Application of downhole flow control device (DFCV) has proven to be a successful strategy to mitigate early water or gas breakthrough in many fields in Asia. A conventional numerical modeling workflow is often applied in such studies. However, the full potential from the downhole installation is often not explored due to several numerical oversights in failure to adapt to the unique operation requirements and DCFV hardware design representation. This paper presents a practical approach to address pitfalls involved in high-resolution numerical simulation DFCV design optimization. In this paper, a multi-stage procedure is highlighted involving a numerical simulation model prepared for DFCV design and optimization. The first step is to investigate the grid resolution from the 3D model. This is to ensure the effect of grid-to-well resolutions from coarse scale to finer scales to capture the device behavior along the open hole (OH) length of horizontal wells and to capture the gas and water influx from contact. The second step is to design and optimize the packer placement based on permeability contrast as primary reference using a practical approach by setting the number of packers as a sensitivity variable with uniform DFCV setting design. It is then followed by an unbiased design workflow is to optimize benefits of all kinds of DFCV such as nozzle-based and viscosity dependent inflow control devices of zonally varying setting or optimal configuration designs. The practical approach is demonstrated on a synthetic simulation model with a horizontal well to address the oversights in modelling prior to DFCV design and optimization process. Based on this work, vertical grid resolution to oil thickness ratio exceeding 1:32 amplified the differences in results due to numerical dispersion problem. For packer location optimization, several sensitivities of different packer placements and number of packers were performed to compare the oil cumulative incremental. The optimum number of packers with uniform DFCV design is 19 packers, however the oil gain will be decreased once the number of packers is reduced. Finally, the practicality of applying a global optimization algorithm to such studies during real-time operations was investigated. A unique practical approach is presented to address pitfalls involved in the needs of high-resolution numerical simulation in DFCV optimization. This approach captures the complex physics and resolution involved while ensuring the design loop efficient enough to perform fine-tuning during run-in-hole or on-the fly design onsite. In addition, this design optimization workflow is possible due to the availability of a new standard advanced reservoir simulator, that is cloud-compliant and has efficient multi-core parallel processing which otherwise would take days if not weeks conventionally to complete the task, deemed unsuitable for near real-time design or fine-tuning needs.
{"title":"Practical Approach to Address Pitfalls of High-Resolution Numerical Simulation Modeling in Advanced Completion Design Optimization Today","authors":"Zhen-Xuan Yew, Chee Seong Tan, Wee Wei Wa, G. Goh","doi":"10.4043/31649-ms","DOIUrl":"https://doi.org/10.4043/31649-ms","url":null,"abstract":"\u0000 Application of downhole flow control device (DFCV) has proven to be a successful strategy to mitigate early water or gas breakthrough in many fields in Asia. A conventional numerical modeling workflow is often applied in such studies. However, the full potential from the downhole installation is often not explored due to several numerical oversights in failure to adapt to the unique operation requirements and DCFV hardware design representation. This paper presents a practical approach to address pitfalls involved in high-resolution numerical simulation DFCV design optimization.\u0000 In this paper, a multi-stage procedure is highlighted involving a numerical simulation model prepared for DFCV design and optimization. The first step is to investigate the grid resolution from the 3D model. This is to ensure the effect of grid-to-well resolutions from coarse scale to finer scales to capture the device behavior along the open hole (OH) length of horizontal wells and to capture the gas and water influx from contact. The second step is to design and optimize the packer placement based on permeability contrast as primary reference using a practical approach by setting the number of packers as a sensitivity variable with uniform DFCV setting design. It is then followed by an unbiased design workflow is to optimize benefits of all kinds of DFCV such as nozzle-based and viscosity dependent inflow control devices of zonally varying setting or optimal configuration designs.\u0000 The practical approach is demonstrated on a synthetic simulation model with a horizontal well to address the oversights in modelling prior to DFCV design and optimization process. Based on this work, vertical grid resolution to oil thickness ratio exceeding 1:32 amplified the differences in results due to numerical dispersion problem. For packer location optimization, several sensitivities of different packer placements and number of packers were performed to compare the oil cumulative incremental. The optimum number of packers with uniform DFCV design is 19 packers, however the oil gain will be decreased once the number of packers is reduced. Finally, the practicality of applying a global optimization algorithm to such studies during real-time operations was investigated.\u0000 A unique practical approach is presented to address pitfalls involved in the needs of high-resolution numerical simulation in DFCV optimization. This approach captures the complex physics and resolution involved while ensuring the design loop efficient enough to perform fine-tuning during run-in-hole or on-the fly design onsite. In addition, this design optimization workflow is possible due to the availability of a new standard advanced reservoir simulator, that is cloud-compliant and has efficient multi-core parallel processing which otherwise would take days if not weeks conventionally to complete the task, deemed unsuitable for near real-time design or fine-tuning needs.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"191 4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75604439","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}
Nurul Nadia Ezzatty Abu Bakar, M. Hod, M. A. Abitalhah, A. F. Omar, Avinash Kishore Kumar, C. Lau, Ahmad Fadhli Ismail, Adhi Naharindra, Zaidi Rahimy M Ghazali
This paper presents the success story of an exploration well in Malaysia which exemplary applied a breakthrough integration of 3-1/2″ tubing in 8-1/2″ hole cemented monobore utilizing a new well testing concept of Tubing Stem Test (TST) to save cost and rig time. The Tubing Stem Test (TST) concept which is the new approach of testing a well that integrates both completion and well test technology into a single system compared to conventional Drill Stem Test (DST). The cemented monobore technology was successfully implemented by smooth and flawless planning and execution. A comprehensive planning and collaboration of multiple disciplines in Wells and Subsurface team had ensured a successful delivery of the first Tubing Stem Test (TST) with 3-1/2″ Tubing Cemented Monobore in a near-field exploration well targeting marginal reservoir in Malaysia. During planning stage, the challenges were to ensure that the cementing design concept suits TST application to be executed smoothly by incorporating multiple of risk assessments, lessons learnt, best practices review, feasibility studies and multiple design challenge sessions. This is to ensure that the well integrity is not jeopardized by achieving good cement bond across 3.5″ × 8.5″ annulus section with exclusion of WAB (Welltec Annular Barrier) packer. During execution stage, main concern in cementing operation pushed project team to re-design the fit-for-purpose cementing slurry and multiple cement tests were performed to ensure cementing objectives were achieved. Project team optimized the design by using G Cement Silica blend which has been proven to eliminate fluid migration and provide good compressive strength (UCS). This has allowed additional perforation zone for the new target as CBL/VDL shown good cement bonding to targeted top of cement. Some of the good practices includes good tubing standoff, efficient pre-flush, spacer & cement slurry design with fast compressive strength development, good displacement efficiency and effective plug bump strategy. The thought process, design requirement both for the hardware and cement slurry, and execution follow through of cemented monobore operation in driving for cost savings and operational efficiency will be elaborated. This collaborative initiative has resulted significant cost savings by eliminating cost of wellbore clean-up (WBCU), eliminate 7″ Casing or Liner for reservoir section, DST package, DST tubing rental, simpler completion accessories and 5 days of rig operation days. Despite facing with challenging cement issue with challenging cement batch used, well has achieved good CBL/VDL result and 100% zonal isolation which has enabled perforation of planned and additional target hydrocarbon zones. Simultaneously, formation damage risk was reduced by eliminating the time the formation is exposed to overbalance brine This paper presents the planning and operational execution of 3-1/2″ Tubing in 8-1/2″ Hole Cemented Monobore to realize the fe
{"title":"Breakthrough Integration of 3-1/2? Tubing in 8-1/2? Hole Cemented Monobore for Successful Tubing Stem Test TST","authors":"Nurul Nadia Ezzatty Abu Bakar, M. Hod, M. A. Abitalhah, A. F. Omar, Avinash Kishore Kumar, C. Lau, Ahmad Fadhli Ismail, Adhi Naharindra, Zaidi Rahimy M Ghazali","doi":"10.4043/31617-ms","DOIUrl":"https://doi.org/10.4043/31617-ms","url":null,"abstract":"\u0000 This paper presents the success story of an exploration well in Malaysia which exemplary applied a breakthrough integration of 3-1/2″ tubing in 8-1/2″ hole cemented monobore utilizing a new well testing concept of Tubing Stem Test (TST) to save cost and rig time. The Tubing Stem Test (TST) concept which is the new approach of testing a well that integrates both completion and well test technology into a single system compared to conventional Drill Stem Test (DST). The cemented monobore technology was successfully implemented by smooth and flawless planning and execution.\u0000 A comprehensive planning and collaboration of multiple disciplines in Wells and Subsurface team had ensured a successful delivery of the first Tubing Stem Test (TST) with 3-1/2″ Tubing Cemented Monobore in a near-field exploration well targeting marginal reservoir in Malaysia.\u0000 During planning stage, the challenges were to ensure that the cementing design concept suits TST application to be executed smoothly by incorporating multiple of risk assessments, lessons learnt, best practices review, feasibility studies and multiple design challenge sessions. This is to ensure that the well integrity is not jeopardized by achieving good cement bond across 3.5″ × 8.5″ annulus section with exclusion of WAB (Welltec Annular Barrier) packer.\u0000 During execution stage, main concern in cementing operation pushed project team to re-design the fit-for-purpose cementing slurry and multiple cement tests were performed to ensure cementing objectives were achieved. Project team optimized the design by using G Cement Silica blend which has been proven to eliminate fluid migration and provide good compressive strength (UCS). This has allowed additional perforation zone for the new target as CBL/VDL shown good cement bonding to targeted top of cement. Some of the good practices includes good tubing standoff, efficient pre-flush, spacer & cement slurry design with fast compressive strength development, good displacement efficiency and effective plug bump strategy. The thought process, design requirement both for the hardware and cement slurry, and execution follow through of cemented monobore operation in driving for cost savings and operational efficiency will be elaborated.\u0000 This collaborative initiative has resulted significant cost savings by eliminating cost of wellbore clean-up (WBCU), eliminate 7″ Casing or Liner for reservoir section, DST package, DST tubing rental, simpler completion accessories and 5 days of rig operation days. Despite facing with challenging cement issue with challenging cement batch used, well has achieved good CBL/VDL result and 100% zonal isolation which has enabled perforation of planned and additional target hydrocarbon zones. Simultaneously, formation damage risk was reduced by eliminating the time the formation is exposed to overbalance brine\u0000 This paper presents the planning and operational execution of 3-1/2″ Tubing in 8-1/2″ Hole Cemented Monobore to realize the fe","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"106 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74344861","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. Kumar, Sandhria Ferriawan Agung Pambudi, Milind Salunke, J. W. Rayappa
Calcareous soil type is found at many locations, requiring careful selection of foundation type. Calcareous soil is mostly or partly composed of calcium carbonate in the form of lime or chalk derived from the underlying chalk or limestone rock. North-West Shelf of Australia is an example of site which consists of carbonate soil types wherein the majority of existing offshore facilities and platforms being installed using Drilled and Grouted (D&G) piled foundations and in some instances using Gravity based foundations. This paper discusses alternate foundation concepts on such soils, namely; (i) Micro-piles, and (ii) Inclined pile cluster, along with the common concepts of (iii) D&G piles and (iv) Gravity based foundations. The foundation concepts are discussed with focus on key aspects of the foundation structural configuration, vertical foundation capacity feasibility, and some serviceability related aspects. In addition, offshore operation and installation duration perspective are also discussed to provide some insight on how each foundation concept could suit the project preference which often influence the final selection of foundation concept. Risk/challenges and advantages of each concept are then summarized for overall comparison.
{"title":"Alternate Foundation Concepts for Offshore Jackets in Calcareous Soils","authors":"C. Kumar, Sandhria Ferriawan Agung Pambudi, Milind Salunke, J. W. Rayappa","doi":"10.4043/31595-ms","DOIUrl":"https://doi.org/10.4043/31595-ms","url":null,"abstract":"\u0000 Calcareous soil type is found at many locations, requiring careful selection of foundation type. Calcareous soil is mostly or partly composed of calcium carbonate in the form of lime or chalk derived from the underlying chalk or limestone rock. North-West Shelf of Australia is an example of site which consists of carbonate soil types wherein the majority of existing offshore facilities and platforms being installed using Drilled and Grouted (D&G) piled foundations and in some instances using Gravity based foundations.\u0000 This paper discusses alternate foundation concepts on such soils, namely; (i) Micro-piles, and (ii) Inclined pile cluster, along with the common concepts of (iii) D&G piles and (iv) Gravity based foundations. The foundation concepts are discussed with focus on key aspects of the foundation structural configuration, vertical foundation capacity feasibility, and some serviceability related aspects. In addition, offshore operation and installation duration perspective are also discussed to provide some insight on how each foundation concept could suit the project preference which often influence the final selection of foundation concept. Risk/challenges and advantages of each concept are then summarized for overall comparison.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"52 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77666422","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. Huisman, M. Ottolini, B. Cerfontaine, M. Brown, C. Davidson, Y. Sharif, S. Robinson
This paper presents preliminary experimental and analytical investigations of the push-in pile concept, which aims at installing piles in the offshore environment without significant underwater noise. The concept replaces a large diameter pile with a cluster of closely spaced smaller piles. The piles are installed progressively by cycles of jacking. During each cycle, a pile is successively pushed downwards or moved upwards while used as a reaction pile. This process was physically modelled in a geotechnical beam centrifuge and a predictive model was developed and calibrated against these tests. A parametric study was then undertaken to optimise the cluster design and reduce the tool weight necessary to achieve a given installation depth or cluster capacity. Smaller pile diameters are more beneficial to reduce the necessary tool weight during the cluster installation, but require considerably longer piles to achieve the target capacity. The full optimisation of a cost-effective pile cluster will require additional constraints, such as the lateral capacity (not investigated here) and expected installation time.
{"title":"Design Optimisation of Deep Pile Foundations Installed by Static Forces","authors":"M. Huisman, M. Ottolini, B. Cerfontaine, M. Brown, C. Davidson, Y. Sharif, S. Robinson","doi":"10.4043/31461-ms","DOIUrl":"https://doi.org/10.4043/31461-ms","url":null,"abstract":"\u0000 This paper presents preliminary experimental and analytical investigations of the push-in pile concept, which aims at installing piles in the offshore environment without significant underwater noise. The concept replaces a large diameter pile with a cluster of closely spaced smaller piles. The piles are installed progressively by cycles of jacking. During each cycle, a pile is successively pushed downwards or moved upwards while used as a reaction pile. This process was physically modelled in a geotechnical beam centrifuge and a predictive model was developed and calibrated against these tests. A parametric study was then undertaken to optimise the cluster design and reduce the tool weight necessary to achieve a given installation depth or cluster capacity. Smaller pile diameters are more beneficial to reduce the necessary tool weight during the cluster installation, but require considerably longer piles to achieve the target capacity. The full optimisation of a cost-effective pile cluster will require additional constraints, such as the lateral capacity (not investigated here) and expected installation time.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78140065","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. Ismail, Sunanda Magna Bela, S. Hashim, Khai Lun Tham, C. H. Roh, S. N. M. Bt M. Zain, Nur Hidayah M Zamani, Jagaan Selladurai
Wellbore enlargement technique such as hydraulic fracturing or frac packing (or extension pack using linear gel) treatment is very much required in the brown field reservoirs with unconsolidated sands, poor sorting, and uniformity coefficient as well as very high fine content. The cost escalates when this requirement happens for multiple zones which needs longer rig time. This paper will discuss on the execution part of 7" ESTMZ system deployment, extension pack design, lessons learnt and required mitigation on the system itself. Conventionally, most of the operator will perform extension pack operation using stack-pack technique which required longer rig time, due to repetition of perforation, deburring and installation of gravel pack assembly which followed by gravel placement operation based on number of zones. Further optimization is the Single Trip Multi Zone (STMZ) system developed to enable multi zones gravel placement treatment and installation done in single trip in order to reduce the rig time. However, the 7" STMZ system is still have some limitation on its pumping capability due to system design and high friction pressure hence unable to be used for any frac-pack or extension pack treatment. The next generation of 7" ESTMZ system was introduced to overcome all the limitation of its predecessor and enables the frac-pack operation to be performed in a single trip manner which assuredly reduced considerable rig days. Furthermore, this system can eliminate deployment of inner string inside lower completion assemblies for zonal isolation and reservoir selectivity which can be risky especially in highly deviated wells. This system comes with modular screen design with integrated sliding sleeve with proprietary shifting profile. Like the conventional stack pack system, a sump packer will be run in hole via wireline and tractor as a base for sump area and depth reference. Then, the well is perforated with oriented gun and selected perforation technique for all zones in a single trip followed by debur run using wellbore clean out BHA. ESTMZ assembly is deployed to cover all zones with single concentric wash pipe system for the treatment. The zone interval length and zonal spacing are fully independent and may come with various length as oppose to the STMZ system. Hence, no dummy zone is required. The gravel placement design for this particular field was designed precisely to contain the growth to avoid fracturing into the nearby coal, shale, and water contact region. As a result, the reservoirs were successfully treated with extension pack of 220lb/ft packing factor at highest proppant concentration of 4.8ppg and 10bpm pumping rate. The technology discussed in this paper is a first in the world application in highly deviated well category where the author is intended to register the pain points as well as best practices to be replicated.
{"title":"7in Enhanced Single-Trip Multizone System ESTMZ: Fracturing Design, Execution and Operation Lessons Learnt in Highly Deviated Well with Nearby Shale, Coal and Water Contact","authors":"M. Ismail, Sunanda Magna Bela, S. Hashim, Khai Lun Tham, C. H. Roh, S. N. M. Bt M. Zain, Nur Hidayah M Zamani, Jagaan Selladurai","doi":"10.4043/31496-ms","DOIUrl":"https://doi.org/10.4043/31496-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Wellbore enlargement technique such as hydraulic fracturing or frac packing (or extension pack using linear gel) treatment is very much required in the brown field reservoirs with unconsolidated sands, poor sorting, and uniformity coefficient as well as very high fine content. The cost escalates when this requirement happens for multiple zones which needs longer rig time. This paper will discuss on the execution part of 7\" ESTMZ system deployment, extension pack design, lessons learnt and required mitigation on the system itself. Conventionally, most of the operator will perform extension pack operation using stack-pack technique which required longer rig time, due to repetition of perforation, deburring and installation of gravel pack assembly which followed by gravel placement operation based on number of zones. Further optimization is the Single Trip Multi Zone (STMZ) system developed to enable multi zones gravel placement treatment and installation done in single trip in order to reduce the rig time. However, the 7\" STMZ system is still have some limitation on its pumping capability due to system design and high friction pressure hence unable to be used for any frac-pack or extension pack treatment.\u0000 \u0000 \u0000 \u0000 The next generation of 7\" ESTMZ system was introduced to overcome all the limitation of its predecessor and enables the frac-pack operation to be performed in a single trip manner which assuredly reduced considerable rig days. Furthermore, this system can eliminate deployment of inner string inside lower completion assemblies for zonal isolation and reservoir selectivity which can be risky especially in highly deviated wells. This system comes with modular screen design with integrated sliding sleeve with proprietary shifting profile. Like the conventional stack pack system, a sump packer will be run in hole via wireline and tractor as a base for sump area and depth reference. Then, the well is perforated with oriented gun and selected perforation technique for all zones in a single trip followed by debur run using wellbore clean out BHA. ESTMZ assembly is deployed to cover all zones with single concentric wash pipe system for the treatment. The zone interval length and zonal spacing are fully independent and may come with various length as oppose to the STMZ system. Hence, no dummy zone is required.\u0000 \u0000 \u0000 \u0000 The gravel placement design for this particular field was designed precisely to contain the growth to avoid fracturing into the nearby coal, shale, and water contact region. As a result, the reservoirs were successfully treated with extension pack of 220lb/ft packing factor at highest proppant concentration of 4.8ppg and 10bpm pumping rate.\u0000 \u0000 \u0000 \u0000 The technology discussed in this paper is a first in the world application in highly deviated well category where the author is intended to register the pain points as well as best practices to be replicated.\u0000","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"133 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76678392","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}
Valsan Vevakanandan, A. Numpang, Doreen Dayah, Sze-Fong Kho, A. Tan, A. Ting
The X field is a mature oil field producing with water injection in place. As part of a phased development, in Phase Two, two infill wells were planned and drilled to extract incremental recovery from a discovered undeveloped reservoir. This includes planning two horizontal producer wells requiring active real time geosteering utilizing deep resistivity tool technology. The wells’ objectives are to ensure the well placement was in an optimal location and to maintain the trajectory within a reservoir that is approximately 100ft thick and was believed to be homogenous field wide. The main challenge to this feat is the faulted nature of the field and the uncertainty in reservoir thickness and extend due to limited well penetrations at this reservoir level. During the planning phase, it was identified early that a deep resistivity tool would be beneficial in geosteering the wells. Prior to drilling, an integrated pre-job model was designed to test multiple tool settings and subsurface scenarios to strategize an execution plan identifying key points where there is a need for real time trajectory adjustments and to pre-plan alternative trajectories based on subsurface scenarios to enable efficient turnaround time to react to real-time results. Conventional navigation tools yield only a shallow to medium depth of measurement (~15ft) which would not have met the objectives of the well given the geological complexities (high fault offsets, laminated reservoirs) and well design (high angle to horizontal). The ultra-deep resistivity (UDR) tool was employed instead to enable trajectory optimization with up to ~100ft depth of investigation (DOI), using a multi-frequency, multi-spaced antenna design from medium and long spaced transmitter receiver spacings providing up to 9 vector components. In real time, the 1D inversion (using 5 of the vector components) was used for early sand and fluid contact detection. During execution, the same integrated team was monitoring the well and close interaction between the subsurface, geosteering and directional drilling team was a key requirement to ensure drilling of the well was safely and objectively executed, especially with the challenges posed with virtual working through a pandemic. As is when dealing with subsurface uncertainties, there were numerous surprises encountered during the drilling of the horizontal wells. Particularly in the matter of fault throw uncertainty and sand distribution. The initial 1D real-time UDR results were able to assist in real-time trajectory adjustments and to provide some geological understandings with regards to fault throw and location of possible faults along the well bore which were then confirmed with borehole image logs. Additionally, 3D inversion images were processed post drilling, and further geological insights were discovered with regards to the depositional trends on the reservoir. In a reservoir that was initially thought to be sand-rich and homogenous, 3D inversion
{"title":"Delivering Horizontal Wells in a Deepwater Borneo Field within a Heavily Faulted Reservoir Using State-of-the-Art Navigation Tools by a Multi-Disciplinary Integrated Team","authors":"Valsan Vevakanandan, A. Numpang, Doreen Dayah, Sze-Fong Kho, A. Tan, A. Ting","doi":"10.4043/31484-ms","DOIUrl":"https://doi.org/10.4043/31484-ms","url":null,"abstract":"\u0000 The X field is a mature oil field producing with water injection in place. As part of a phased development, in Phase Two, two infill wells were planned and drilled to extract incremental recovery from a discovered undeveloped reservoir. This includes planning two horizontal producer wells requiring active real time geosteering utilizing deep resistivity tool technology. The wells’ objectives are to ensure the well placement was in an optimal location and to maintain the trajectory within a reservoir that is approximately 100ft thick and was believed to be homogenous field wide. The main challenge to this feat is the faulted nature of the field and the uncertainty in reservoir thickness and extend due to limited well penetrations at this reservoir level.\u0000 During the planning phase, it was identified early that a deep resistivity tool would be beneficial in geosteering the wells. Prior to drilling, an integrated pre-job model was designed to test multiple tool settings and subsurface scenarios to strategize an execution plan identifying key points where there is a need for real time trajectory adjustments and to pre-plan alternative trajectories based on subsurface scenarios to enable efficient turnaround time to react to real-time results.\u0000 Conventional navigation tools yield only a shallow to medium depth of measurement (~15ft) which would not have met the objectives of the well given the geological complexities (high fault offsets, laminated reservoirs) and well design (high angle to horizontal). The ultra-deep resistivity (UDR) tool was employed instead to enable trajectory optimization with up to ~100ft depth of investigation (DOI), using a multi-frequency, multi-spaced antenna design from medium and long spaced transmitter receiver spacings providing up to 9 vector components. In real time, the 1D inversion (using 5 of the vector components) was used for early sand and fluid contact detection.\u0000 During execution, the same integrated team was monitoring the well and close interaction between the subsurface, geosteering and directional drilling team was a key requirement to ensure drilling of the well was safely and objectively executed, especially with the challenges posed with virtual working through a pandemic.\u0000 As is when dealing with subsurface uncertainties, there were numerous surprises encountered during the drilling of the horizontal wells. Particularly in the matter of fault throw uncertainty and sand distribution. The initial 1D real-time UDR results were able to assist in real-time trajectory adjustments and to provide some geological understandings with regards to fault throw and location of possible faults along the well bore which were then confirmed with borehole image logs. Additionally, 3D inversion images were processed post drilling, and further geological insights were discovered with regards to the depositional trends on the reservoir. In a reservoir that was initially thought to be sand-rich and homogenous, 3D inversion ","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83860325","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}
Normawani Kerya, D. Leong, Sippakorn Apiwathanasorn
This paper examines the sand production management strategies practised by Carigali-PTTEPI Operating Company (CPOC) to minimize the impact of excessive sand production on the processing facilities and well integrity as sand production from producing wells continues to increase. Sudden well interruptions could jeopardise the daily production delivery hence require all risks to be mitigated at early stage includes risk from sand production. Gas reservoirs in CPOC operated fields were developed with monobore completions without active sand control. CPOC adopts the passive sand management approach, where sand is allowed to be produced to surface and later managed on the top-side facilities. The objective is to manage the produced sand using existing facilities and minimize the process upset/downtime. CPOC Sand Production Management consists of two main parts, Monitoring and Remediation. Two types of monitoring are done: Sand Production Monitoring and Corrosion/Erosion Monitoring. Ultrasonic Sand Detector has been used as the main tool for Sand Production Monitoring. Ultrasonic Testing (UT) has been carried out for all production flowlines as part of Corrosion/Erosion monitoring. Effective monitoring has become the enabler for proactive remediation actions. The remediation focuses on two areas: minimize sand production from wells (via MSFR/MASR-Maximum Sand Free Rate/Maximum Allowable Sand Rate), carry out water shut off, sand failure analysis etc.) and improve the integrity and reliability of processing facilities through upgrading activities. The interpretation of sand production from Ultrasonic Sand Detector allows qualitative and quantitative assessments of sand production and operational instruction for flowing wells via MSFR/MASR. In addition, UT survey is used to estimate the flowline remaining life. Proactive remediation of topside equipment is done in a timely and effective manner using Ultrasonic Sand Detector's data together with other inspection data. CPOC has also upgraded several topside equipment to improve the efficiency of sand removal, equipment integrity and reliability. This topside upgrade includes main processing platform sand removal upgrade, slug catcher cleaning, flowline wrapping, etc. This multidisciplinary collaboration since 2014, which integrate the monitoring of sand production from the wellbore with remediation activities of the downstream processes, has allowed CPOC to safely operate and achieve production target without loss of containment. The sand production management strategies practised by CPOC not only allows the company to safely operate and achieve production target, it also enables the use of "slimhole monobore" completion which is economical and practical well design without the need for conventional downhole sand control, and results in well cost of <10 MMUS. This type of field development and sand production management has become a standard technology in the Gulf of Thailand.
{"title":"Sand Management Strategy in Offshore Gas Field in the Gulf of Thailand","authors":"Normawani Kerya, D. Leong, Sippakorn Apiwathanasorn","doi":"10.4043/31499-ms","DOIUrl":"https://doi.org/10.4043/31499-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This paper examines the sand production management strategies practised by Carigali-PTTEPI Operating Company (CPOC) to minimize the impact of excessive sand production on the processing facilities and well integrity as sand production from producing wells continues to increase. Sudden well interruptions could jeopardise the daily production delivery hence require all risks to be mitigated at early stage includes risk from sand production.\u0000 \u0000 \u0000 \u0000 Gas reservoirs in CPOC operated fields were developed with monobore completions without active sand control. CPOC adopts the passive sand management approach, where sand is allowed to be produced to surface and later managed on the top-side facilities. The objective is to manage the produced sand using existing facilities and minimize the process upset/downtime.\u0000 CPOC Sand Production Management consists of two main parts, Monitoring and Remediation. Two types of monitoring are done: Sand Production Monitoring and Corrosion/Erosion Monitoring. Ultrasonic Sand Detector has been used as the main tool for Sand Production Monitoring. Ultrasonic Testing (UT) has been carried out for all production flowlines as part of Corrosion/Erosion monitoring. Effective monitoring has become the enabler for proactive remediation actions. The remediation focuses on two areas: minimize sand production from wells (via MSFR/MASR-Maximum Sand Free Rate/Maximum Allowable Sand Rate), carry out water shut off, sand failure analysis etc.) and improve the integrity and reliability of processing facilities through upgrading activities.\u0000 \u0000 \u0000 \u0000 The interpretation of sand production from Ultrasonic Sand Detector allows qualitative and quantitative assessments of sand production and operational instruction for flowing wells via MSFR/MASR. In addition, UT survey is used to estimate the flowline remaining life. Proactive remediation of topside equipment is done in a timely and effective manner using Ultrasonic Sand Detector's data together with other inspection data. CPOC has also upgraded several topside equipment to improve the efficiency of sand removal, equipment integrity and reliability. This topside upgrade includes main processing platform sand removal upgrade, slug catcher cleaning, flowline wrapping, etc. This multidisciplinary collaboration since 2014, which integrate the monitoring of sand production from the wellbore with remediation activities of the downstream processes, has allowed CPOC to safely operate and achieve production target without loss of containment.\u0000 \u0000 \u0000 \u0000 The sand production management strategies practised by CPOC not only allows the company to safely operate and achieve production target, it also enables the use of \"slimhole monobore\" completion which is economical and practical well design without the need for conventional downhole sand control, and results in well cost of <10 MMUS. This type of field development and sand production management has become a standard technology in the Gulf of Thailand.\u0000","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89187153","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper demonstrates another success story on delivering a new Best-In-Class Tendered Assisted Drilling (TAD) Wellhead Platform. A clear target/goal to achieve project value driver, ie. reduce CAPEX and accelerate project maturation speed. With demonstration of good front-end development work and project delivery strategies set from the beginning of the project, a series of strategic approach to deliver competitive scoping and requirement with the intent of achieving cost saving and minimize fabrication duration by meeting targeted weight reduction for both Topside and Substructures. The ultimate purpose of all these strategic approaches is to develop a set of standard template design and efficient project execution strategy for new TAD Wellhead platform that is replicable in Shell. Civil, Structural and Offshore Engineering discipline in Shell has leveraging past project good practices, lesson learnt and benchmarking against internal and external project to develop a fit-for-purpose design. Initial findings from the benchmarking study indicated at water depth of 143m in Sarawak water, jackets are launch-installed, typically. The continuous improvement exercises aimed to reduce both Topsides and Substructure weight, which eventually creates opportunity for jacket to convert from launch-installed in the initially concept to lift-installed jacket. Some of key successes from this improvement journey includes topside deck level/footprint optimization, optimized topside structural framing and deck leg spacing to have a small work-points from top, elimination of jacket dummy leg thus reduce overall jacket footprint/weight, lean foundation design, e.g. 1 skirt pile per leg etc. However, the key challenge to the lift-installed jacket concept at the water region of 140m remains at jacket lift weight that is limited by the typical heavy lift vessel crane capacity and it requires a stringent weather window limit. Hence, weight management, i.e. set NTE weight on the jacket lift weight is paramount and it needs to be managed from engineering phase all the way to offshore installation. The outcome of the continuous improvement journey showed tremendous satisfying result to save project cost and schedule. With massive reduction of jacket weight (>50%) thus it reduces fabrication schedule, and unlocks provision of yard flexibility that invites more competitive bidding from EPC contractors (especially small fabricator) thus potentially reduce overall EPC cost. The significant improvement in steel quantity reducing overall jacket steel material procurement cost and fabrication cost. Elimination of jacket loadout via skidding facility (for launch type jacket) that further reduces fabrication cost. This is the first lift-installed jacket in Shell Malaysia at this water region. Leveraging on project knowledge and learning, specific technical specifications for L2 TAD Wellhead Platform design and installation aids have been developed in shell, with the int
{"title":"Delivering Best-In-Class Shallow Water Tender-Assisted Drilling Wellhead Platform, a New Chapter","authors":"Michael Michael, W. Chow, Khian Aik Loh","doi":"10.4043/31400-ms","DOIUrl":"https://doi.org/10.4043/31400-ms","url":null,"abstract":"\u0000 This paper demonstrates another success story on delivering a new Best-In-Class Tendered Assisted Drilling (TAD) Wellhead Platform. A clear target/goal to achieve project value driver, ie. reduce CAPEX and accelerate project maturation speed. With demonstration of good front-end development work and project delivery strategies set from the beginning of the project, a series of strategic approach to deliver competitive scoping and requirement with the intent of achieving cost saving and minimize fabrication duration by meeting targeted weight reduction for both Topside and Substructures.\u0000 The ultimate purpose of all these strategic approaches is to develop a set of standard template design and efficient project execution strategy for new TAD Wellhead platform that is replicable in Shell.\u0000 Civil, Structural and Offshore Engineering discipline in Shell has leveraging past project good practices, lesson learnt and benchmarking against internal and external project to develop a fit-for-purpose design. Initial findings from the benchmarking study indicated at water depth of 143m in Sarawak water, jackets are launch-installed, typically.\u0000 The continuous improvement exercises aimed to reduce both Topsides and Substructure weight, which eventually creates opportunity for jacket to convert from launch-installed in the initially concept to lift-installed jacket. Some of key successes from this improvement journey includes topside deck level/footprint optimization, optimized topside structural framing and deck leg spacing to have a small work-points from top, elimination of jacket dummy leg thus reduce overall jacket footprint/weight, lean foundation design, e.g. 1 skirt pile per leg etc.\u0000 However, the key challenge to the lift-installed jacket concept at the water region of 140m remains at jacket lift weight that is limited by the typical heavy lift vessel crane capacity and it requires a stringent weather window limit. Hence, weight management, i.e. set NTE weight on the jacket lift weight is paramount and it needs to be managed from engineering phase all the way to offshore installation.\u0000 The outcome of the continuous improvement journey showed tremendous satisfying result to save project cost and schedule. With massive reduction of jacket weight (>50%) thus it reduces fabrication schedule, and unlocks provision of yard flexibility that invites more competitive bidding from EPC contractors (especially small fabricator) thus potentially reduce overall EPC cost. The significant improvement in steel quantity reducing overall jacket steel material procurement cost and fabrication cost.\u0000 Elimination of jacket loadout via skidding facility (for launch type jacket) that further reduces fabrication cost.\u0000 This is the first lift-installed jacket in Shell Malaysia at this water region. Leveraging on project knowledge and learning, specific technical specifications for L2 TAD Wellhead Platform design and installation aids have been developed in shell, with the int","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90570143","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}
Cuttings reinjection is an effective way to treat oilfield waste. There is still a risk of slurry leakage during the field operations although cuttings re-injection technology has been widely used. The study of fracture initiation and propagation during cuttings re-injection is important for operational design. Fracturing is a complex physical process that combines fluid seepage, temperature diffusion, stress change, and rock damage. In offshore cuttings re-injection projects, the temperature difference between the injection slurry and the formation has a significant impact on the fracture behaviors, especially in high-temperature-high-pressure (HTHP) formations. In this paper, a fully coupled thermal-hydraulic-mechanical (THM) model was developed by the cohesive element method for modeling cuttings re-injection. The multi-physical field evolution in cuttings re-injection process in HTHP offshore formation was studied. The simulation results show that the cooling effect of the injection fluid causes the contraction of the formation which leads to an increase in the tensile stress of the rock and a decrease in the formation fracture pressure. The cooling effect results in a wider and shorter fracture than the case without the consideration of the cooling effect. Therefore, it allows more slurry to be injected in a limited near-wellbore zone, reducing the risk of slurry leakage during the injection process. The cooling effect is positively correlated with the temperature difference between the injection slurry and the formation.
{"title":"Fully Coupled Thermal-Hydraulic-Mechanical Analysis of Hydraulic Fracture in Offshore Cuttings Re-Injection","authors":"Shuai Zhang, Yongcun Feng, Bin Li","doi":"10.4043/31384-ms","DOIUrl":"https://doi.org/10.4043/31384-ms","url":null,"abstract":"\u0000 Cuttings reinjection is an effective way to treat oilfield waste. There is still a risk of slurry leakage during the field operations although cuttings re-injection technology has been widely used. The study of fracture initiation and propagation during cuttings re-injection is important for operational design. Fracturing is a complex physical process that combines fluid seepage, temperature diffusion, stress change, and rock damage. In offshore cuttings re-injection projects, the temperature difference between the injection slurry and the formation has a significant impact on the fracture behaviors, especially in high-temperature-high-pressure (HTHP) formations. In this paper, a fully coupled thermal-hydraulic-mechanical (THM) model was developed by the cohesive element method for modeling cuttings re-injection. The multi-physical field evolution in cuttings re-injection process in HTHP offshore formation was studied. The simulation results show that the cooling effect of the injection fluid causes the contraction of the formation which leads to an increase in the tensile stress of the rock and a decrease in the formation fracture pressure. The cooling effect results in a wider and shorter fracture than the case without the consideration of the cooling effect. Therefore, it allows more slurry to be injected in a limited near-wellbore zone, reducing the risk of slurry leakage during the injection process. The cooling effect is positively correlated with the temperature difference between the injection slurry and the formation.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89464547","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}
Naturally fractured reservoirs are more difficult, complex and expensive to evaluate using numerical simulation when compared to conventional reservoirs. There are well known approaches, dual porosity and dual permeability system in which two grids - one for the fractures and another one for matrix – are used to model the behavior of fracture reservoirs characterized by initial high production followed by a steep decline and then low production for many years. However, most of the time these approaches require a large amount of input data in addition to being computationally too expensive and time consuming in field applications utilizing many grid blocks to model. This paper presents a new pseudo-approach in which a single porosity model can be used for modelling of naturally fractured reservoirs with some modification in the absolute permeability and relative permeabilities. The absolute permeability of the single porosity model is enhanced to capture the effect of permeability from the fracture. This can be a multiplier globally applied to all blocks or local enhancement around the wells having high fracture intensity. Initially the flow is mostly coming from the fracture network so the first "fracture dominant" relative permeability or combination of fracture/matrix relative permeability is used, and later in the lifetime of the reservoir, when the flow transitions to primarily matrix flow, a second "matrix dominated" relative permeability is used to control the fluid flow. The key in this approach is to find the time/date which flow diverted from fracture to matrix. This can be determined from the overall oil rate of the field. After finding the correct date, then the relative permeability is altered from "fracture dominant" to "matrix dominant" recurrently on that time. The new approach is applied to an onshore matured field in Indonesia. The numerical model has the total grid blocks of 1.2 million, 75 wells and around 700 thousand active grid blocks. The original single porosity model could not match the field historical data while dual porosity could captured it correctly. Numerical simulation is utilized along with the new method in a single porosity model for history matching of the field and the results are compared with the dual porosity model of the same model. The absolute permeability enhancement and the first relative permeability curves are used as matching parameters. The results of this study show that both models having same/similar production and pressure profile. Liquid rate, oil rate, water cut, GOR and average pressure are compared. Furthermore, the runtime for the field case improved by 75%. The total runtime of the new approach was 22 hours resulting in significant speed-up compared to the dual porosity runtime of about 4 days. This approach is going to be used for few other fractured reservoirs in the future where time and/or fracture data are limited.
{"title":"A New Reservoir Simulation Approach for Modelling of Naturally Fractured Reservoir in an Onshore Indonesian Mature Field","authors":"Seyed Mousa Mousavimirkalaei, Irma Primasari, Ninik Purwatiningsih, M. Edmondson, Andika Wicakson","doi":"10.4043/31389-ms","DOIUrl":"https://doi.org/10.4043/31389-ms","url":null,"abstract":"\u0000 Naturally fractured reservoirs are more difficult, complex and expensive to evaluate using numerical simulation when compared to conventional reservoirs. There are well known approaches, dual porosity and dual permeability system in which two grids - one for the fractures and another one for matrix – are used to model the behavior of fracture reservoirs characterized by initial high production followed by a steep decline and then low production for many years. However, most of the time these approaches require a large amount of input data in addition to being computationally too expensive and time consuming in field applications utilizing many grid blocks to model.\u0000 This paper presents a new pseudo-approach in which a single porosity model can be used for modelling of naturally fractured reservoirs with some modification in the absolute permeability and relative permeabilities. The absolute permeability of the single porosity model is enhanced to capture the effect of permeability from the fracture. This can be a multiplier globally applied to all blocks or local enhancement around the wells having high fracture intensity. Initially the flow is mostly coming from the fracture network so the first \"fracture dominant\" relative permeability or combination of fracture/matrix relative permeability is used, and later in the lifetime of the reservoir, when the flow transitions to primarily matrix flow, a second \"matrix dominated\" relative permeability is used to control the fluid flow. The key in this approach is to find the time/date which flow diverted from fracture to matrix. This can be determined from the overall oil rate of the field. After finding the correct date, then the relative permeability is altered from \"fracture dominant\" to \"matrix dominant\" recurrently on that time.\u0000 The new approach is applied to an onshore matured field in Indonesia. The numerical model has the total grid blocks of 1.2 million, 75 wells and around 700 thousand active grid blocks. The original single porosity model could not match the field historical data while dual porosity could captured it correctly. Numerical simulation is utilized along with the new method in a single porosity model for history matching of the field and the results are compared with the dual porosity model of the same model. The absolute permeability enhancement and the first relative permeability curves are used as matching parameters.\u0000 The results of this study show that both models having same/similar production and pressure profile. Liquid rate, oil rate, water cut, GOR and average pressure are compared. Furthermore, the runtime for the field case improved by 75%. The total runtime of the new approach was 22 hours resulting in significant speed-up compared to the dual porosity runtime of about 4 days. This approach is going to be used for few other fractured reservoirs in the future where time and/or fracture data are limited.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75812938","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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