the time-on-wall ranging between 1.5 and 7 hours. In the development campaign, 50+ samples (gas and oil) were collected with the time-on-wall ranging between 45 minutes and 2.5 hours. Given the depths and low permeabilities of the reservoirs with high overbalance, this resulted in significant time savings. The larger flow area of the elongated and extra-elongated focused packers ensured minimal contamination in the collected samples given the challenging sampling conditions, where restrictions to pressure drawdown existed. The PVT laboratory results showed ‘insignificant’ oil-based mud filtrate contamination in the samples. In addition, the large sample volumes provided flexibility for additional PVT studies and improved resource assessment.\u0000 The focused sampling technology was successfully applied in both exploration and development campaigns in the SE Asia region. The pre-job simulations ensured optimal packer selection between the three focused packer types. The comparison between the actual sampling results and the 3D near-wellbore simulation would help optimize future sampling operations in the area. In addition, the two campaigns have reiterated a clear value of information in saving cost, reduci","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74771844","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}
Tapas Ray, Faisal Ibrahim Alharam, Mohamed Abdulla Shayea, Ali Saleh Al Hammadi, Abdulla Humaid AL-Jarwan, Jumaan Mohamed Al-Breiki, Mohamed Ali Bani Hamoor, Nagendra Rustagi
There was an urgent requirement for a low-cost fast-track solution to increase the oil processing capacity in one of the ADNOC Offshore facilities in order to facilitate the scheduled maintainence of the Oil Trains as well as to handle additional production before a new train is commissioned. Capacity of each of the four Oil Trains is primarily limited by the vibration problem of the 1st vessel (Inlet Sphere) in the train, due to which field tests could not be performed to establish Oil Train maximum throughput. It was concluded through detailed studies, including Computation Fluid Dynamic Analysis, that there is no techno-economically feasible solution to overcome the vibration problem of the Inlet Spheres. However, the problem could be circumvented if the extra flow is routed to the downstream facilities by bypassing the Inlet Sphere completely. The objective of this in-house study is to find a low-cost solution to overcome the limitation of the Inlet Spheres and other bottlenecks in the trains. Based on the debottlenecking study outcome, it was proposed to use the stand-by Emergency Sphere - while retaining its original design functionality of handling emergency liquid relief - and its associated Crude Transfer Pump to transfer the additional flow (above the Inlet Sphere allowable capacity) directly to the Inlet Sphere downstream system. Similarly, course of actions were also identified for other bottlenecks. Based on the debottlenecking study recommendations, it was agreed to carry out the modification in two of the four Oil Trains considering the Crude Transfer Pump capacity limitation as well as to keep the cost to minimum by maximizing the usage of the existing assets. Subsequent to the modifications, field tests were conducted and test result showed that the oil-handling capacity of each Oil Train could be increased by 17%. No change in the operating conditions of the existing facilities were required and all the specifications of export crude oil were also met. Based on the test results, other improvements were also suggested. Accordingly, it was concluded to embark on executing the proposed modifications for all the Oil Trains. The debottlenecking scheme, which is implemented at a cost of ~1 Million USD, is able to generate a revenue of ~2 Million USD per day. Hence, the scheme when extended to the all the four trains would generate a revenue of ~8 Million USD per day. Execution cost for this modification for all the four trains is estimated to be less than 15 Million USD, whereas a new train of similar capacity would cost more than 200 Million USD. This paper highlights how in-house Technical Support can provide a fit-for-purpose and cost-effective solution to Company’s business needs. The study is a perfect example of "Maximizing Value of Every Barrel Produced".
{"title":"Debottlenecking of Oil Processing Train Capacity","authors":"Tapas Ray, Faisal Ibrahim Alharam, Mohamed Abdulla Shayea, Ali Saleh Al Hammadi, Abdulla Humaid AL-Jarwan, Jumaan Mohamed Al-Breiki, Mohamed Ali Bani Hamoor, Nagendra Rustagi","doi":"10.2118/197608-ms","DOIUrl":"https://doi.org/10.2118/197608-ms","url":null,"abstract":"\u0000 There was an urgent requirement for a low-cost fast-track solution to increase the oil processing capacity in one of the ADNOC Offshore facilities in order to facilitate the scheduled maintainence of the Oil Trains as well as to handle additional production before a new train is commissioned. Capacity of each of the four Oil Trains is primarily limited by the vibration problem of the 1st vessel (Inlet Sphere) in the train, due to which field tests could not be performed to establish Oil Train maximum throughput. It was concluded through detailed studies, including Computation Fluid Dynamic Analysis, that there is no techno-economically feasible solution to overcome the vibration problem of the Inlet Spheres. However, the problem could be circumvented if the extra flow is routed to the downstream facilities by bypassing the Inlet Sphere completely. The objective of this in-house study is to find a low-cost solution to overcome the limitation of the Inlet Spheres and other bottlenecks in the trains. Based on the debottlenecking study outcome, it was proposed to use the stand-by Emergency Sphere - while retaining its original design functionality of handling emergency liquid relief - and its associated Crude Transfer Pump to transfer the additional flow (above the Inlet Sphere allowable capacity) directly to the Inlet Sphere downstream system. Similarly, course of actions were also identified for other bottlenecks. Based on the debottlenecking study recommendations, it was agreed to carry out the modification in two of the four Oil Trains considering the Crude Transfer Pump capacity limitation as well as to keep the cost to minimum by maximizing the usage of the existing assets.\u0000 Subsequent to the modifications, field tests were conducted and test result showed that the oil-handling capacity of each Oil Train could be increased by 17%. No change in the operating conditions of the existing facilities were required and all the specifications of export crude oil were also met. Based on the test results, other improvements were also suggested. Accordingly, it was concluded to embark on executing the proposed modifications for all the Oil Trains.\u0000 The debottlenecking scheme, which is implemented at a cost of ~1 Million USD, is able to generate a revenue of ~2 Million USD per day. Hence, the scheme when extended to the all the four trains would generate a revenue of ~8 Million USD per day. Execution cost for this modification for all the four trains is estimated to be less than 15 Million USD, whereas a new train of similar capacity would cost more than 200 Million USD.\u0000 This paper highlights how in-house Technical Support can provide a fit-for-purpose and cost-effective solution to Company’s business needs. The study is a perfect example of \"Maximizing Value of Every Barrel Produced\".","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75919222","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}
Yazan Ghassan Mheibesh, M. Fraim, A. Sultan, Fahad Hassan Al Shehri
The purpose of this scoping model study of Zarrarah field, with ~14 BSTB, and ~30 TSCF OIIP and GIIP respectively, was to show that natural gas cap could be used in a zero emission power plant to generate electricity, produce NGLs, and capture carbon dioxide gas. Over the lifetime of the project, the injected CO2 gas will displace the oil column in the heterogeneous carbonate rock system in a miscible gravity dominate mode. Petrophysical data needed to construct a simulation model for Zarrarh field was collected from literature review. We used 12 analogous rock types from neighboring fields of Asab and Bu Hasa. The CMG-GEM reservoir model used 18 components to describe the fluid properties and to verify no asphaltene drop out near the producing well bore. The model was calibrated on total field oil production and gas oil ratio and then various CO2 flooding scenarios were tested to optimize recovery and minimize gas coning in the horizontal well flooding patterns. The current production method for Zarrarah field is gas cap expansion with recycling of lean methane gas into the gas cap for pressure maintenance and recovery of NGLs. The averaged over the heterogeneous rock type regions, the miscible CO2 flood recovered at least 20% additional oil for each reservoir sector. The percentage of produced NGLs from the total in place will increase from 23% to 36% over the lifetime of the project with CO2 extraction. This production method will also supply for UAE and KSA at least 20 GW of zero emissions electric power for the next thirty years. CO2 reduces the oil viscosity and reduces gas coning by swelling the oil in the natural fractures system. The optimal CO2 injection technique is flank injection starting at the northern end of Zarrarah field. At the end of project life, the CO2 gas reserves should approach 30 TSCF to flood other reservoirs in the Empty Quarter such as Shah oil field. The novelty of this work is designing the first economic and zero emission power plant for EOR in KSA and UAE. Generating the first economic man-made CO2 storage reservoir for future miscible oil recovery in the Empty Quarter. The increased NGL recovery will help supply the feed stock for the petrochemical industry for the next 30 years. This technique has also the ability of providing a fresh water source for low salinity water flooding or local inhabitants.
{"title":"Scoping Model Study of Carbon Capture and Storage for Enhanced Oil Recovery for the Zarrarah Oil Field in UAE","authors":"Yazan Ghassan Mheibesh, M. Fraim, A. Sultan, Fahad Hassan Al Shehri","doi":"10.2118/197558-ms","DOIUrl":"https://doi.org/10.2118/197558-ms","url":null,"abstract":"\u0000 The purpose of this scoping model study of Zarrarah field, with ~14 BSTB, and ~30 TSCF OIIP and GIIP respectively, was to show that natural gas cap could be used in a zero emission power plant to generate electricity, produce NGLs, and capture carbon dioxide gas. Over the lifetime of the project, the injected CO2 gas will displace the oil column in the heterogeneous carbonate rock system in a miscible gravity dominate mode.\u0000 Petrophysical data needed to construct a simulation model for Zarrarh field was collected from literature review. We used 12 analogous rock types from neighboring fields of Asab and Bu Hasa. The CMG-GEM reservoir model used 18 components to describe the fluid properties and to verify no asphaltene drop out near the producing well bore. The model was calibrated on total field oil production and gas oil ratio and then various CO2 flooding scenarios were tested to optimize recovery and minimize gas coning in the horizontal well flooding patterns.\u0000 The current production method for Zarrarah field is gas cap expansion with recycling of lean methane gas into the gas cap for pressure maintenance and recovery of NGLs. The averaged over the heterogeneous rock type regions, the miscible CO2 flood recovered at least 20% additional oil for each reservoir sector. The percentage of produced NGLs from the total in place will increase from 23% to 36% over the lifetime of the project with CO2 extraction. This production method will also supply for UAE and KSA at least 20 GW of zero emissions electric power for the next thirty years. CO2 reduces the oil viscosity and reduces gas coning by swelling the oil in the natural fractures system. The optimal CO2 injection technique is flank injection starting at the northern end of Zarrarah field. At the end of project life, the CO2 gas reserves should approach 30 TSCF to flood other reservoirs in the Empty Quarter such as Shah oil field.\u0000 The novelty of this work is designing the first economic and zero emission power plant for EOR in KSA and UAE. Generating the first economic man-made CO2 storage reservoir for future miscible oil recovery in the Empty Quarter. The increased NGL recovery will help supply the feed stock for the petrochemical industry for the next 30 years. This technique has also the ability of providing a fresh water source for low salinity water flooding or local inhabitants.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76498097","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}
Sarah Bernardes de Almeida, A. Pereira, E. Ruidiaz, A. Winter, J. V. Vargas, E. Koroishi, O. V. Trevisan, R. V. D. Almeida
The aim of this work is the experimental study of a fractured carbonate rock model for oil recovery evaluation. For this, a new experimental routine regarding petrophysical characterization was developed and validated. The evaluation of oil recovery was performed by mass balance. Also, the heterogeneity of the fractured rock model and the distribution of the saturations was calculated by X-ray computed tomography. An induced fractured was created adding a longitudinal spacer (Lie, 2013) at a reservoir carbonate rock plug from a Brazilian pre-salt reservoir. Drainage process was performed by forced displacement using synthetic formation water and oil from the same reservoir rock. The model was aged at 63°C for 28 days. X-ray computerized tomography was used for porosity and fluid saturations calculations. The initial injection rate was 0.1 cm3/min. After reaching the saturation plateau, the rate was decreased to 0.05 cm3/min to evaluate possible incremental recovery. The developed methodology allowed the construction of a porous media with an induced fracture representative from a naturally fractured reservoir. The rock sample was cut lengthwise with a metal saw. A POM spacer was used to represent the fracture, and glass beads filled the fracture in order to give a representative porosity to the fractured rock model. The petrophysical properties of the matrix and the fracture were obtained during each step of the fractured rock model construction. The matrices porosities obtained were 8% and 14%, and the permeabilities 68 mD and 40 mD, respective to each semicylinder of the plug. The fracture porosity and permeability obtained were 1.6% and 146 Darcy, respectively. For the entire fractured rock model, the porosity was 12.5% and the permeability 5 Darcy. The approach to mimic a drainage method reached an initial water saturation of 57%. The recovery factor obtained by the seawater injection at a 0.1 cm3/min flow rate was 30%. An increase of 3% was obtained when the flow was decreased to 0.05 cm3/min. The CT scan measurement yields additional information such heterogeneity of the model through the porosity profile in the fracture, matrix, and the entire fractured rock model. This work presents an innovative methodology to mimic a natural fractured reservoir model which provided a full routine for petrophysical properties evaluation of a physical model. Besides, computed tomography (CT) scans validated porosity values. Thus, a better understanding of the effects of the flow rate in oil recovery on fractured carbonates rocks and the potential of the model developed for this type of studies could be verified.
{"title":"Experimental Study of Fractured Carbonate Rock Model for Oil Recovery Evaluation","authors":"Sarah Bernardes de Almeida, A. Pereira, E. Ruidiaz, A. Winter, J. V. Vargas, E. Koroishi, O. V. Trevisan, R. V. D. Almeida","doi":"10.2118/197866-ms","DOIUrl":"https://doi.org/10.2118/197866-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The aim of this work is the experimental study of a fractured carbonate rock model for oil recovery evaluation. For this, a new experimental routine regarding petrophysical characterization was developed and validated. The evaluation of oil recovery was performed by mass balance. Also, the heterogeneity of the fractured rock model and the distribution of the saturations was calculated by X-ray computed tomography.\u0000 \u0000 \u0000 \u0000 An induced fractured was created adding a longitudinal spacer (Lie, 2013) at a reservoir carbonate rock plug from a Brazilian pre-salt reservoir. Drainage process was performed by forced displacement using synthetic formation water and oil from the same reservoir rock. The model was aged at 63°C for 28 days. X-ray computerized tomography was used for porosity and fluid saturations calculations. The initial injection rate was 0.1 cm3/min. After reaching the saturation plateau, the rate was decreased to 0.05 cm3/min to evaluate possible incremental recovery.\u0000 \u0000 \u0000 \u0000 The developed methodology allowed the construction of a porous media with an induced fracture representative from a naturally fractured reservoir. The rock sample was cut lengthwise with a metal saw. A POM spacer was used to represent the fracture, and glass beads filled the fracture in order to give a representative porosity to the fractured rock model. The petrophysical properties of the matrix and the fracture were obtained during each step of the fractured rock model construction. The matrices porosities obtained were 8% and 14%, and the permeabilities 68 mD and 40 mD, respective to each semicylinder of the plug. The fracture porosity and permeability obtained were 1.6% and 146 Darcy, respectively. For the entire fractured rock model, the porosity was 12.5% and the permeability 5 Darcy. The approach to mimic a drainage method reached an initial water saturation of 57%. The recovery factor obtained by the seawater injection at a 0.1 cm3/min flow rate was 30%. An increase of 3% was obtained when the flow was decreased to 0.05 cm3/min. The CT scan measurement yields additional information such heterogeneity of the model through the porosity profile in the fracture, matrix, and the entire fractured rock model.\u0000 \u0000 \u0000 \u0000 This work presents an innovative methodology to mimic a natural fractured reservoir model which provided a full routine for petrophysical properties evaluation of a physical model. Besides, computed tomography (CT) scans validated porosity values. Thus, a better understanding of the effects of the flow rate in oil recovery on fractured carbonates rocks and the potential of the model developed for this type of studies could be verified.\u0000","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79771359","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}
Hamad Al-Rashidi, Abdul-Aziz Safar, Baraa Al-Shammari, Nitin L. Rane, Batoul Muhsain, T. Al-Mutairi, Bader S. Al-Mal, N. Al-Kandari, Dalal Mohammad, Bruce Duncan, Hanan F. Al-Saeed, S. Desai, Mariam Kamal
Meeting 2040 KPC Strategic plan objectives and KOC production targets will require adoption of new cost-effective technologies and methods in Kuwait fields, resulting in incremental oil production and extended life of the fields. Long-term oil production through artificial lift application can lead to pressure depletion and water cut incremental in mature fields, which can cause obvious wellbore impairments, particularly in medium to week formations such as Wara and Upper Burgan formations. One of the critical parameters that will have great influence on maturing this strategy is sand management-field development. Recently some of high producing wells perforated in Wara sandstone Formation in the Greater Burgan field in Kuwait have been plugged due to sand production issues. Understanding the causes of this critical challenge will definitely help KOC in finding the optimum sand management work flow and select the right sand control technologies to maximize the oil production in Wara formation. Several sand characterization tests were conducted on core plugs and produced samples collected downhole, ESP wellbore data was linked with well logs analysis and production data for understanding the sand production phenomena within the intervals and help establish a sand collapse model. Based on the lab work, modeling and ESP real time data, a screening benchmark was developed for sand management and control for Wara formation. The unique customized screening criteria will support South East Kuwait (SEK) field development to identify/avoid the potential sanding intervals and sustain oil production at safe drawdown pressure, which definitely will prevent ESP failures and extend the ESP lifetime. The risk assessment for potential sanding intervals has been established to predict sand production in most new Wara wells. Some Wara wells targeting shallower or weaker sands would normally be sand control candidates, by taking into account the completion design, optimizing surface sand management workflow, managing safe drawdown and BHFP levels, and taking advantage of favorable stress vectors through oriented perforation can encompass the sand free well operating envelopes over life of well production and depletion conditions.
{"title":"Deep Learning for Sand Production Analysis and Optimum Workflow in the Greater Burgan Field","authors":"Hamad Al-Rashidi, Abdul-Aziz Safar, Baraa Al-Shammari, Nitin L. Rane, Batoul Muhsain, T. Al-Mutairi, Bader S. Al-Mal, N. Al-Kandari, Dalal Mohammad, Bruce Duncan, Hanan F. Al-Saeed, S. Desai, Mariam Kamal","doi":"10.2118/197922-ms","DOIUrl":"https://doi.org/10.2118/197922-ms","url":null,"abstract":"\u0000 Meeting 2040 KPC Strategic plan objectives and KOC production targets will require adoption of new cost-effective technologies and methods in Kuwait fields, resulting in incremental oil production and extended life of the fields. Long-term oil production through artificial lift application can lead to pressure depletion and water cut incremental in mature fields, which can cause obvious wellbore impairments, particularly in medium to week formations such as Wara and Upper Burgan formations.\u0000 One of the critical parameters that will have great influence on maturing this strategy is sand management-field development. Recently some of high producing wells perforated in Wara sandstone Formation in the Greater Burgan field in Kuwait have been plugged due to sand production issues. Understanding the causes of this critical challenge will definitely help KOC in finding the optimum sand management work flow and select the right sand control technologies to maximize the oil production in Wara formation. Several sand characterization tests were conducted on core plugs and produced samples collected downhole, ESP wellbore data was linked with well logs analysis and production data for understanding the sand production phenomena within the intervals and help establish a sand collapse model. Based on the lab work, modeling and ESP real time data, a screening benchmark was developed for sand management and control for Wara formation. The unique customized screening criteria will support South East Kuwait (SEK) field development to identify/avoid the potential sanding intervals and sustain oil production at safe drawdown pressure, which definitely will prevent ESP failures and extend the ESP lifetime. The risk assessment for potential sanding intervals has been established to predict sand production in most new Wara wells. Some Wara wells targeting shallower or weaker sands would normally be sand control candidates, by taking into account the completion design, optimizing surface sand management workflow, managing safe drawdown and BHFP levels, and taking advantage of favorable stress vectors through oriented perforation can encompass the sand free well operating envelopes over life of well production and depletion conditions.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84862679","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. Moharana, M. Mahapatra, S. Chakraborty, D. Biswal, K. Havelia
Petroleum Geologists have always been a group who looked at rocks, developed and described depositional concepts, mapping structures to discover and develop hydrocarbons for profit. With the advent of new technologies and computing power, geology started to become a lot more quantitative. The first wave of this new revolution was the introduction of geostatistics and the discipline of geomodelling, dealing with quantitative statistics like variograms, histograms, stochastic models which could be used to put a number and range on the geological uncertainty. However, geostatistics which was originally developed in the mining industry in the 1950's deals more with regularly sampled data, describing their spatial variability and directionality. In majority of development fields, with many wells sampling the reservoir, geostatistics helps us to create a feasible proxy for the subsurface reservoirs, when it is backed by a strong conceptual geological foundation. However, as the number of wells decreases, the data for geostatistical analysis reduces and a geomodeller must rely strongly on the conceptual geological knowledge, to build a predictive geological model rather than the noisy picture which over-reliance on blind geostatistics can provide. Until recently, there was no way of quantifying or visualizing depositional concepts in 3D for a geologist save for few block diagrams and average sand distribution maps. However, these were mostly manual, deterministic with a long turnaround time for any alternate concepts. A relatively recent and still underused addition to the geologist's set of quantitative tools has been geologic process modeling (or GPM, also called stratigraphic forward modeling). This technique aims to model the processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution on the basis of quantitative deterministic physical principles (Cross 1990; Tetzlaff & Priddy 2001; Merriam & Davis 2001). The results show the geometry and composition of the stratigraphic sequence as a consequence of sea-level change, paleogeography, paleoclimate, tectonics and variation in sediment input. In its scope, GPM is similar to detailed sequence stratigraphy. However, the latter has been developed on the basis of observations and inferences, mostly from seismic data, and conceptual models that specify what stratigraphic relationships should be expected under certain conditions (such as sea-level rise and fall, or variations in sediment input). GPM on the other hand, is based solely on numeric modeling of open-channel flow, currents, waves, and the movement of sediment. The observed stratigraphy is the result of modeling a physical system which can then be further used for refinement in a geological facies model. (Tetzlaff et. al 2014) In the currents study a 3D geological model for the B-9 field, based on the Geological Process Modeling (GPM) has been attempted Owing to the thin pays in deltaic san
{"title":"Improving Reservoir Facies Model by Successful Application of Forward Stratigraphic Modeling Techniques for Offshore Deltaic Reservoir in India","authors":"A. Moharana, M. Mahapatra, S. Chakraborty, D. Biswal, K. Havelia","doi":"10.2118/197334-ms","DOIUrl":"https://doi.org/10.2118/197334-ms","url":null,"abstract":"\u0000 Petroleum Geologists have always been a group who looked at rocks, developed and described depositional concepts, mapping structures to discover and develop hydrocarbons for profit. With the advent of new technologies and computing power, geology started to become a lot more quantitative. The first wave of this new revolution was the introduction of geostatistics and the discipline of geomodelling, dealing with quantitative statistics like variograms, histograms, stochastic models which could be used to put a number and range on the geological uncertainty. However, geostatistics which was originally developed in the mining industry in the 1950's deals more with regularly sampled data, describing their spatial variability and directionality. In majority of development fields, with many wells sampling the reservoir, geostatistics helps us to create a feasible proxy for the subsurface reservoirs, when it is backed by a strong conceptual geological foundation. However, as the number of wells decreases, the data for geostatistical analysis reduces and a geomodeller must rely strongly on the conceptual geological knowledge, to build a predictive geological model rather than the noisy picture which over-reliance on blind geostatistics can provide. Until recently, there was no way of quantifying or visualizing depositional concepts in 3D for a geologist save for few block diagrams and average sand distribution maps. However, these were mostly manual, deterministic with a long turnaround time for any alternate concepts.\u0000 A relatively recent and still underused addition to the geologist's set of quantitative tools has been geologic process modeling (or GPM, also called stratigraphic forward modeling). This technique aims to model the processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution on the basis of quantitative deterministic physical principles (Cross 1990; Tetzlaff & Priddy 2001; Merriam & Davis 2001). The results show the geometry and composition of the stratigraphic sequence as a consequence of sea-level change, paleogeography, paleoclimate, tectonics and variation in sediment input. In its scope, GPM is similar to detailed sequence stratigraphy. However, the latter has been developed on the basis of observations and inferences, mostly from seismic data, and conceptual models that specify what stratigraphic relationships should be expected under certain conditions (such as sea-level rise and fall, or variations in sediment input). GPM on the other hand, is based solely on numeric modeling of open-channel flow, currents, waves, and the movement of sediment. The observed stratigraphy is the result of modeling a physical system which can then be further used for refinement in a geological facies model. (Tetzlaff et. al 2014)\u0000 In the currents study a 3D geological model for the B-9 field, based on the Geological Process Modeling (GPM) has been attempted Owing to the thin pays in deltaic san","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81219398","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}
Water based muds (WBM) provide an eco-friendly and cost effective way out for drilling a petroleum well without using oil based muds. WBM may cause some problems when a water sensitive formation (such as shale) is encountered during drilling. The infiltration of water from mud causes formation minerals to dissolve that may lead to formation damage. Fluid loss also alters the rheological properties of mud which is highly undesirable hence fluid loss should be minimum. Present study aims to experimentally investigate the effect of CuO and ZnO nanoparticles in presence of poly(4-styrenesulfonic acid-co-maleic acid) sodium salt (PSSM) as a fluid loss control agent for WBM at high pressure-high temperature (HPHT) conditions. Base mud containing hydroxyethyl cellulose was mixed with 1.0 w/v% of PSSM and varying concentrations of either nanoparticle (0.25, 0.50, 0.75 and 1.00 w/v%). The resulting drilling fluid formulations were examined by using viscometer, high temperature ageing cell in roller oven, API filter press, HPHT filter press and capillary suction timer. Zeta potential of nanoparticles in water with and without PSSM was measured using particle size analyser. Filter cake formed by API filtration tests were analysed by field emission scanning electron microscope (FESEM). Ageing experiments were also performed at 230°F for 16 hours and HPHT filtration tests were conducted at 300°F. Experimental studies have shown that the addition of CuO decreased the rheological parameters such as apparent viscosity, plastic viscosity and yield point by 10 to 15% before hot rolling of drilling fluid. After hot rolling, the rheological parameter for mud containing CuO were reduced, but as the concentration of nanoparticle increased, the rheological properties improved. Effect of CuO was more pronounced as compared to ZnO nanoparticles on fluid loss. The addition of 1.0 w/v% PSSM in base mud reduced LPLT fluid loss to ~64%. API fluid loss of PSSM containing mud was further reduced by ~12% on addition of only 1.0 w/v% of CuO. At 1.0 w/v% concentration of ZnO, API filtrate of base mud reduced by ~8%. HPHT filtrate loss for mud having 1.0 w/v% PSSM was 14.6 mL in 30 minutes at 300°F. Addition of nanoparticles further reduced HPHT filtration loss by 15 to 20%. FESEM images of filter cakes suggested that there were complex structures of polymer chains covering the pores of filter cake, and the network was further blocked by the nanoparticle clusters, therefore inhibiting the passage of fluid through it. The results obtained from this experimental work have shown that the efficiency of polymer as fluid loss reducer has improved due to the addition of nanoparticles, especially with CuO. The novel combination of CuO nanoparticles with poly(4-styrenesulfonic acid-co-maleic acid) sodium salt can further be explored and engineered to develop an efficient fluid loss reducing formulation for water based mud.
{"title":"Effect of CuO and ZnO Nanoparticles on Efficacy of Poly 4-Styrenesulfonic Acid-Co-Maleic Acid Sodium Salt for Controlling HPHT Filtration","authors":"Mukarram Beg, H. Kesarwani, Shivanjali Sharma","doi":"10.2118/197703-ms","DOIUrl":"https://doi.org/10.2118/197703-ms","url":null,"abstract":"\u0000 Water based muds (WBM) provide an eco-friendly and cost effective way out for drilling a petroleum well without using oil based muds. WBM may cause some problems when a water sensitive formation (such as shale) is encountered during drilling. The infiltration of water from mud causes formation minerals to dissolve that may lead to formation damage. Fluid loss also alters the rheological properties of mud which is highly undesirable hence fluid loss should be minimum.\u0000 Present study aims to experimentally investigate the effect of CuO and ZnO nanoparticles in presence of poly(4-styrenesulfonic acid-co-maleic acid) sodium salt (PSSM) as a fluid loss control agent for WBM at high pressure-high temperature (HPHT) conditions. Base mud containing hydroxyethyl cellulose was mixed with 1.0 w/v% of PSSM and varying concentrations of either nanoparticle (0.25, 0.50, 0.75 and 1.00 w/v%). The resulting drilling fluid formulations were examined by using viscometer, high temperature ageing cell in roller oven, API filter press, HPHT filter press and capillary suction timer. Zeta potential of nanoparticles in water with and without PSSM was measured using particle size analyser. Filter cake formed by API filtration tests were analysed by field emission scanning electron microscope (FESEM). Ageing experiments were also performed at 230°F for 16 hours and HPHT filtration tests were conducted at 300°F.\u0000 Experimental studies have shown that the addition of CuO decreased the rheological parameters such as apparent viscosity, plastic viscosity and yield point by 10 to 15% before hot rolling of drilling fluid. After hot rolling, the rheological parameter for mud containing CuO were reduced, but as the concentration of nanoparticle increased, the rheological properties improved. Effect of CuO was more pronounced as compared to ZnO nanoparticles on fluid loss. The addition of 1.0 w/v% PSSM in base mud reduced LPLT fluid loss to ~64%. API fluid loss of PSSM containing mud was further reduced by ~12% on addition of only 1.0 w/v% of CuO. At 1.0 w/v% concentration of ZnO, API filtrate of base mud reduced by ~8%. HPHT filtrate loss for mud having 1.0 w/v% PSSM was 14.6 mL in 30 minutes at 300°F. Addition of nanoparticles further reduced HPHT filtration loss by 15 to 20%. FESEM images of filter cakes suggested that there were complex structures of polymer chains covering the pores of filter cake, and the network was further blocked by the nanoparticle clusters, therefore inhibiting the passage of fluid through it.\u0000 The results obtained from this experimental work have shown that the efficiency of polymer as fluid loss reducer has improved due to the addition of nanoparticles, especially with CuO. The novel combination of CuO nanoparticles with poly(4-styrenesulfonic acid-co-maleic acid) sodium salt can further be explored and engineered to develop an efficient fluid loss reducing formulation for water based mud.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78029747","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}
Javier Torres, Eglier Yanez Hernandez, Olla Kadoura, M. Zidan, M. Uijttenhout, A. Harbi, Y. A. Hammadi, Mohamed R. Al Zaabi, E. Draoui, U. Ghauri, Osama Saeed, Y. A. Katheeri, Jawad Ismail, Najem A. Qambar, D. Beaman, R. Salimov, Knut Nes
An integrated and collaborative study was required in order to determine the most cost effective field development scenario while ensuring collision risk mitigation, to define and validate the well planning and slot allocation for the wells scheduled for the next ten years as part of the re-development due to a new sub-surface strategic scheme that was later extended to the full lifecycle of a green field offshore Abu Dhabi. The workflow included data, feedback and participation of four main stakeholders: Sub-surface Team, Petroleum Engineering Team, Drilling & Completion Team and Surface Facilities Engineering Team. The process started with the provision of the targets by the Petroleum Engineering Team, previously validated by the Sub-Surface Team to the Drilling & Completion Team. The second step included generation of preliminary trajectories including high-level anti-collision analysis against existing wells as well as other planned wells; this step also included validation of the Completion requirements based on the preliminary drilling schedule and equipment availability. The trajectories were then sent back to the Petroleum Engineering Team for well objectives validation and finally a multi-disciplinary session with the Surface Facilities Engineering Team, Petroleum Engineering Team and Drilling & Completion Team was executed to ensure readiness of surface installations based on the drilling schedule; as part of the outcome of this session multiple iterations occurred until alignment and agreement of all the stakeholders was achieved. The outcome of the workflow was the generation of full field development study including the preliminary trajectories, their respective slot allocation, high-level anti-collisions and estimated Drillex (Drilling Capex) validated and agreed by all stakeholders. This novel approach to the integrated multi-disciplinary collaborative field development well planning provides multiple benefits such as: 1. Fast delivery of scenarios for field development well planning, reducing the cycle time to less than half of the conventional time required. 2. Generation of multiple scenarios instead of a single scenario, allowing further optimization of cost and risk reduction without compromising expected production targets. 3. Early understanding of the completion equipment requirements to ensure availability based on the drilling schedule. 4. Quick response to unplanned changes based on the understanding of the full field scale planning allowing swapping of wells with minimum to impact on cost, risk and operations. 5. Full In-House process that represents a continuous and dynamic project allowing constant fine tuning based on new data and new models instead of a fixed time stamp, static, project with a single report outcome.
{"title":"Novel Integrated Multi-Disciplinary Collaborative Field Development Well Planning Workflow for the Full Lifecycle of a Green Field Offshore Abu Dhabi","authors":"Javier Torres, Eglier Yanez Hernandez, Olla Kadoura, M. Zidan, M. Uijttenhout, A. Harbi, Y. A. Hammadi, Mohamed R. Al Zaabi, E. Draoui, U. Ghauri, Osama Saeed, Y. A. Katheeri, Jawad Ismail, Najem A. Qambar, D. Beaman, R. Salimov, Knut Nes","doi":"10.2118/197240-ms","DOIUrl":"https://doi.org/10.2118/197240-ms","url":null,"abstract":"\u0000 An integrated and collaborative study was required in order to determine the most cost effective field development scenario while ensuring collision risk mitigation, to define and validate the well planning and slot allocation for the wells scheduled for the next ten years as part of the re-development due to a new sub-surface strategic scheme that was later extended to the full lifecycle of a green field offshore Abu Dhabi.\u0000 The workflow included data, feedback and participation of four main stakeholders: Sub-surface Team, Petroleum Engineering Team, Drilling & Completion Team and Surface Facilities Engineering Team. The process started with the provision of the targets by the Petroleum Engineering Team, previously validated by the Sub-Surface Team to the Drilling & Completion Team. The second step included generation of preliminary trajectories including high-level anti-collision analysis against existing wells as well as other planned wells; this step also included validation of the Completion requirements based on the preliminary drilling schedule and equipment availability. The trajectories were then sent back to the Petroleum Engineering Team for well objectives validation and finally a multi-disciplinary session with the Surface Facilities Engineering Team, Petroleum Engineering Team and Drilling & Completion Team was executed to ensure readiness of surface installations based on the drilling schedule; as part of the outcome of this session multiple iterations occurred until alignment and agreement of all the stakeholders was achieved.\u0000 The outcome of the workflow was the generation of full field development study including the preliminary trajectories, their respective slot allocation, high-level anti-collisions and estimated Drillex (Drilling Capex) validated and agreed by all stakeholders.\u0000 This novel approach to the integrated multi-disciplinary collaborative field development well planning provides multiple benefits such as: 1. Fast delivery of scenarios for field development well planning, reducing the cycle time to less than half of the conventional time required. 2. Generation of multiple scenarios instead of a single scenario, allowing further optimization of cost and risk reduction without compromising expected production targets. 3. Early understanding of the completion equipment requirements to ensure availability based on the drilling schedule. 4. Quick response to unplanned changes based on the understanding of the full field scale planning allowing swapping of wells with minimum to impact on cost, risk and operations. 5. Full In-House process that represents a continuous and dynamic project allowing constant fine tuning based on new data and new models instead of a fixed time stamp, static, project with a single report outcome.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77193345","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 jacket structure is designed to support a platform required for drilling and production facilities. The jacket is subjected to complex, multi-directional loading during installation. Overturning moments from wind, current and wave loads are skewed from overturning moments from pile and jacket weight eccentricity. The mudmat geometry can be simple with symmetrical mudmats at the four corners of the jacket base or can be complex due to full rectangular area with an off-center, open, rectangular bay for conductor installation. Mudmat geometry, loads during pile installation and soil conditions combined to produce a challenging overturning stability problem. Equivalent area methods of API RP 2GEO and ISO 19901-4 may not predict the low overturning resistance, and a typical righting moment analysis may not capture the soil-structure interaction. To address the geometry and complex loading, a plasticity analysis of overturning stability was performed and is described herein. Partial safety factors as recommended by API RP 2GEO, ISO 19901-4 were used to assess stability so that overturning from the jacket dead weight could be treated separately from the wind, current and wave loading. Since the partial safety factors are lower for the stabilizing forces compared to the forces causing overturning moments, the resulting safety factors can be lower. Moment and force equilibrium were imposed, and the minimum overturning safety factor was found. Although the vector sum of the factored loads was oriented away from a principal axis of the mudmat, upper bound plasticity methods were used to investigate kinematically admissible failure mechanisms. The method of analysis easily accounts for irregular foundation geometry and complex, multidirectional loading with varying degrees of uncertainty. The method fills a gap in API RP 2GEO and can be implemented in a simple spreadsheet. A case study is presented to demonstrate the safety factor variation using API RP 2GEO method and the proposed failure method with varying eccentricity in the gravity loads and overturning moments due to wind, current and wave loads.
夹套结构设计用于支撑钻井和生产设施所需的平台。夹套在安装过程中承受复杂的多向载荷。由风、水流和波浪荷载引起的倾覆力矩与由桩和护套重量偏心引起的倾覆力矩相偏斜。泥垫的几何形状可以很简单，在护套底座的四个角落都有对称的泥垫，也可以很复杂，因为整个矩形区域都有一个偏离中心的、开放的矩形槽，用于安装导体。泥层几何形状、桩安装过程中的荷载和土壤条件共同产生了具有挑战性的倾覆稳定性问题。API RP 2GEO和ISO 19901-4的等效面积方法可能无法预测低倾覆阻力，典型的扭转力矩分析可能无法捕获土-结构相互作用。为了解决几何和复杂载荷，进行了倾覆稳定性的塑性分析，并在此进行了描述。采用API RP 2GEO和ISO 19901-4推荐的部分安全系数来评估稳定性，以便将导管套自重引起的倾覆与风、流和波浪载荷分开处理。由于稳定力的部分安全系数比引起倾覆力矩的力低，因此产生的安全系数可以更低。通过施加力矩和力平衡，求出最小倾覆安全系数。虽然因子荷载的矢量和取向远离泥地的主轴，但上限塑性方法被用于研究运动学上允许的破坏机制。这种分析方法易于考虑不规则的基础几何形状和复杂的多向不确定性荷载。该方法填补了API RP 2GEO的空白，可以在一个简单的电子表格中实现。通过实例验证了API RP - 2GEO方法在重力荷载和风、流、浪作用下倾覆力矩变化时的安全系数变化，以及所提出的破坏方法。
{"title":"Mudmat Analysis of Jacket Structure - Case Study","authors":"N. Nagaraju, C. Kumar, Nitin Varghese","doi":"10.2118/197799-ms","DOIUrl":"https://doi.org/10.2118/197799-ms","url":null,"abstract":"\u0000 A jacket structure is designed to support a platform required for drilling and production facilities. The jacket is subjected to complex, multi-directional loading during installation. Overturning moments from wind, current and wave loads are skewed from overturning moments from pile and jacket weight eccentricity. The mudmat geometry can be simple with symmetrical mudmats at the four corners of the jacket base or can be complex due to full rectangular area with an off-center, open, rectangular bay for conductor installation. Mudmat geometry, loads during pile installation and soil conditions combined to produce a challenging overturning stability problem. Equivalent area methods of API RP 2GEO and ISO 19901-4 may not predict the low overturning resistance, and a typical righting moment analysis may not capture the soil-structure interaction. To address the geometry and complex loading, a plasticity analysis of overturning stability was performed and is described herein.\u0000 Partial safety factors as recommended by API RP 2GEO, ISO 19901-4 were used to assess stability so that overturning from the jacket dead weight could be treated separately from the wind, current and wave loading. Since the partial safety factors are lower for the stabilizing forces compared to the forces causing overturning moments, the resulting safety factors can be lower. Moment and force equilibrium were imposed, and the minimum overturning safety factor was found. Although the vector sum of the factored loads was oriented away from a principal axis of the mudmat, upper bound plasticity methods were used to investigate kinematically admissible failure mechanisms. The method of analysis easily accounts for irregular foundation geometry and complex, multidirectional loading with varying degrees of uncertainty. The method fills a gap in API RP 2GEO and can be implemented in a simple spreadsheet.\u0000 A case study is presented to demonstrate the safety factor variation using API RP 2GEO method and the proposed failure method with varying eccentricity in the gravity loads and overturning moments due to wind, current and wave loads.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82250995","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}
Shilpi Gupta, A. Govil, Guillermo Obando, Tonje Winther, Laurent Delabroy
In an oilfield well, when the annulus contents behind the casing are evaluated using ultrasonic measurements, the properties of the borehole mud, such as acoustic impedance and fluid velocity, are critical input for the accurate determination of acoustic impedance of annulus material and its subsequent bond quality. In deviated or horizontal wells, mud settling, and subsequent segregation leads to azimuthal and depth uncertainties in annulus evaluation. Typically, due to gravity, mud segregates, with the light component at the top and heavier component at the lower side of the well. In a non-homogeneous mud, using a single mud impedance value for computing acoustic impedance of the annulus can lead to ambiguous answers with uncertainties. Traditionally, it has been a challenge to accurately measure and apply these variations in acoustic impedance of the mud to precisely interpret the bond quality in the annulus. A novel pulse-echo processing scheme called R+ inversion, based on a 3-parameter inversion approach, eliminates, to a great extent, the dependence on prior knowledge of the borehole mud. The 3-parameter inversion can also reveal conditions such as mud deposition and segregation in deviated pipes. This new processing enables easier and accurate interpretation of the annular content together with essential information about the logging fluid. Four case studies established the successful implementation of R+ inversion in deviated wells in the Norwegian Continental Shelf (NCS) with azimuthal uncertainties in the mud acoustic impedance to provide reliable annulus interpretation. These measurements correlate and are validated using sonic logs as well as flexural attenuation measurements, thus providing confidence in the results and decisions. The case studies compare acoustic impedance results using legacy processing and R+ inversion processing. The limitation to use the azimuthal variations of mud in the traditional processing sometimes leave unanswered questions related to the bond quality affecting the intervention decisions expected from the bond log. With the help of R+ inversion, the operator managed to take informed intervention decisions faster, thus saving rig time and cost. Four case studies are explained in the details that demonstrate and validate the importance of R+ inversion when borehole mud settling occurs azimuthally, thus overcoming previous limitations of mud impedance computation and usage. Cement evaluation using R+ inversion enables accurate and critical decision making during new well construction, intervention, plugging, and abandonment in all conditions, irrespective of the casing sizes and cement types.
{"title":"State of the Art Development in Annulus Evaluation","authors":"Shilpi Gupta, A. Govil, Guillermo Obando, Tonje Winther, Laurent Delabroy","doi":"10.2118/197338-ms","DOIUrl":"https://doi.org/10.2118/197338-ms","url":null,"abstract":"\u0000 In an oilfield well, when the annulus contents behind the casing are evaluated using ultrasonic measurements, the properties of the borehole mud, such as acoustic impedance and fluid velocity, are critical input for the accurate determination of acoustic impedance of annulus material and its subsequent bond quality. In deviated or horizontal wells, mud settling, and subsequent segregation leads to azimuthal and depth uncertainties in annulus evaluation. Typically, due to gravity, mud segregates, with the light component at the top and heavier component at the lower side of the well. In a non-homogeneous mud, using a single mud impedance value for computing acoustic impedance of the annulus can lead to ambiguous answers with uncertainties. Traditionally, it has been a challenge to accurately measure and apply these variations in acoustic impedance of the mud to precisely interpret the bond quality in the annulus.\u0000 A novel pulse-echo processing scheme called R+ inversion, based on a 3-parameter inversion approach, eliminates, to a great extent, the dependence on prior knowledge of the borehole mud. The 3-parameter inversion can also reveal conditions such as mud deposition and segregation in deviated pipes. This new processing enables easier and accurate interpretation of the annular content together with essential information about the logging fluid.\u0000 Four case studies established the successful implementation of R+ inversion in deviated wells in the Norwegian Continental Shelf (NCS) with azimuthal uncertainties in the mud acoustic impedance to provide reliable annulus interpretation. These measurements correlate and are validated using sonic logs as well as flexural attenuation measurements, thus providing confidence in the results and decisions. The case studies compare acoustic impedance results using legacy processing and R+ inversion processing. The limitation to use the azimuthal variations of mud in the traditional processing sometimes leave unanswered questions related to the bond quality affecting the intervention decisions expected from the bond log. With the help of R+ inversion, the operator managed to take informed intervention decisions faster, thus saving rig time and cost. Four case studies are explained in the details that demonstrate and validate the importance of R+ inversion when borehole mud settling occurs azimuthally, thus overcoming previous limitations of mud impedance computation and usage.\u0000 Cement evaluation using R+ inversion enables accurate and critical decision making during new well construction, intervention, plugging, and abandonment in all conditions, irrespective of the casing sizes and cement types.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87510302","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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