Chang Siong Ting, N. Minggu, Dahlila Kamat, Kit Teng Chaw, Chee Seong Tan, Sanggeetha Kalidas, Gladson Joe Barretto
In this paper, we evaluate the effectiveness of production enhancement activities for well B Long-string (i.e. well BL) using distributed temperature sensing (DTS) technology. Installation of permanent fiber-optic cable across the reservoir sections has enabled gas lift monitoring, identification of well integrity issues and zonal inflow profiling from perforation contribution. Recent DTS interpretation indicated leak point at 4,025ft with sub-optimal gas lifting which has resulted in loss of 300 BOPD. Hence, well intervention such as tubing patch and gas lift valve change-out (GLVC) were conducted consecutively to restore its initial production. The effectiveness of executed remedial jobs will be discussed along the findings and interpretations of the temperature survey result from DTS. Well BL is a long-string gas lifted producer that flows from two zones. Prior to the tubing patch, the multi-finger caliper tool was logged in well BL to further validate the leak point indicated by DTS. The caliper logging survey identified that maximum penetration (100%) occurs at 4,025 ft, which classified it as a leak hole. Time-lapsed DTS measurement, specifically; pre-, during-, and post-tubing patch and GLVC were acquired. It is analyzed along with Permanent Downhole Gauge (PDG) data and surface parameters [e.g., tubing head pressure (THP), casing head pressure (CHP), Gas lift injection rate, etc]. The multi-measurement interpretation is further complemented by nodal analysis for a more conclusive finding. A baseline temperature was acquired during the shut-in period as a geothermal gradient reference to determine any anomalies against the temperature acquired during each event. Operation quick-look indicated both GLVC and tubing patch are deemed to be successfully carried out as per the program with minimal workover challenges. However, the executed remedial jobs that are expected to resume the production from Well BL to its initial production shows it is still underperforming. Production rate keeps declining during the post-job execution. Qualitative interpretation from DTS temperature profiles, reveals another significant tubing leak detected at 4,007ft after the tubing patch. By accidental find, the DTS data also showed that the production from top zone (short string) was produced through the leak hole at the long string to surface. Further investigation applying nodal analysis and PDG data indicated that crossflow was observed from the top zone production through and into bottom leak hole at the long string. This has led to serious production loss in well BL. Furthermore, temperature profile that's demonstrated the injected gas was unable to reach the orifice (operating node) due to multi-pointing, thus resulted in the well's underperforming production post-remedial job execution. In this root-cause finding showcase, DTS data have been providing valuable findings on the effectiveness of executed remedial jobs in well BL. DTS measurement and monito
{"title":"Production Enhancement Evaluation via Permanent Fiber Optics Distributed Temperature Sensing Interpretation for a Gas-Lifted Producer in Field B, Offshore Malaysia","authors":"Chang Siong Ting, N. Minggu, Dahlila Kamat, Kit Teng Chaw, Chee Seong Tan, Sanggeetha Kalidas, Gladson Joe Barretto","doi":"10.4043/31654-ms","DOIUrl":"https://doi.org/10.4043/31654-ms","url":null,"abstract":"\u0000 In this paper, we evaluate the effectiveness of production enhancement activities for well B Long-string (i.e. well BL) using distributed temperature sensing (DTS) technology. Installation of permanent fiber-optic cable across the reservoir sections has enabled gas lift monitoring, identification of well integrity issues and zonal inflow profiling from perforation contribution. Recent DTS interpretation indicated leak point at 4,025ft with sub-optimal gas lifting which has resulted in loss of 300 BOPD. Hence, well intervention such as tubing patch and gas lift valve change-out (GLVC) were conducted consecutively to restore its initial production. The effectiveness of executed remedial jobs will be discussed along the findings and interpretations of the temperature survey result from DTS.\u0000 Well BL is a long-string gas lifted producer that flows from two zones. Prior to the tubing patch, the multi-finger caliper tool was logged in well BL to further validate the leak point indicated by DTS. The caliper logging survey identified that maximum penetration (100%) occurs at 4,025 ft, which classified it as a leak hole. Time-lapsed DTS measurement, specifically; pre-, during-, and post-tubing patch and GLVC were acquired. It is analyzed along with Permanent Downhole Gauge (PDG) data and surface parameters [e.g., tubing head pressure (THP), casing head pressure (CHP), Gas lift injection rate, etc]. The multi-measurement interpretation is further complemented by nodal analysis for a more conclusive finding. A baseline temperature was acquired during the shut-in period as a geothermal gradient reference to determine any anomalies against the temperature acquired during each event.\u0000 Operation quick-look indicated both GLVC and tubing patch are deemed to be successfully carried out as per the program with minimal workover challenges. However, the executed remedial jobs that are expected to resume the production from Well BL to its initial production shows it is still underperforming. Production rate keeps declining during the post-job execution. Qualitative interpretation from DTS temperature profiles, reveals another significant tubing leak detected at 4,007ft after the tubing patch. By accidental find, the DTS data also showed that the production from top zone (short string) was produced through the leak hole at the long string to surface. Further investigation applying nodal analysis and PDG data indicated that crossflow was observed from the top zone production through and into bottom leak hole at the long string. This has led to serious production loss in well BL. Furthermore, temperature profile that's demonstrated the injected gas was unable to reach the orifice (operating node) due to multi-pointing, thus resulted in the well's underperforming production post-remedial job execution. In this root-cause finding showcase, DTS data have been providing valuable findings on the effectiveness of executed remedial jobs in well BL. DTS measurement and monito","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89965500","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Asadi, Riezal Arieffiandhany, P. Setiawan, Hendro Vico, Christine Lorita, A. Mansur, R. Chrislianto, G. Sucahyo
Hydraulic fracturing optimisation for tight sandstone requires a reliable geomechanical model in the reservoirs and bounding formations to achieve an optimum production after fracturing. This paper presents a case study of Upper Cibulakan tight sandstone reservoirs in an oil field located in Offshore Northwest Java, Indonesia. Field structure is composed of multiple reservoir sandstones with interlayer shales. Two sandstone units with gross thicknesses up to 60 feet, effective porosity of 15% and permeability of 8 mD were targeted for hydraulic fracturing. An integrated approach is proposed to use available offset wells data, real-time acoustic logs, calibrated geomechanical model, and miniFrac and Step-rate tests to optimise hydraulic fracturing parameters and treatment schedule. In pre-fracturing stage, geomechanical model was developed for target intervals using offset wells data including fracture closure pressures from past miniFrac tests. To estimate the reservoir and bounding formations Young’ modulus and Poisson's ratio, compressional and dipole shear wave slowness logs as well as bulk density logs from offset wells were used. Poroelastic minimum horizontal stress in the sandstone intervals was calibrated with closure pressure data while bounding shale stress was calibrated with regional leak-off pressures. The final stress model of offset wells was verified with the borehole condition and drilling experiences. Target well for hydraulic fracturing was drilled with a 12¼° wellbore, 45 degrees deviated and oriented sub-parallel to maximum horizontal stress azimuth (north south). Processed acoustic logs were used to revise the pre-frac rock mechanical properties which verified the low ranges of static Young's modulus. Analysis of mini fall-off tests revealed important information about reservoir pressure depletion of ~250 psi which was not captured by offset wells pore pressure data. Pore pressure profile across the reservoirs was modified and depletion induced poroelastic stresses were estimated. Stress profile calibrated with actual closure pressure data from miniFrac test integrated with actual reservoir pressure revealed the stress contrast of up to ~350 psi between reservoir sandstones and bounding shales, which is favorable for fracture containment. Calibrated Geomechanics model was used to update the treatment schedule for main hydraulic fracturing including optimisation of size, volume and concentration of injected proppants and volume of fracturing fluid. Integrated Geomechanics modelling with acoustic logging and fracturing design enabled to achieve a successful hydraulic fracturing stimulation by exceeding the planned production rate. Post fracturing production test showed initial rate of approximately 50-barrel oil per day (bbl/d) higher than expected production rate from stimulated reservoir volume. Calibrated geomechanics model provided valuable inputs for proppant size and conductivity optimisation to reduce the effects o
{"title":"Integrating Advanced Acoustic Measurement and Geomechanics with Hydraulic Fracturing Field Data Helped to Improve Hydraulic Fracture Geometry Characterization and Increase Productivity","authors":"S. Asadi, Riezal Arieffiandhany, P. Setiawan, Hendro Vico, Christine Lorita, A. Mansur, R. Chrislianto, G. Sucahyo","doi":"10.4043/31647-ms","DOIUrl":"https://doi.org/10.4043/31647-ms","url":null,"abstract":"\u0000 Hydraulic fracturing optimisation for tight sandstone requires a reliable geomechanical model in the reservoirs and bounding formations to achieve an optimum production after fracturing. This paper presents a case study of Upper Cibulakan tight sandstone reservoirs in an oil field located in Offshore Northwest Java, Indonesia. Field structure is composed of multiple reservoir sandstones with interlayer shales. Two sandstone units with gross thicknesses up to 60 feet, effective porosity of 15% and permeability of 8 mD were targeted for hydraulic fracturing. An integrated approach is proposed to use available offset wells data, real-time acoustic logs, calibrated geomechanical model, and miniFrac and Step-rate tests to optimise hydraulic fracturing parameters and treatment schedule.\u0000 In pre-fracturing stage, geomechanical model was developed for target intervals using offset wells data including fracture closure pressures from past miniFrac tests. To estimate the reservoir and bounding formations Young’ modulus and Poisson's ratio, compressional and dipole shear wave slowness logs as well as bulk density logs from offset wells were used. Poroelastic minimum horizontal stress in the sandstone intervals was calibrated with closure pressure data while bounding shale stress was calibrated with regional leak-off pressures. The final stress model of offset wells was verified with the borehole condition and drilling experiences.\u0000 Target well for hydraulic fracturing was drilled with a 12¼° wellbore, 45 degrees deviated and oriented sub-parallel to maximum horizontal stress azimuth (north south). Processed acoustic logs were used to revise the pre-frac rock mechanical properties which verified the low ranges of static Young's modulus. Analysis of mini fall-off tests revealed important information about reservoir pressure depletion of ~250 psi which was not captured by offset wells pore pressure data. Pore pressure profile across the reservoirs was modified and depletion induced poroelastic stresses were estimated. Stress profile calibrated with actual closure pressure data from miniFrac test integrated with actual reservoir pressure revealed the stress contrast of up to ~350 psi between reservoir sandstones and bounding shales, which is favorable for fracture containment. Calibrated Geomechanics model was used to update the treatment schedule for main hydraulic fracturing including optimisation of size, volume and concentration of injected proppants and volume of fracturing fluid.\u0000 Integrated Geomechanics modelling with acoustic logging and fracturing design enabled to achieve a successful hydraulic fracturing stimulation by exceeding the planned production rate. Post fracturing production test showed initial rate of approximately 50-barrel oil per day (bbl/d) higher than expected production rate from stimulated reservoir volume. Calibrated geomechanics model provided valuable inputs for proppant size and conductivity optimisation to reduce the effects o","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"100 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77673155","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Gou, Raja Azlan Raja Ismail, F. Yuen, Nadia Zulkifli, R. Hee, P. van der Vegt, B. Ralphie, Fazideen Hassan
South Furious is an oilfield in the Inboard Belt offshore North Sabah with oil production since 1979. The field is heavily faulted and compartmentalized, making it structurally complex and challenging for development. It is believed that the field has a low recovery factor, despite having a relatively large oil in-place volume reported. Its highly-heterogenous Stage IVA reservoir with thin sand-shale intercalations, and poor seismic imaging quality make stratigraphic interpretation and well correlations highly uncertain. Recognizing the limitations of conventional methods for well correlation in South Furious, SEA Hibiscus decided to take a quantitative approach on the existing well logs itself, particularly the gamma ray (GR) curve. This data-driven approach is a shift from the unsuccessful model-based method. Cyclostratigraphic analysis using CycloLog works on the principle that extra-terrestrial forces described by the Milankovitch Cycles have a huge influence on sedimentation processes, and its record are preserved in the well logs that we acquire while drilling, although not always obvious without the proper quantitative approach. This high-resolution stratigraphic method allows the detection of cyclic signals in facies-sensitive wireline logs (e.g., gamma ray), including subtle ones, and at resolutions that are equivalent to 4th to 6th Order stratigraphic cycles. Utilizing the Integrated Prediction Error Filter Analysis (INPEFA), geological breaks or events are quantitatively and objectively identified. Cyclostratigraphic and climate stratigraphy concepts as described by Perlmutter and Matthews (1990) and Nio (2005) form the basis of this analysis, which is an evolution of traditional sequence stratigraphic concepts. Results from the 10 pilot wells in South Furious show dramatic improvements in the stratigraphic correlation resolution, particularly in the deeper/older sections, allowing correlations to be made across different fault block segments, previously nearly impossible. With the ongoing inclusion of more wells to the cyclostratigraphic study and future plans to integrate independent chemostratigraphic data, a more robust stratigraphic framework for the field would be established. Results from the current study prove that the cyclostratigraphic method allows objective, quantitative and data-driven stratigraphic well correlations to be made from a systematic and quantitative review of existing well logs, without additional rock sampling or measurement, and in a cost-effective manner. Geoscientists should always be receptive to new ways of working, including utilizing data and techniques that have origins outside mainstream geoscience.
South Furious油田位于Sabah北部近海Inboard Belt，自1979年开始生产石油。该油田断层严重，分隔严重，使得其结构复杂，开发具有挑战性。据报道，该油田的产油量相对较大，但采收率较低。其IVA级储层高度非均质，砂页岩夹层薄，地震成像质量差，使得地层解释和井对比具有很大的不确定性。SEA Hibiscus认识到South Furious常规井对比方法的局限性，决定对现有测井曲线，特别是伽马射线(GR)曲线采取定量方法。这种数据驱动的方法是从失败的基于模型的方法转变而来的。使用CycloLog进行旋回地层分析的原理是，米兰科维奇旋回所描述的地外力量对沉积过程有巨大影响，其记录保存在我们在钻探时获得的测井曲线中，尽管在没有适当的定量方法的情况下并不总是很明显。这种高分辨率地层方法可以在对相敏感的电缆测井(如伽马射线)中检测到旋回信号，包括细微的旋回信号，其分辨率相当于4至6级地层旋回。利用综合预测误差滤波分析(INPEFA)，可以定量和客观地识别地质断裂或事件。Perlmutter和Matthews(1990)以及Nio(2005)所描述的旋回地层学和气候地层学概念构成了这一分析的基础，这是传统层序地层学概念的演变。South Furious的10口试验井的结果显示，地层对比分辨率有了显著提高，特别是在更深/更老的剖面，可以在不同的断块段之间进行对比，这在以前几乎是不可能的。随着越来越多的井加入到旋回地层学研究中，以及未来整合独立化学地层学数据的计划，将为该油田建立一个更强大的地层框架。目前的研究结果证明，旋回地层学方法可以通过对现有测井曲线的系统和定量评价，以客观、定量和数据驱动的方式进行地层对比，而无需额外的岩石取样或测量，而且成本效益高。地球科学家应该始终接受新的工作方式，包括利用来自主流地球科学之外的数据和技术。
{"title":"Deciphering the Record of the Sun-Earth Dance in Well Logs: The Extra-Terrestrial Imprint and its Application to High-Resolution Stratigraphy and Well Correlation in South Furious Field, Offshore North Sabah","authors":"P. Gou, Raja Azlan Raja Ismail, F. Yuen, Nadia Zulkifli, R. Hee, P. van der Vegt, B. Ralphie, Fazideen Hassan","doi":"10.4043/31567-ms","DOIUrl":"https://doi.org/10.4043/31567-ms","url":null,"abstract":"\u0000 South Furious is an oilfield in the Inboard Belt offshore North Sabah with oil production since 1979. The field is heavily faulted and compartmentalized, making it structurally complex and challenging for development. It is believed that the field has a low recovery factor, despite having a relatively large oil in-place volume reported. Its highly-heterogenous Stage IVA reservoir with thin sand-shale intercalations, and poor seismic imaging quality make stratigraphic interpretation and well correlations highly uncertain. Recognizing the limitations of conventional methods for well correlation in South Furious, SEA Hibiscus decided to take a quantitative approach on the existing well logs itself, particularly the gamma ray (GR) curve. This data-driven approach is a shift from the unsuccessful model-based method.\u0000 Cyclostratigraphic analysis using CycloLog works on the principle that extra-terrestrial forces described by the Milankovitch Cycles have a huge influence on sedimentation processes, and its record are preserved in the well logs that we acquire while drilling, although not always obvious without the proper quantitative approach. This high-resolution stratigraphic method allows the detection of cyclic signals in facies-sensitive wireline logs (e.g., gamma ray), including subtle ones, and at resolutions that are equivalent to 4th to 6th Order stratigraphic cycles. Utilizing the Integrated Prediction Error Filter Analysis (INPEFA), geological breaks or events are quantitatively and objectively identified. Cyclostratigraphic and climate stratigraphy concepts as described by Perlmutter and Matthews (1990) and Nio (2005) form the basis of this analysis, which is an evolution of traditional sequence stratigraphic concepts.\u0000 Results from the 10 pilot wells in South Furious show dramatic improvements in the stratigraphic correlation resolution, particularly in the deeper/older sections, allowing correlations to be made across different fault block segments, previously nearly impossible. With the ongoing inclusion of more wells to the cyclostratigraphic study and future plans to integrate independent chemostratigraphic data, a more robust stratigraphic framework for the field would be established.\u0000 Results from the current study prove that the cyclostratigraphic method allows objective, quantitative and data-driven stratigraphic well correlations to be made from a systematic and quantitative review of existing well logs, without additional rock sampling or measurement, and in a cost-effective manner. Geoscientists should always be receptive to new ways of working, including utilizing data and techniques that have origins outside mainstream geoscience.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"409 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89658410","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. I. M. Ishak, T. Lemma, Mohd Hafis Muhammad Daud, Norfazlin Mohd Fatimi, A. R. A Rahman, Azam A Rahman, A. R. Othman
IGUSA (Intelligent Global Ultimate Strength Analysis) is a tool developed by PETRONAS to predict the ultimate strength of a fixed offshore jacket platforms installed in Malaysian waters using machine learning techniques. The ultimate strength, or more commonly represented by Reserve Strength Ratio (RSR), is a gauge of the robustness and redundancy inhibited in a fixed offshore structure. It is very useful in being an indicator for fitness-for-purpose of the platform and which is an integral part of Structural Integrity Management (SIM). However, a typical deterministic ultimate strength analysis for a fixed offshore structure is a time intensive process, using specialized software in the realm of plastic collapse analysis. As such, it is intended that machine learning techniques to be utilized to perform a prediction for the RSR, subsequently optimizing resources in SIM processes. This paper will discuss the development of data-driven predictive model of IGUSA. Various machine learning techniques were experimented on PETRONAS' Global Ultimate Strength Analysis (GUSA) data. The objective is to obtain an accurate and reliable model to predict the RSR. Nonlinear regression using Artificial Neural Network (ANN) was found to provide the best model to predict the Base Shear Collapse, and hence the RSR for a typical jacket platform. The ANN model was incorporated into the IGUSA tool for deployment within PETRONAS. It is envisaged that IGUSA will be a valuable rapid screening tool for the typical platforms and the deterministic ultimate strength efforts can be focused on the more critical platforms. Based on IGUSA development, the usage of machine learning techniques is proven to be useful in the structural engineering discipline. It is hoped that IGUSA will be able to assist PETRONAS and other Oil and Gas Operators in the region to optimize their resources in SIM processes.
{"title":"IGUSA: Prediction of Ultimate Strength of Fixed Offshore Structures in Malaysian Waters Using Machine Learning Techniques","authors":"M. I. M. Ishak, T. Lemma, Mohd Hafis Muhammad Daud, Norfazlin Mohd Fatimi, A. R. A Rahman, Azam A Rahman, A. R. Othman","doi":"10.4043/31493-ms","DOIUrl":"https://doi.org/10.4043/31493-ms","url":null,"abstract":"\u0000 IGUSA (Intelligent Global Ultimate Strength Analysis) is a tool developed by PETRONAS to predict the ultimate strength of a fixed offshore jacket platforms installed in Malaysian waters using machine learning techniques.\u0000 The ultimate strength, or more commonly represented by Reserve Strength Ratio (RSR), is a gauge of the robustness and redundancy inhibited in a fixed offshore structure. It is very useful in being an indicator for fitness-for-purpose of the platform and which is an integral part of Structural Integrity Management (SIM). However, a typical deterministic ultimate strength analysis for a fixed offshore structure is a time intensive process, using specialized software in the realm of plastic collapse analysis. As such, it is intended that machine learning techniques to be utilized to perform a prediction for the RSR, subsequently optimizing resources in SIM processes.\u0000 This paper will discuss the development of data-driven predictive model of IGUSA. Various machine learning techniques were experimented on PETRONAS' Global Ultimate Strength Analysis (GUSA) data. The objective is to obtain an accurate and reliable model to predict the RSR. Nonlinear regression using Artificial Neural Network (ANN) was found to provide the best model to predict the Base Shear Collapse, and hence the RSR for a typical jacket platform. The ANN model was incorporated into the IGUSA tool for deployment within PETRONAS. It is envisaged that IGUSA will be a valuable rapid screening tool for the typical platforms and the deterministic ultimate strength efforts can be focused on the more critical platforms.\u0000 Based on IGUSA development, the usage of machine learning techniques is proven to be useful in the structural engineering discipline. It is hoped that IGUSA will be able to assist PETRONAS and other Oil and Gas Operators in the region to optimize their resources in SIM processes.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88434983","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Al-Sabea, M. Patra, A. Abu-Eida, Jamayel Mubarak Dhafiri, M. Gobran, Fatemah Amir Al Rasheed, S. Prosvirkin
The Horizontal wells enhance reservoir performance by placing a long wellbore section within the reservoir. As they help in reducing water and/or gas production, increasing oil rates, reducing sand production and finally in achieving efficient drainage of the reservoir. The inflow control devices (ICDs) are used to address the issues of premature water and/or gas breakthrough, uniform flow distribution and reservoir depletion in the oilfield. They reduce the flow of unwanted fluids and balance the production distribution across the entire lateral section. The production contribution across the ICDs monitoring to take necessary remedial action is one of the challenges in this type of completion. In this case study, the main objective was to determine the contribution profile and source of water in horizontal well with passive ICD completion installed back in 2011. The various challenges were the low production rate, heavy oil with water, erratic and inconsistent nature of the well flow, ESP design test with lack of recent flow results, and lack of some data about the ICDs. In addition, unlike most of the cases where the ICDs are installed in open hole, this case the ICDs are installed in 7in liner with nine perforation intervals. This paper presents the use of multi arrays production logging combined with spectral noise and high precise temperature tools, to determine the contribution profile and source of water in this challenging ICD completion. The contribution profile across the ICDs was determined using the multi arrays production logging data and temperature simulation models assisted by noise data. The results were in contrary to the previous production logging results and helped significantly in the design of proper ICD cleaning operations. The work-over resulted in successfully restoring and attaining high oil gain. The innovative combination of multi arrays production logging combined with spectral noise and high precise temperature tools to determine the contribution profile and source of water in horizontal well with ICD completion.
{"title":"Defining the Zonal Contribution in a Horizontal Well with Cased Hole ICD's Completion Using Innovative Integration of Multi Arrays Production Logging, Spectral Noise and High Resolution Temperature Log","authors":"S. Al-Sabea, M. Patra, A. Abu-Eida, Jamayel Mubarak Dhafiri, M. Gobran, Fatemah Amir Al Rasheed, S. Prosvirkin","doi":"10.4043/31593-ms","DOIUrl":"https://doi.org/10.4043/31593-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The Horizontal wells enhance reservoir performance by placing a long wellbore section within the reservoir. As they help in reducing water and/or gas production, increasing oil rates, reducing sand production and finally in achieving efficient drainage of the reservoir. The inflow control devices (ICDs) are used to address the issues of premature water and/or gas breakthrough, uniform flow distribution and reservoir depletion in the oilfield. They reduce the flow of unwanted fluids and balance the production distribution across the entire lateral section. The production contribution across the ICDs monitoring to take necessary remedial action is one of the challenges in this type of completion.\u0000 In this case study, the main objective was to determine the contribution profile and source of water in horizontal well with passive ICD completion installed back in 2011. The various challenges were the low production rate, heavy oil with water, erratic and inconsistent nature of the well flow, ESP design test with lack of recent flow results, and lack of some data about the ICDs. In addition, unlike most of the cases where the ICDs are installed in open hole, this case the ICDs are installed in 7in liner with nine perforation intervals.\u0000 \u0000 \u0000 \u0000 This paper presents the use of multi arrays production logging combined with spectral noise and high precise temperature tools, to determine the contribution profile and source of water in this challenging ICD completion.\u0000 \u0000 \u0000 \u0000 The contribution profile across the ICDs was determined using the multi arrays production logging data and temperature simulation models assisted by noise data. The results were in contrary to the previous production logging results and helped significantly in the design of proper ICD cleaning operations. The work-over resulted in successfully restoring and attaining high oil gain.\u0000 \u0000 \u0000 \u0000 The innovative combination of multi arrays production logging combined with spectral noise and high precise temperature tools to determine the contribution profile and source of water in horizontal well with ICD completion.\u0000","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 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":"84955716","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}
Working with naturally fractured reservoirs (NFRs) can be challenging. Inadequate understanding of the enhanced oil recovery (EOR) driving forces in these reservoirs may result in serious conformance issues due to excessive water production. As a result, this work investigates and numerically validates some fundamental flow mechanisms in heterogeneous reservoirs, particularly capillary-dominant ones, to highlight the best EOR strategy for this specific case. Consequently, a two-dimensional lab-scale reservoir model with injection and production ports was designed, fabricated, and tested in single-phase and two-phase flow scenarios, simulating a water-wet fractured system. First, a single-phase flow waterflood baseline was studied, compared to the literature, verified by commercial reservoir simulation software, and eventually considered to calibrate the porosity and permeability model in the simulation model where the controlling variables are limited. Based on this work, the same procedures were experimentally repeated and verified by simulation, where waterflooding and polymer injection were used to displace oil with more governing variables. The single-phase scenarios aided in distinguishing between the waterflood and polymer flood cases. Water prefers to channel through high permeable streaks when injected into a fractured water-wet reservoir, resulting in poor volumetric sweep and significant bypassed zones. Whereas the controlling variables in two-phase flow were increased, capillarity and mobility ratio were dominant in the simulation. During waterflooding, flow divergence was observed faster toward the matrix medium, overriding the high permeability front in the fracture due to the strong capillarity contrast between the matrix and fracture media. Even when capillarity is strongly present, polymer flooding demonstrated a better volumetric sweep in all scenarios. The unique demonstration of fluid flow inside the two-dimensional lab-scale reservoir model, as well as numerical simulation, shed light on the efficacy of these EOR strategies in fractured reservoirs. Furthermore, for the first time, the behavior of capillary-dominant reservoirs with an advancing flow path within smaller pores compared to larger ones within the reservoir media has been experimentally captured. Understanding reservoir characteristics and having the know-how to implement the best recovery scenario can, in fact, maximize the field's life cycle and increase the Recovery Factor (RF).
{"title":"An Experimental and Numerical Approach for the Best Enhanced Oil Recovery Strategy in Capillary-Dominant Reservoirs","authors":"Ahmad Alabdulghani, H. Hoteit, King Abdullah","doi":"10.4043/31602-ms","DOIUrl":"https://doi.org/10.4043/31602-ms","url":null,"abstract":"\u0000 Working with naturally fractured reservoirs (NFRs) can be challenging. Inadequate understanding of the enhanced oil recovery (EOR) driving forces in these reservoirs may result in serious conformance issues due to excessive water production. As a result, this work investigates and numerically validates some fundamental flow mechanisms in heterogeneous reservoirs, particularly capillary-dominant ones, to highlight the best EOR strategy for this specific case.\u0000 Consequently, a two-dimensional lab-scale reservoir model with injection and production ports was designed, fabricated, and tested in single-phase and two-phase flow scenarios, simulating a water-wet fractured system. First, a single-phase flow waterflood baseline was studied, compared to the literature, verified by commercial reservoir simulation software, and eventually considered to calibrate the porosity and permeability model in the simulation model where the controlling variables are limited. Based on this work, the same procedures were experimentally repeated and verified by simulation, where waterflooding and polymer injection were used to displace oil with more governing variables.\u0000 The single-phase scenarios aided in distinguishing between the waterflood and polymer flood cases. Water prefers to channel through high permeable streaks when injected into a fractured water-wet reservoir, resulting in poor volumetric sweep and significant bypassed zones. Whereas the controlling variables in two-phase flow were increased, capillarity and mobility ratio were dominant in the simulation. During waterflooding, flow divergence was observed faster toward the matrix medium, overriding the high permeability front in the fracture due to the strong capillarity contrast between the matrix and fracture media. Even when capillarity is strongly present, polymer flooding demonstrated a better volumetric sweep in all scenarios.\u0000 The unique demonstration of fluid flow inside the two-dimensional lab-scale reservoir model, as well as numerical simulation, shed light on the efficacy of these EOR strategies in fractured reservoirs. Furthermore, for the first time, the behavior of capillary-dominant reservoirs with an advancing flow path within smaller pores compared to larger ones within the reservoir media has been experimentally captured. Understanding reservoir characteristics and having the know-how to implement the best recovery scenario can, in fact, maximize the field's life cycle and increase the Recovery Factor (RF).","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85303360","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Zulkipli, B. Ralphie, J. Shah, Taufik Nordin, R. Masoudi, M. A. N. C. A. Razak, Ismail Marzuki Gazali, J. Toelke, S. Koronfol, Jacob Proctor, David Gonzales, Valentyn Vovk, Xuebei Shi, Huiwen Sheng
Advances in the fields of information technology, computation, and predictive analytics have permeated the energy industry and are reshaping methods for exploration, development, and production. These technologies can be applied to subsurface data to reliably predict a host of properties where only few are available. Among the numerous sources of subsurface data, rock and fluid analysis stand out as the means of directly measuring subsurface properties. The challenge in this work is to maximize information gain from legacy pdf reports and unstructured data tables that represented over 70 years of laboratory work and investment. The implication of modeling this data into an organized data store means better assessment of economic viability and producibility in frontier basins and the capability to identify bypassed pay in old wells that may not have rock material. This paper presents innovative and agile technologies that integrate data management, data quality assessment, and predictive machine learning to maximize the company asset value using underutilized legacy core data. The developed machine learning algorithms identify potential outliers, benchmark the valuable data against current industry standards, increase the confidence in data quality and avoid amplifying error in predicting reservoir properties. The workflow presented in the paper is expected to reduce uncertainties in subsurface studies caused by limited core data, improper analog selection, high cost, limited time for acquiring new cores, and long delivery times of core analysis data. The workflow reduces the requirement for subsurface formation evaluation rework as new data becomes available at later project stages resulting in optimized field development. The workflow enhanced by machine learning also improves the prediction and propagation of reservoir properties to uncored borehole sections. In conclusion, managing legacy core data and transforming it to generate new subsurface insights are critical step to establish a reliable database in support of business excellence and the digitalization journey. Innovative machine learning tools continue to unlock new values from legacy core data that significantly impact the entire reservoir life cycle including reserves booking, production forecasting, well placement, and completion design.
{"title":"Bringing Huge Core Analysis Legacy Data Into Life Using Machine Learning","authors":"S. Zulkipli, B. Ralphie, J. Shah, Taufik Nordin, R. Masoudi, M. A. N. C. A. Razak, Ismail Marzuki Gazali, J. Toelke, S. Koronfol, Jacob Proctor, David Gonzales, Valentyn Vovk, Xuebei Shi, Huiwen Sheng","doi":"10.4043/31419-ms","DOIUrl":"https://doi.org/10.4043/31419-ms","url":null,"abstract":"\u0000 Advances in the fields of information technology, computation, and predictive analytics have permeated the energy industry and are reshaping methods for exploration, development, and production. These technologies can be applied to subsurface data to reliably predict a host of properties where only few are available. Among the numerous sources of subsurface data, rock and fluid analysis stand out as the means of directly measuring subsurface properties. The challenge in this work is to maximize information gain from legacy pdf reports and unstructured data tables that represented over 70 years of laboratory work and investment. The implication of modeling this data into an organized data store means better assessment of economic viability and producibility in frontier basins and the capability to identify bypassed pay in old wells that may not have rock material.\u0000 This paper presents innovative and agile technologies that integrate data management, data quality assessment, and predictive machine learning to maximize the company asset value using underutilized legacy core data. The developed machine learning algorithms identify potential outliers, benchmark the valuable data against current industry standards, increase the confidence in data quality and avoid amplifying error in predicting reservoir properties.\u0000 The workflow presented in the paper is expected to reduce uncertainties in subsurface studies caused by limited core data, improper analog selection, high cost, limited time for acquiring new cores, and long delivery times of core analysis data. The workflow reduces the requirement for subsurface formation evaluation rework as new data becomes available at later project stages resulting in optimized field development. The workflow enhanced by machine learning also improves the prediction and propagation of reservoir properties to uncored borehole sections.\u0000 In conclusion, managing legacy core data and transforming it to generate new subsurface insights are critical step to establish a reliable database in support of business excellence and the digitalization journey. Innovative machine learning tools continue to unlock new values from legacy core data that significantly impact the entire reservoir life cycle including reserves booking, production forecasting, well placement, and completion design.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"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":"90788746","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}
Subsea pipeline is still considered a major cost contributor for offshore oil and gas field development. One of the major factors which affect this high cost is expensive installation cost due to expensive pipelay barge mobilization/demobilization cost, daily charter rate, as well as low speed for pipelay using welding. Several technologies were being considered to further optimize capital expenditure (CAPEX) for subsea pipeline installation. Mechanical Interference Fit Connector (MIFC) is currently being considered as an option to optimize the cost for rigid offshore pipeline installation. However, this technology is new in Malaysia, and the normal regulatory requirement for the application is still based on welding. There was a requirement to demonstrate the design and integrity of the MIFC to meet the conventional requirement for pipeline welding as part of the regulatory requirement for a permit to install (PTI) and permit to operate (PTO). This paper presents the approach to assess the design and performance of the MIFC joint. The assessment includes design verification using finite element analysis (FEA), and subsequent validation by full-scale testing. Several cases have been analyzed and tested to simulate the full-life cycle loading of the pipeline, starting from joint preparation, offshore installation loading, hydrotest loading and in-place loading during operation. The outcome of the modeling and verification by full-scale testing concluded that the MIFC was able to meet and even exceed the minimum requirement of the joint integrity during the full life cycle of the pipeline loading from installation until operation. As a result, the joint acceptance criteria envelope can be designed as acceptance criteria for regulatory purposes and for offshore application quality assurance and control purpose in-lieu of the acceptance criteria by welding. This approach has then been accepted by Malaysian Regulatory for PTI/PTO requirement and successfully applied for one of the pipeline projects in one of PETRONAS subsidiary as first application in Malaysia and the world longest MIFC application for a single subsea pipeline. This successful application opens the possibility for replication to other fields and other pipeline operators in Malaysia.
{"title":"Qualification of Mechanical Interference Fit Connection for Offshore Pipeline Application","authors":"I. Eka Putra, M. A. M. Adnan, M. Badaruddin","doi":"10.4043/31674-ms","DOIUrl":"https://doi.org/10.4043/31674-ms","url":null,"abstract":"\u0000 Subsea pipeline is still considered a major cost contributor for offshore oil and gas field development. One of the major factors which affect this high cost is expensive installation cost due to expensive pipelay barge mobilization/demobilization cost, daily charter rate, as well as low speed for pipelay using welding. Several technologies were being considered to further optimize capital expenditure (CAPEX) for subsea pipeline installation. Mechanical Interference Fit Connector (MIFC) is currently being considered as an option to optimize the cost for rigid offshore pipeline installation. However, this technology is new in Malaysia, and the normal regulatory requirement for the application is still based on welding. There was a requirement to demonstrate the design and integrity of the MIFC to meet the conventional requirement for pipeline welding as part of the regulatory requirement for a permit to install (PTI) and permit to operate (PTO). This paper presents the approach to assess the design and performance of the MIFC joint. The assessment includes design verification using finite element analysis (FEA), and subsequent validation by full-scale testing. Several cases have been analyzed and tested to simulate the full-life cycle loading of the pipeline, starting from joint preparation, offshore installation loading, hydrotest loading and in-place loading during operation. The outcome of the modeling and verification by full-scale testing concluded that the MIFC was able to meet and even exceed the minimum requirement of the joint integrity during the full life cycle of the pipeline loading from installation until operation. As a result, the joint acceptance criteria envelope can be designed as acceptance criteria for regulatory purposes and for offshore application quality assurance and control purpose in-lieu of the acceptance criteria by welding. This approach has then been accepted by Malaysian Regulatory for PTI/PTO requirement and successfully applied for one of the pipeline projects in one of PETRONAS subsidiary as first application in Malaysia and the world longest MIFC application for a single subsea pipeline. This successful application opens the possibility for replication to other fields and other pipeline operators in Malaysia.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"92 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83812285","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}
Southeast Asia is one of the leading regions globally in terms of planned gas developments in the next decade. We estimate sour gas contamination in Southeast Asian gas discoveries is one of the major challenges delaying over 10 billion barrels of oil equivalent gas resources from coming online. These developments are planned in Malaysia, Indonesia, and Vietnam, requiring around $20 billion of investments, and could potentially make a significant contribution to regional production post-2030. But the fields contain high levels of sour gas, which makes development challenging and costly. Sour gas refers to natural gas that contains significant amounts of acidic gases such as hydrogen sulfide and carbon dioxide (CO2). Some industry majors are moving forward with exploration and development - albeit at a slow pace. Off Malaysia, work on Petronas’ Kasawari, Shell's Rosmari-Marjoram and PTTEP's Lang Lebah fields have been lined up, while Indonesia has witnessed similar slow progress on similar projects operated by IOCs and the government is also hoping the potential of its Natuna D-Alpha field will attract investors. However, as domestic gas demand in the countries increases and output drops, efforts must be made to overcome the complex geology and associated challenges. In fact, globally SE Asia & NW Australia are one of the largest regions with concentrations of sour gas. The paper intends to highlight Southeast Asia's role in planned gas developments globally and the significance of these developments in regional production. We deep dive into the planned developments risked by the sour gas contamination which makes up over 40% of the gas resources planned for development in Southeast Asia by 2030.
{"title":"Billions of Barrels at Risk in Southeast Asia Due to Sour Gas","authors":"Prateek Pandey","doi":"10.4043/31335-ms","DOIUrl":"https://doi.org/10.4043/31335-ms","url":null,"abstract":"\u0000 Southeast Asia is one of the leading regions globally in terms of planned gas developments in the next decade. We estimate sour gas contamination in Southeast Asian gas discoveries is one of the major challenges delaying over 10 billion barrels of oil equivalent gas resources from coming online. These developments are planned in Malaysia, Indonesia, and Vietnam, requiring around $20 billion of investments, and could potentially make a significant contribution to regional production post-2030. But the fields contain high levels of sour gas, which makes development challenging and costly. Sour gas refers to natural gas that contains significant amounts of acidic gases such as hydrogen sulfide and carbon dioxide (CO2). Some industry majors are moving forward with exploration and development - albeit at a slow pace. Off Malaysia, work on Petronas’ Kasawari, Shell's Rosmari-Marjoram and PTTEP's Lang Lebah fields have been lined up, while Indonesia has witnessed similar slow progress on similar projects operated by IOCs and the government is also hoping the potential of its Natuna D-Alpha field will attract investors. However, as domestic gas demand in the countries increases and output drops, efforts must be made to overcome the complex geology and associated challenges. In fact, globally SE Asia & NW Australia are one of the largest regions with concentrations of sour gas. The paper intends to highlight Southeast Asia's role in planned gas developments globally and the significance of these developments in regional production. We deep dive into the planned developments risked by the sour gas contamination which makes up over 40% of the gas resources planned for development in Southeast Asia by 2030.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"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":"73547289","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}
Saikat Das, Supakit Rugsapun, Nilisip Juin Akang, M. A. Seleman, Kevin Riaz
There is a perception that conventional wireline logging operation in Managed Pressure Drilling (MPD) and Pressurised Mud Cap Drilling (PMCD) conditions is not feasible due to HSE risks associated with the operation. Rigging up a wireline assembly and safely performing the job while the well is experiencing total or partial loss circulation or potential gas migration is extremely challenging with currently available technology. However, with the new comprehensive technology, described in this paper, these challenges can be mitigated enabling acquisition of all desired formation evaluation data. MPD and PMCD techniques, with close loop adjustable back pressure, have gained wide acceptance. This is owed to the current market demand of drilling deep-water wells, with narrow mud windows and in fractured reservoirs, under total or partial loss conditions, safely and with optimum cost. To reduce the drilling risk, relatively simple drilling bottom hole assembly (BHA), with limited logging while drilling (LWD) tools, are preferred in such conditions. A new technological solution is desired to acquire complete formation evaluation data, on wireline, after drilling. Wireline well logging under this condition requires a non-standard and complex rig up, especially in the floater, to allow the operation to be performed safely but efficiently. With the new development of Managed Pressure Logging System (MPLS), an integration of Smart Sub System, and Grease Injection System, wireline operation can now be performed safely in active MPD/PMCD conditions. The newly developed smart sub, discussed in this paper, features an innovative system available for multiple operations including MPD/PMCD wireline logging. It provides the sought-after well control mechanism which allows wireline operations, through a side entry, without interfering with drilling rig's top drive system. The unique design of the sub is compatible with all industry-recognized grease injection and pack off systems used to maintain the desired pressure in the wellbore. When deployed with active PMCD condition, it creates a closed-loop system to enable the driller to continuously pump drilling fluid and adjust borehole pressure during wireline logging. This paper discusses the complete operational detail of a number of wireline logging operations performed in a deep-water well under MPD/PMCD condition. This includes planning, associated challenges, deployment risk assessment, standard operating procedure, and mitigation plan. The paper also incorporates standard data acquisition practices, results, lessons learned, and recommendations. This comprehensive workflow of wireline logging, with MPD/PMCD technique, and under total or partial loss condition, using the smart sub, pushes the wireline operating boundaries of data acquisition for formation evaluation, to places previously thought to be not feasible. This new solution has the potential to solve other challenging wireline deployments applicat
{"title":"Wireline Data Acquisition under Managed Pressure and Pressurized Mud Cap Drilling Condition – Pushing the Boundaries of Data Acquisition Envelop for Formation Evaluation","authors":"Saikat Das, Supakit Rugsapun, Nilisip Juin Akang, M. A. Seleman, Kevin Riaz","doi":"10.4043/31576-ms","DOIUrl":"https://doi.org/10.4043/31576-ms","url":null,"abstract":"\u0000 There is a perception that conventional wireline logging operation in Managed Pressure Drilling (MPD) and Pressurised Mud Cap Drilling (PMCD) conditions is not feasible due to HSE risks associated with the operation. Rigging up a wireline assembly and safely performing the job while the well is experiencing total or partial loss circulation or potential gas migration is extremely challenging with currently available technology. However, with the new comprehensive technology, described in this paper, these challenges can be mitigated enabling acquisition of all desired formation evaluation data.\u0000 MPD and PMCD techniques, with close loop adjustable back pressure, have gained wide acceptance. This is owed to the current market demand of drilling deep-water wells, with narrow mud windows and in fractured reservoirs, under total or partial loss conditions, safely and with optimum cost. To reduce the drilling risk, relatively simple drilling bottom hole assembly (BHA), with limited logging while drilling (LWD) tools, are preferred in such conditions. A new technological solution is desired to acquire complete formation evaluation data, on wireline, after drilling. Wireline well logging under this condition requires a non-standard and complex rig up, especially in the floater, to allow the operation to be performed safely but efficiently. With the new development of Managed Pressure Logging System (MPLS), an integration of Smart Sub System, and Grease Injection System, wireline operation can now be performed safely in active MPD/PMCD conditions.\u0000 The newly developed smart sub, discussed in this paper, features an innovative system available for multiple operations including MPD/PMCD wireline logging. It provides the sought-after well control mechanism which allows wireline operations, through a side entry, without interfering with drilling rig's top drive system. The unique design of the sub is compatible with all industry-recognized grease injection and pack off systems used to maintain the desired pressure in the wellbore. When deployed with active PMCD condition, it creates a closed-loop system to enable the driller to continuously pump drilling fluid and adjust borehole pressure during wireline logging. This paper discusses the complete operational detail of a number of wireline logging operations performed in a deep-water well under MPD/PMCD condition. This includes planning, associated challenges, deployment risk assessment, standard operating procedure, and mitigation plan. The paper also incorporates standard data acquisition practices, results, lessons learned, and recommendations.\u0000 This comprehensive workflow of wireline logging, with MPD/PMCD technique, and under total or partial loss condition, using the smart sub, pushes the wireline operating boundaries of data acquisition for formation evaluation, to places previously thought to be not feasible. This new solution has the potential to solve other challenging wireline deployments applicat","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74839875","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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