Hydrate formation in production and control lines has been a serious issue in the oil industry, especially in the deepwater offshore market. This article focuses on a compact temporary plant designed to be assembled on offshore rigs for heating and injecting high flow rate water to break hydrates. Hydrates are formed under determined conditions (high pressure at low temperature) in which natural gas hydrocarbon molecules are trapped in ice molecules, forming crystal structures and plugging or choking lines, causing operational problems. When preventive solutions, such as chemical inhibitors or thermal insulation, do not work, the formed hydrate must be broken or dissociated to set the lines free. One option is active heating, in which hot fluid is circulated to increase the temperature and break the hydrate ice structures. Consequently, a compact plant, with combined direct and indirect heating, was designed to deliver a customized solution for an offshore rig. Drill or salt water pumps were used to supply cold water at 12 bpm at 25 °C, and two steam generators were used to inject steam into the flow, mixing inline and delivering water at 49 °C at the mud tanks. This tank water was pumped through mud pumps at 12 bpm, passing through four steam heat exchangers (SHE) to deliver water at a final temperature of 90 °C. The total process used six steam generators and four SHE to heat water from 25 to 90 °C at 12 bpm. The compact design for the high flow rate injection plant was only possible with combined and independent processes. Direct heating by steam injection was used inline downstream from the drill water pump to preheat the water to 49 °C while feeding the mud tank. Indirect heating used four SHE downstream of the mud pump to deliver water at 90 °C at the seabed.
{"title":"Compact Hydrate Dissociation Plant: Combined Direct and Indirect Heating for Increased Efficiency","authors":"Romulo Margotto, Gabriel Franklin, Jeferson Cunha","doi":"10.4043/29928-ms","DOIUrl":"https://doi.org/10.4043/29928-ms","url":null,"abstract":"\u0000 Hydrate formation in production and control lines has been a serious issue in the oil industry, especially in the deepwater offshore market. This article focuses on a compact temporary plant designed to be assembled on offshore rigs for heating and injecting high flow rate water to break hydrates.\u0000 Hydrates are formed under determined conditions (high pressure at low temperature) in which natural gas hydrocarbon molecules are trapped in ice molecules, forming crystal structures and plugging or choking lines, causing operational problems. When preventive solutions, such as chemical inhibitors or thermal insulation, do not work, the formed hydrate must be broken or dissociated to set the lines free. One option is active heating, in which hot fluid is circulated to increase the temperature and break the hydrate ice structures. Consequently, a compact plant, with combined direct and indirect heating, was designed to deliver a customized solution for an offshore rig.\u0000 Drill or salt water pumps were used to supply cold water at 12 bpm at 25 °C, and two steam generators were used to inject steam into the flow, mixing inline and delivering water at 49 °C at the mud tanks. This tank water was pumped through mud pumps at 12 bpm, passing through four steam heat exchangers (SHE) to deliver water at a final temperature of 90 °C. The total process used six steam generators and four SHE to heat water from 25 to 90 °C at 12 bpm.\u0000 The compact design for the high flow rate injection plant was only possible with combined and independent processes. Direct heating by steam injection was used inline downstream from the drill water pump to preheat the water to 49 °C while feeding the mud tank. Indirect heating used four SHE downstream of the mud pump to deliver water at 90 °C at the seabed.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"233 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114230792","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}
Jin Fu, Xi Wang, Shunyuan Zhang, Bingshan Liu, Chen Chen, Guobin Yang
Marginal Oilfields are refered to as those oilfields that are hardly developed efficiently with current technical and ecomonical conditions, characterized as high costs of development and low profit margins. However, under certain economical and technical circumstances, marginal oilfields may be transferred to be conventional ones. Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin. CNPC signed a cooperation contract with Petrobras in 2013, taking 10% of the total shares. How to efficiently develop the oilfield has been a challenging issue. Technologies of smart water injection in Shengli Oilfield have been studied, while the field development and environment (deep water) of Libra Oilfield have been analyzed, in order that the smart water injection technologies may be modified to develop the marginal oilfield more efficiently. Different from conventional zonal water injection technologies, the remote wireless control water injection technologies take advantages of packers that are connected with each other via preset cables, which achieves downhole testing and water injection simultaneously. Being run via tubing, the water injection string locates a nozzle for each reservoir that is isolated by a packer. All nozzles are connected with packers via the preset cables that work as power lines for the whole string, so that downhole data such as pressures, flows and temperatures are all transferred to the processing computer on the surface. The computer program is used to convert pressure and formation signals into curves that are transferred to Company via WIFI or mobile 2G/3G/4G webs, in order that technicians there may understand and learn about downhole pressures, temperatures, flows and nozzle conditions in real time. They are able to open and close the nozzles totally or partially by giving orders that are transferred as signals via cables. In order to cope with offshore environment of Libra Oilfield in Santos Basin, pre-set cable packers have been modified accordingly, so that highly deviated wells may be developed with the smart water injection technologies. A field trial deployed in BM-C-33 Block Libra Oilfield shows that the modified smart water injection technologies are feasible for Libra Oilfield, as a novel solution to inject water in highly-deviated and horizontal wells in offshore oilfields.
{"title":"Research on Engineering Technologies to Develop China's Complex Reservoirs and their Feasibility in Development of Marginal Oilfields in South America","authors":"Jin Fu, Xi Wang, Shunyuan Zhang, Bingshan Liu, Chen Chen, Guobin Yang","doi":"10.4043/29956-ms","DOIUrl":"https://doi.org/10.4043/29956-ms","url":null,"abstract":"\u0000 Marginal Oilfields are refered to as those oilfields that are hardly developed efficiently with current technical and ecomonical conditions, characterized as high costs of development and low profit margins. However, under certain economical and technical circumstances, marginal oilfields may be transferred to be conventional ones. Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin. CNPC signed a cooperation contract with Petrobras in 2013, taking 10% of the total shares. How to efficiently develop the oilfield has been a challenging issue.\u0000 Technologies of smart water injection in Shengli Oilfield have been studied, while the field development and environment (deep water) of Libra Oilfield have been analyzed, in order that the smart water injection technologies may be modified to develop the marginal oilfield more efficiently.\u0000 Different from conventional zonal water injection technologies, the remote wireless control water injection technologies take advantages of packers that are connected with each other via preset cables, which achieves downhole testing and water injection simultaneously. Being run via tubing, the water injection string locates a nozzle for each reservoir that is isolated by a packer. All nozzles are connected with packers via the preset cables that work as power lines for the whole string, so that downhole data such as pressures, flows and temperatures are all transferred to the processing computer on the surface. The computer program is used to convert pressure and formation signals into curves that are transferred to Company via WIFI or mobile 2G/3G/4G webs, in order that technicians there may understand and learn about downhole pressures, temperatures, flows and nozzle conditions in real time. They are able to open and close the nozzles totally or partially by giving orders that are transferred as signals via cables. In order to cope with offshore environment of Libra Oilfield in Santos Basin, pre-set cable packers have been modified accordingly, so that highly deviated wells may be developed with the smart water injection technologies.\u0000 A field trial deployed in BM-C-33 Block Libra Oilfield shows that the modified smart water injection technologies are feasible for Libra Oilfield, as a novel solution to inject water in highly-deviated and horizontal wells in offshore oilfields.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"109 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114275105","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 work provides an immersive visualization of oil & gas relevant systems and enhanced oil recovery (EOR) processes at the nanoscale by coupling molecular dynamics (MD) simulations with gamming virtual reality (VR) technologies. The main objective is to understand oil/brine/rock interfaces at molecular level and identify the underlying EOR mechanisms at the atomic scale. Within this immersive experience, the user can directly interact and enhance its perception of atomic environment for EOR applications. The experiences cover nano-EOR, nano-IOR and low-salt processes at nanoscale based on MD calculations of nanoparticles at oil-brine interfaces, oil-brine at silica nanopores and calcite-brine-oil interfaces, respectively. The MD simulations are performed with the Lammps package. The visualizations were done with an HTC Vive and Oculus Rift virtual reality headsets with the Nomad VR and Unitymol software. For the Nomad VR, the trajectories are previously saved from a Lammps molecular dynamics simulation, whereas, for the Unitymol, the simulation with Lammps is performed on-the-fly through the iMD (interactive MD) plugin. The user can visualize and navigate through the trajectories using the Nomad VR. Furthermore, the Unitymol also allows the user apply forces on selected molecules on real time during the VR experience. As means of comparison, the visualization was also performed with cell-phone based VR headsets with the Nomad VR application. Our demonstrations show that VR combined with molecular simulations can be an interesting and attractive way to improve the perception of the nanoscale for the general public. Additionally, it is an emergent tool to characterize, improve the understanding and provide molecular insights about nanosystems and the EOR methods, and also to be integrated with on-going digitalization processes within the oil & gas industry.
{"title":"Virtual Reality for Visualization of Enhanced Oil Recovery Processes at Nanoscale","authors":"J. M. D. Almeida, C. R. Miranda","doi":"10.4043/29899-ms","DOIUrl":"https://doi.org/10.4043/29899-ms","url":null,"abstract":"\u0000 This work provides an immersive visualization of oil & gas relevant systems and enhanced oil recovery (EOR) processes at the nanoscale by coupling molecular dynamics (MD) simulations with gamming virtual reality (VR) technologies. The main objective is to understand oil/brine/rock interfaces at molecular level and identify the underlying EOR mechanisms at the atomic scale. Within this immersive experience, the user can directly interact and enhance its perception of atomic environment for EOR applications. The experiences cover nano-EOR, nano-IOR and low-salt processes at nanoscale based on MD calculations of nanoparticles at oil-brine interfaces, oil-brine at silica nanopores and calcite-brine-oil interfaces, respectively. The MD simulations are performed with the Lammps package. The visualizations were done with an HTC Vive and Oculus Rift virtual reality headsets with the Nomad VR and Unitymol software. For the Nomad VR, the trajectories are previously saved from a Lammps molecular dynamics simulation, whereas, for the Unitymol, the simulation with Lammps is performed on-the-fly through the iMD (interactive MD) plugin. The user can visualize and navigate through the trajectories using the Nomad VR. Furthermore, the Unitymol also allows the user apply forces on selected molecules on real time during the VR experience. As means of comparison, the visualization was also performed with cell-phone based VR headsets with the Nomad VR application. Our demonstrations show that VR combined with molecular simulations can be an interesting and attractive way to improve the perception of the nanoscale for the general public. Additionally, it is an emergent tool to characterize, improve the understanding and provide molecular insights about nanosystems and the EOR methods, and also to be integrated with on-going digitalization processes within the oil & gas industry.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116743987","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. Baumann, Raphael Pereira Scudino, M. Smart, Marcos Jun Tsuchie, E. Schnitzler, Roger Savoldi Roman
Perforating the extremely large deepwater wells in the Santos Basin fields, offshore Brazil, is done in a single-trip, shoot-and-pull operation, using 7.0-in. guns loaded with ultra-deep penetrating charges, which produce 65-in. of penetration depth per API RP 19B. These wells have 9-5/8-in. and 9-7/8-in. production casing with gross perforated lengths sometimes exceeding 600-m, and bottom hole pressures larger than 8,000-psi, in some cases reaching 13,500-psi. Perforating these wells with 7.0-in guns is very challenging because of the large downhole loads acting on the tubing string and on the drillship. To evaluate gunshock overloading risks, we utilize a simulation model to predict gunshock loads. This simulation model helps to assess the maximum loads for different perforating scenarios, and helps to devise strategies to reduce the peak tension on the tubing string and drillship to safe levels. Perforating shock loads are generated by the detonation of the guns and by the associated pressure waves in the completion fluid, such pressure waves act on the guns, tools, and tubing string. Shock loads can pose a serious risk of parting the tubing string and/or damaging the drillship's hoisting equipment. A fully coupled fluid-structure simulation model is used to predict perforating shock loads. Before every perforating job, the operator evaluates the peak transient loads on the tubing string and heave compensator, and decides on the best strategy to prevent gunshock-related damage. Many drillship operators believe that large-size gunstrings can damage the heave compensation system. Often, afraid of damaging the heave compensators, drillship operators opt for disabling the heave compensation system when perforating, and this is what can create unfavorable conditions that can lead to extremely high loads on the tubing-string. Computer simulation of the perforating event with models having varying degrees of heave compensation show the need for heave compensation to reduce the peak tension load on the tubing-string. Actual drillship measurements and simulation results of transient hook-load are presented side-by-side, as well as sensitivity studies of the transient tubing-load dependence on the heave compensator's load-movement relationship. Actual hook-load measurements from one perforating job done with heave compensation and one without heave compensation show the need to use heave compensation to reduce the peak tension load on the tubing-string. Gunshock loading simulations are described in detail, using actual jobs data to analyze the transient shock load on the tubing string and on the drillship. Detailed comparisons between simulated and measured peak drillship hook loads are presented, as well as the tubing axial load dependence on the heave compensator's load-movement relationship. This information will help operators to decide on the strategy to avoid having non-productive time because of shock related equipment damage.
巴西海上Santos盆地油田的超大型深水井射孔作业只需一次起下钻，使用7.0-in。装有超深穿甲弹的枪炮，能产生65英寸。按API RP 19B计算的穿透深度。这些井的尺寸为9-5/ 8in。和9-7/8-in。生产套管的总射孔长度有时超过600米，井底压力大于8000 psi，某些情况下达到13500 psi。使用7.0 in射孔枪对这些井进行射孔是非常具有挑战性的，因为对管柱和钻井船施加了很大的井下载荷。为了评估炮震超载风险，我们利用仿真模型来预测炮震载荷。该模拟模型有助于评估不同射孔场景下的最大载荷，并有助于制定策略，将管柱和钻井船的峰值张力降低到安全水平。射孔冲击载荷是由射孔枪的爆轰和完井液中相关的压力波产生的，这些压力波作用于射孔枪、工具和管柱。冲击载荷可能会造成管柱断裂和/或损坏钻井船的起重设备。采用全耦合流固耦合仿真模型预测射孔冲击载荷。在每次射孔作业之前，作业者都会评估管柱和升沉补偿器的峰值瞬态载荷，并确定防止炮震相关损坏的最佳策略。许多钻井船运营商认为，大尺寸的炮串会损坏升沉补偿系统。通常，由于担心损坏升沉补偿器，钻井船运营商在射孔时选择关闭升沉补偿系统，这可能会造成不利的条件，导致管柱承受极高的载荷。利用具有不同升沉补偿程度的模型对射孔过程进行了计算机模拟，结果表明需要进行升沉补偿以降低管柱的峰值张力载荷。同时给出了钻井船的实测数据和瞬态挂钩载荷的仿真结果，以及升沉补偿器载荷-运动关系对瞬态油管载荷依赖的敏感性研究。采用升沉补偿和不采用升沉补偿的射孔作业的实际钩载荷测量结果表明，需要使用升沉补偿来降低管柱的峰值张力载荷。详细描述了炮震载荷模拟，利用实际作业数据分析了管柱和钻井船上的瞬态冲击载荷。详细比较了模拟和实测的钻井船钩峰值载荷，以及油管轴向载荷与升沉补偿器载荷-运动关系的关系。这些信息将帮助作业者决定策略，以避免因与冲击相关的设备损坏而导致非生产时间。
{"title":"Perforating the Largest Deepwater Wells in Brazil - Minimizing Shock Loads","authors":"C. Baumann, Raphael Pereira Scudino, M. Smart, Marcos Jun Tsuchie, E. Schnitzler, Roger Savoldi Roman","doi":"10.4043/29914-ms","DOIUrl":"https://doi.org/10.4043/29914-ms","url":null,"abstract":"\u0000 Perforating the extremely large deepwater wells in the Santos Basin fields, offshore Brazil, is done in a single-trip, shoot-and-pull operation, using 7.0-in. guns loaded with ultra-deep penetrating charges, which produce 65-in. of penetration depth per API RP 19B. These wells have 9-5/8-in. and 9-7/8-in. production casing with gross perforated lengths sometimes exceeding 600-m, and bottom hole pressures larger than 8,000-psi, in some cases reaching 13,500-psi. Perforating these wells with 7.0-in guns is very challenging because of the large downhole loads acting on the tubing string and on the drillship. To evaluate gunshock overloading risks, we utilize a simulation model to predict gunshock loads. This simulation model helps to assess the maximum loads for different perforating scenarios, and helps to devise strategies to reduce the peak tension on the tubing string and drillship to safe levels.\u0000 Perforating shock loads are generated by the detonation of the guns and by the associated pressure waves in the completion fluid, such pressure waves act on the guns, tools, and tubing string. Shock loads can pose a serious risk of parting the tubing string and/or damaging the drillship's hoisting equipment. A fully coupled fluid-structure simulation model is used to predict perforating shock loads. Before every perforating job, the operator evaluates the peak transient loads on the tubing string and heave compensator, and decides on the best strategy to prevent gunshock-related damage.\u0000 Many drillship operators believe that large-size gunstrings can damage the heave compensation system. Often, afraid of damaging the heave compensators, drillship operators opt for disabling the heave compensation system when perforating, and this is what can create unfavorable conditions that can lead to extremely high loads on the tubing-string. Computer simulation of the perforating event with models having varying degrees of heave compensation show the need for heave compensation to reduce the peak tension load on the tubing-string. Actual drillship measurements and simulation results of transient hook-load are presented side-by-side, as well as sensitivity studies of the transient tubing-load dependence on the heave compensator's load-movement relationship. Actual hook-load measurements from one perforating job done with heave compensation and one without heave compensation show the need to use heave compensation to reduce the peak tension load on the tubing-string.\u0000 Gunshock loading simulations are described in detail, using actual jobs data to analyze the transient shock load on the tubing string and on the drillship. Detailed comparisons between simulated and measured peak drillship hook loads are presented, as well as the tubing axial load dependence on the heave compensator's load-movement relationship. This information will help operators to decide on the strategy to avoid having non-productive time because of shock related equipment damage.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116647393","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}
L. Lima, Nadege Bize-Forest, Alexandre Evsukoff, Renata Leonhardt
This paper proposes an unsupervised neural network model for facies pattern recognition and formation characterization using borehole images. The goal is to create an automated workflow for rock fabric identification using high resolution acoustic or electrical borehole images with the aim of supporting 3D geological modeling. The results are compared and validated with geological and petrophysical interpretation. Image-based facies recognition is challenging when applying Deep Learning techniques: 1/ the volume of released labeled data constrains the abilities to build a robust neural network model 2/ data classification itself is subject to geologist interpretation. Additionally, indirect measurements can bias data, hindering the correlation between log response and any particular classification. We propose, therefore, an application of a fully convolutional autoencoder for borehole image data clustering to extract the most representative information displayed by the images without relying on labeled data. The data set corresponds to electrical borehole images with high-resolution at 0.2in and 80% borehole coverage. First, we apply an autoencoder reconstruction loss for network pre-training, then a joint training using cluster assignment hardening. After training and applying the model, patterns represented by each cluster of geological facies or geomechanical features constitute a library that can be assigned by the user to specific facies or can be automatically correlated to the core description. The method provides pattern recognition and facies prediction with higher resolution and accuracy than conventional Machine Learning methods based on the clustering of petrophysical properties.
{"title":"Unsupervised Deep Learning for Facies Pattern Recognition on Borehole Images","authors":"L. Lima, Nadege Bize-Forest, Alexandre Evsukoff, Renata Leonhardt","doi":"10.4043/29726-ms","DOIUrl":"https://doi.org/10.4043/29726-ms","url":null,"abstract":"\u0000 This paper proposes an unsupervised neural network model for facies pattern recognition and formation characterization using borehole images. The goal is to create an automated workflow for rock fabric identification using high resolution acoustic or electrical borehole images with the aim of supporting 3D geological modeling. The results are compared and validated with geological and petrophysical interpretation.\u0000 Image-based facies recognition is challenging when applying Deep Learning techniques: 1/ the volume of released labeled data constrains the abilities to build a robust neural network model 2/ data classification itself is subject to geologist interpretation. Additionally, indirect measurements can bias data, hindering the correlation between log response and any particular classification.\u0000 We propose, therefore, an application of a fully convolutional autoencoder for borehole image data clustering to extract the most representative information displayed by the images without relying on labeled data.\u0000 The data set corresponds to electrical borehole images with high-resolution at 0.2in and 80% borehole coverage. First, we apply an autoencoder reconstruction loss for network pre-training, then a joint training using cluster assignment hardening. After training and applying the model, patterns represented by each cluster of geological facies or geomechanical features constitute a library that can be assigned by the user to specific facies or can be automatically correlated to the core description. The method provides pattern recognition and facies prediction with higher resolution and accuracy than conventional Machine Learning methods based on the clustering of petrophysical properties.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116663363","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}
Anders T. Sandnes, Vidar Thune Uglane, B. Grimstad
We present a data-driven root cause analysis of slug flow in a subsea field. The asset experienced severe slugging in a riser, which limited production throughput. The results were used in combination with simulator studies and engineering experience to create a better understanding of the underlying root cause for slugging. A selection of signals was investigated as possible drivers behind slug severity. Focus was put on well-specific signals such as pressures, temperatures and flow rates, in addition to total flow rates, pipeline pressures and temperatures, and settings on the topside facility. Total liquid rate, especially the water component, is isolated as an important driver for slugging, while ruling out other signals believed to be important before the analysis, such as production from individual wells. The results were aligned with the field engineers’ experience. Actions were implemented to reduce water production, and this led to reduced slugging. Close collaboration between data scientists and field engineers was essential to guide the search towards actionable evidence. The novelty of this approach lies in utilizing machine learning techniques to model and analyze historical production data in order to find drivers behind events such as slug flow. This makes it easier for field engineers to leverage all available information to optimize production.
{"title":"Slug Flow Root Cause Analysis: A Data-Driven Approach","authors":"Anders T. Sandnes, Vidar Thune Uglane, B. Grimstad","doi":"10.4043/29925-ms","DOIUrl":"https://doi.org/10.4043/29925-ms","url":null,"abstract":"\u0000 We present a data-driven root cause analysis of slug flow in a subsea field. The asset experienced severe slugging in a riser, which limited production throughput. The results were used in combination with simulator studies and engineering experience to create a better understanding of the underlying root cause for slugging.\u0000 A selection of signals was investigated as possible drivers behind slug severity. Focus was put on well-specific signals such as pressures, temperatures and flow rates, in addition to total flow rates, pipeline pressures and temperatures, and settings on the topside facility. Total liquid rate, especially the water component, is isolated as an important driver for slugging, while ruling out other signals believed to be important before the analysis, such as production from individual wells. The results were aligned with the field engineers’ experience. Actions were implemented to reduce water production, and this led to reduced slugging. Close collaboration between data scientists and field engineers was essential to guide the search towards actionable evidence.\u0000 The novelty of this approach lies in utilizing machine learning techniques to model and analyze historical production data in order to find drivers behind events such as slug flow. This makes it easier for field engineers to leverage all available information to optimize production.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125833675","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}
CO2-WAG (Water-Alternating-Gas) has been applied in offshore Brazilian oilfields to improve recovery rates and mitigate the environmental impact that venting produced CO2 would bring. Although CO2 is highly miscible in oil under these reservoirs conditions, this gas is also extremely mobile, and its speciation in the aqueous phase drives reactions with carbonates that can cause severe inorganic scaling problems in production systems. It is crucial, therefore, to effectively design CO2-WAG operations for mobility control and, consequently, enhance reservoir performance, CO2 utilization and flow assurance. This paper addresses the design optimization of coupled CO2-EOR and storage operations applied to the Brazilian Pre-salt offshore context (reservoir properties, infrastructure, regulatory framework and economic characteristics), examining the trade-offs of project profitability, CO2 utilization and calcite scale risk. Several compositional simulations of miscible WAG scenarios were performed and key design parameters were optimized using statistical sampling and evolutionary algorithms. Aqueous and mineral reactions were included in the calculations, allowing us to quantify the calcite mass that can potentially deposit in the perforations and production system. The results showed how optimizing WAG operations can significantly improve the economics and the scale management of oil production from carbonate reservoirs. The optimal WAG design greatly increased incremental NPV per volume of CO2 stored and reduced calcite scale risk by simply rearranging the WAG slugs in a tapered manner. Here we demonstrate that this methodology can be used to determine how to recycle CO2 in a given field for better economics and lower carbon footprint, doing so without triggering calcite mineral deposition to the point of permanent jeopardy of production wells and facilities operability. Therefore, the workflow integrates critical challenges that are correlated, yet often addressed independently, supporting the complex decision-making of CO2-EOR operational design in carbonate reservoirs.
{"title":"Optimization of CO-WAG and Calcite Scale Management in Pre-Salt Carbonate Reservoirs","authors":"H. Rodrigues, E. Mackay, D. Arnold, Duarte Silva","doi":"10.4043/29823-ms","DOIUrl":"https://doi.org/10.4043/29823-ms","url":null,"abstract":"\u0000 CO2-WAG (Water-Alternating-Gas) has been applied in offshore Brazilian oilfields to improve recovery rates and mitigate the environmental impact that venting produced CO2 would bring. Although CO2 is highly miscible in oil under these reservoirs conditions, this gas is also extremely mobile, and its speciation in the aqueous phase drives reactions with carbonates that can cause severe inorganic scaling problems in production systems. It is crucial, therefore, to effectively design CO2-WAG operations for mobility control and, consequently, enhance reservoir performance, CO2 utilization and flow assurance.\u0000 This paper addresses the design optimization of coupled CO2-EOR and storage operations applied to the Brazilian Pre-salt offshore context (reservoir properties, infrastructure, regulatory framework and economic characteristics), examining the trade-offs of project profitability, CO2 utilization and calcite scale risk. Several compositional simulations of miscible WAG scenarios were performed and key design parameters were optimized using statistical sampling and evolutionary algorithms. Aqueous and mineral reactions were included in the calculations, allowing us to quantify the calcite mass that can potentially deposit in the perforations and production system.\u0000 The results showed how optimizing WAG operations can significantly improve the economics and the scale management of oil production from carbonate reservoirs. The optimal WAG design greatly increased incremental NPV per volume of CO2 stored and reduced calcite scale risk by simply rearranging the WAG slugs in a tapered manner.\u0000 Here we demonstrate that this methodology can be used to determine how to recycle CO2 in a given field for better economics and lower carbon footprint, doing so without triggering calcite mineral deposition to the point of permanent jeopardy of production wells and facilities operability. Therefore, the workflow integrates critical challenges that are correlated, yet often addressed independently, supporting the complex decision-making of CO2-EOR operational design in carbonate reservoirs.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122113164","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}
Brazil is one of the most prominent oil and gas offshore market. Recently, investors’ interest has increased, but not only because of the oil price recovery and pre-salt discoveries, but maybe also because of important changes in the regulatory side. Several issues have been discussed by authorities with the industry: local content flexibilization, unitization agreements, multiple fiscal regimes (PSA, Concessions, and Transfer of Rights Agreements), Repetro customs regime, decommissioning regulations, among other topics. To understand this environment is important to look at the changes and the history since the beginning, besides the economic and political forces which influence the decisions. In addition, Brazil 2018 elections have changed the direction and perspectives for this important economic sector. In this paper, the authors describe the evolution of the regulation, the contract models and results of bid rounds in order to tracking the effects of the past decisions. It can help to find clues about which should be the next steps in terms of new regulations for the Brazilian market.
{"title":"Brazilian Regulatory Framework: From the Past to the Expectations About the Future","authors":"M. Bastos, Jorge Luiz Bastos","doi":"10.4043/29834-ms","DOIUrl":"https://doi.org/10.4043/29834-ms","url":null,"abstract":"\u0000 Brazil is one of the most prominent oil and gas offshore market. Recently, investors’ interest has increased, but not only because of the oil price recovery and pre-salt discoveries, but maybe also because of important changes in the regulatory side. Several issues have been discussed by authorities with the industry: local content flexibilization, unitization agreements, multiple fiscal regimes (PSA, Concessions, and Transfer of Rights Agreements), Repetro customs regime, decommissioning regulations, among other topics. To understand this environment is important to look at the changes and the history since the beginning, besides the economic and political forces which influence the decisions. In addition, Brazil 2018 elections have changed the direction and perspectives for this important economic sector. In this paper, the authors describe the evolution of the regulation, the contract models and results of bid rounds in order to tracking the effects of the past decisions. It can help to find clues about which should be the next steps in terms of new regulations for the Brazilian market.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134551059","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}
Kenneth Johnson, V. Okengwu, B. Orluwosu, Ryan Novelen, Jon-Howard Hanson, V. Chaloupka, A. Achich
The introductory use of existing inflow control devices (ICD’s) fitted with innovative dissolvable metal plugging rods to allow the operator to run washpipe free completions to reduce rig time is discussed. This work discusses an ICD washpipe-free application run in a long, deep water horizontal sandface completion in the Egina development. The completion was successfully installed following existing processes for tasks and sub-tasks applied in previous completions in the field. The washpipe-free solution was tailored to the reservoir, and is field-adjustable. The dissolvable plug solution was provided to be used with existing ICD’s available in country, without modification to the ICD housing. Fluid compatibility testing with dissolvable metals was performed establishing dissolution rates under existing reservoir conditions with mud, brine, and cake breaker at field formulations. Introduction of the dissolvable plug solution has provided the operator with an additional option to consider when seeking to further optimize times necessary to run lower completions in deep water wells offshore West Africa. No changes in existing completion procedures were necessary with respect to the procedure for washing down or subsequently placing cake breaker treatment. Running ICD’s with dissolvable plugs was identified as an opportunity to eliminate the need for running lower completion with washpipe. The subject well was run with ICD screens equipped with dissolvable plugs while maintaining full compatibility with the existing upper completion design. Once the well was completed and the tree installed, injectivity testing was successfully performed confirming ICD functionality was re-established. The ICD completion design saved the operator a minimum of 12 hours online rig time, further simplifying running the completion and associated handling times. Offline savings include (1) racking washpipe before running the lower completion, (2) subsequent racking back and laying washpipe upon completing the lower completion, (3) eliminating mobilization of washpipe to/from the rig, and (4) freeing up deck space typically used to accommodate the washpipe. During this saved offline time the auxiliary derrick could be used for other offline equipment preparation, helping provide further savings. Washpipe rental and maintenance costs were eliminated. An important reduction to safety risks related to extensive pipe handling was also achieved. This paper describes laboratory testing, full quality assurance/quality control (QA/QC) and operational procedures, leading to the first successful deployment and excellent functionality of ICD’s with dissolvable plugs in a long deep water horizontal completion eliminating the use of washpipe, while providing associated savings.
{"title":"Implementation of Dissolvable Metals to Isolate Inflow Control Devices and Deliver a Washpipe Free Deep Water Sandface Completion Solution","authors":"Kenneth Johnson, V. Okengwu, B. Orluwosu, Ryan Novelen, Jon-Howard Hanson, V. Chaloupka, A. Achich","doi":"10.4043/29705-ms","DOIUrl":"https://doi.org/10.4043/29705-ms","url":null,"abstract":"\u0000 The introductory use of existing inflow control devices (ICD’s) fitted with innovative dissolvable metal plugging rods to allow the operator to run washpipe free completions to reduce rig time is discussed. This work discusses an ICD washpipe-free application run in a long, deep water horizontal sandface completion in the Egina development. The completion was successfully installed following existing processes for tasks and sub-tasks applied in previous completions in the field. The washpipe-free solution was tailored to the reservoir, and is field-adjustable.\u0000 The dissolvable plug solution was provided to be used with existing ICD’s available in country, without modification to the ICD housing. Fluid compatibility testing with dissolvable metals was performed establishing dissolution rates under existing reservoir conditions with mud, brine, and cake breaker at field formulations. Introduction of the dissolvable plug solution has provided the operator with an additional option to consider when seeking to further optimize times necessary to run lower completions in deep water wells offshore West Africa. No changes in existing completion procedures were necessary with respect to the procedure for washing down or subsequently placing cake breaker treatment.\u0000 Running ICD’s with dissolvable plugs was identified as an opportunity to eliminate the need for running lower completion with washpipe. The subject well was run with ICD screens equipped with dissolvable plugs while maintaining full compatibility with the existing upper completion design. Once the well was completed and the tree installed, injectivity testing was successfully performed confirming ICD functionality was re-established.\u0000 The ICD completion design saved the operator a minimum of 12 hours online rig time, further simplifying running the completion and associated handling times. Offline savings include (1) racking washpipe before running the lower completion, (2) subsequent racking back and laying washpipe upon completing the lower completion, (3) eliminating mobilization of washpipe to/from the rig, and (4) freeing up deck space typically used to accommodate the washpipe. During this saved offline time the auxiliary derrick could be used for other offline equipment preparation, helping provide further savings. Washpipe rental and maintenance costs were eliminated. An important reduction to safety risks related to extensive pipe handling was also achieved.\u0000 This paper describes laboratory testing, full quality assurance/quality control (QA/QC) and operational procedures, leading to the first successful deployment and excellent functionality of ICD’s with dissolvable plugs in a long deep water horizontal completion eliminating the use of washpipe, while providing associated savings.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125264897","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}
R. Freitas, L. Rossi, A. Gregatti, F. Moretti, L. Pagani
Drilling the Marlim field at the Campos Basin has shown quite a challenge in the last few years. The field is located 110 km from Sao Tome cape at the north coast of Rio de Janeiro State, at the Campos Basin, have started commercial exploration for in 1991 and with water depths varying between 600 to 1000 m. The reservoir is composed of sandstone formation and just recently, an exploratory campaign at the field surroundings. The project of the well in the Marlim field was always complex with eight phases predicted. For the phase 4, due to the narrow fracture and pore pressure window, and also the high number of potential flow zones to be isolated, the client has decided to run a 13 5/8" stage collar in order to isolate all sandstone formations and cement the combined 14" × 13 5/8" Intermediate Casing. The idea of using the stage collar was to isolate the water holder formation, Carapebus Lambrusco sandstone, located just at the stage collar depth and then open the stage collar and cement the remaining sandstone all the way to the last water holder formation, Carapebus Marlim sandstone. The other objective of this job was to provide enough integrity to the shoe, set at the salt formation, in order to allow drilling the subsequent 14 ¾"open hole all the way to the carbonate formation. After drilled the 16 1/2" open hole of an offshore well, the intermediate casing had to be cemented with a two stage collar with sub sea release plug set, to bring the top of cement higher and isolate upper formation. Due to operational issues, there was a failure in the first stage cement job, which was confirmed with a failed formation integrity test - necessary 13.0 lb/gal to drill ahead the subsequent 14 3/4" phase. To solve the issue, to achieve formation integrity test of 13 lb/gal, it was necessary to perform a Casing Shoe Squeeze Cement job. The problem is that historically those intervals experience very narrow gaps, which means low injectivity. After several failed attempts with conventional cement, a novel technology was used combining microcement with a strong fluid loss control that could enable the cement to be injected into narrow gaps. The use of microcement alone provides rapid compressive strength development, very low rheology and combining with a fluid loss additive enables to provide the system with very high injectivity
{"title":"Case Study: Brazil Deepwater, Pre-Salt – Successful Intermediate Casing Shoe Squeeze Using Microcement","authors":"R. Freitas, L. Rossi, A. Gregatti, F. Moretti, L. Pagani","doi":"10.4043/29833-ms","DOIUrl":"https://doi.org/10.4043/29833-ms","url":null,"abstract":"\u0000 Drilling the Marlim field at the Campos Basin has shown quite a challenge in the last few years. The field is located 110 km from Sao Tome cape at the north coast of Rio de Janeiro State, at the Campos Basin, have started commercial exploration for in 1991 and with water depths varying between 600 to 1000 m. The reservoir is composed of sandstone formation and just recently, an exploratory campaign at the field surroundings.\u0000 The project of the well in the Marlim field was always complex with eight phases predicted. For the phase 4, due to the narrow fracture and pore pressure window, and also the high number of potential flow zones to be isolated, the client has decided to run a 13 5/8\" stage collar in order to isolate all sandstone formations and cement the combined 14\" × 13 5/8\" Intermediate Casing. The idea of using the stage collar was to isolate the water holder formation, Carapebus Lambrusco sandstone, located just at the stage collar depth and then open the stage collar and cement the remaining sandstone all the way to the last water holder formation, Carapebus Marlim sandstone. The other objective of this job was to provide enough integrity to the shoe, set at the salt formation, in order to allow drilling the subsequent 14 ¾\"open hole all the way to the carbonate formation.\u0000 After drilled the 16 1/2\" open hole of an offshore well, the intermediate casing had to be cemented with a two stage collar with sub sea release plug set, to bring the top of cement higher and isolate upper formation. Due to operational issues, there was a failure in the first stage cement job, which was confirmed with a failed formation integrity test - necessary 13.0 lb/gal to drill ahead the subsequent 14 3/4\" phase.\u0000 To solve the issue, to achieve formation integrity test of 13 lb/gal, it was necessary to perform a Casing Shoe Squeeze Cement job. The problem is that historically those intervals experience very narrow gaps, which means low injectivity. After several failed attempts with conventional cement, a novel technology was used combining microcement with a strong fluid loss control that could enable the cement to be injected into narrow gaps. The use of microcement alone provides rapid compressive strength development, very low rheology and combining with a fluid loss additive enables to provide the system with very high injectivity","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126689667","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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