T. Borges, J. V. Vargas, E. Koroishi, Nilo Kim, O. V. Trevisan, G. S. Bassani
The low salinity water injection (LSWI) is one of the most studied techniques applied to enhanced oil recovery (EOR) from carbonates reservoirs. Wettability alteration and dissolution reaction are mechanisms that support the understanding of this technique. However, the dissolution behavior of Brazilian pre-salt carbonates rocks when treated by LSWI is not yet known. Therefore, the purpose of this work is to evaluate the dissolution effects provided by low salinity water injection in carbonate rocks from a Brazilian pre-salt reservoir using two different injection flow rates in core flooding tests at reservoir conditions. Porosity variation along the length was determined by Computerized Tomography scan analysis. Permeability was determined through pressure drop data. Ions identification and concentration were determined by ions chromatography. The experiments consisted in carrying out two core flooding tests assembled in series at 8100 psi of injection pressure and 65°C. It was performed two different injection flow rates (1 mL/min and 0.1 mL/min) of 16 times diluted synthetic seawater. It was possible to observe three different porosity behaviors along the sample length in both flow rates tested and for both core holder samples. However, the porosity behavior intensity is different from each case. There are regions of predictable behavior, regions of random behavior and inert regions. According to the porosity plots, the sample from the second core holder of the series presented more interaction with the injection fluid. Probably, the mineralogical heterogeneity has influenced in the dissolution phenomenon. The permeability profile remained almost constant for both samples. The ion chromatography analysis revealed a huge variation of magnesium and calcium ions concentration in the first injected porous volume and, subsequently, a constant trend towards the base-line values.
{"title":"Dissolution Behavior of Carbonate Rocks from Brazilian Pre-Salt at Reservoir Conditions by LSWI","authors":"T. Borges, J. V. Vargas, E. Koroishi, Nilo Kim, O. V. Trevisan, G. S. Bassani","doi":"10.4043/29856-ms","DOIUrl":"https://doi.org/10.4043/29856-ms","url":null,"abstract":"\u0000 The low salinity water injection (LSWI) is one of the most studied techniques applied to enhanced oil recovery (EOR) from carbonates reservoirs. Wettability alteration and dissolution reaction are mechanisms that support the understanding of this technique. However, the dissolution behavior of Brazilian pre-salt carbonates rocks when treated by LSWI is not yet known. Therefore, the purpose of this work is to evaluate the dissolution effects provided by low salinity water injection in carbonate rocks from a Brazilian pre-salt reservoir using two different injection flow rates in core flooding tests at reservoir conditions. Porosity variation along the length was determined by Computerized Tomography scan analysis. Permeability was determined through pressure drop data. Ions identification and concentration were determined by ions chromatography. The experiments consisted in carrying out two core flooding tests assembled in series at 8100 psi of injection pressure and 65°C. It was performed two different injection flow rates (1 mL/min and 0.1 mL/min) of 16 times diluted synthetic seawater. It was possible to observe three different porosity behaviors along the sample length in both flow rates tested and for both core holder samples. However, the porosity behavior intensity is different from each case. There are regions of predictable behavior, regions of random behavior and inert regions. According to the porosity plots, the sample from the second core holder of the series presented more interaction with the injection fluid. Probably, the mineralogical heterogeneity has influenced in the dissolution phenomenon. The permeability profile remained almost constant for both samples. The ion chromatography analysis revealed a huge variation of magnesium and calcium ions concentration in the first injected porous volume and, subsequently, a constant trend towards the base-line values.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"319 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":"124289572","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}
B. Cavalcante, P. Rocha, M. Santos, A. Tavares, S. J. A. Neto, Joao Siqueira Matos, M. Marsili
Most of the artificial lift strategies in deepwater environments require sophisticated and robust solutions, aiming to improve the system's run life and reliability. Due to that, oil companies choose only trustable technology and field-proven solutions for artificial lift design. This is the case of Atlanta Field's artificial lift project, with electrical submersible pumps (ESP) installed at more than 1,550 m water depth, to produce heavy oil. For Atlanta Field, the ESP must handle high viscous oil and emulsions at high flow rates to be economically feasible. To achieve this goal, it was deployed one of the most powerful ESP in the world with 1,550 HP induction motor and more than one hundred pump stages into the well. This is the largest ESP in-well successfully installed in Brazil. The artificial lift strategy adopted for Atlanta Field was an in-well ESP as primary method and an artificial lift skid (ALS) installed on the seabed for back-up. When the primary method fails, there is no in-well ESP replacement, because of high costs involved with workover and the back-up system becomes the main one. When the back-up system fails, the replacement of the pumping module is done by an AHTS equipped with active compensate crane for subsea installation. In this way, replacement costs are much lower than those needed to replace pumps inside the wells. So far, this artificial lift strategy has proven to be reliable and project results will be discussed in this paper. Strategies to optimize production will be addressed and observations regarding free gas ESP pumping will be made. After a period producing, the in-well ESP have failed, and the ALS became the main system to produce both wells, as planned. The project faced some challenges with ALS operation, since there was an expressive flow restriction in the in-well ESP. Experimental tests were permeformed to better determine the pressure drop caused by the flow through the pump stages and to propose a solution to the production restriction. By-pass valves were adopted in the project to avoid the mentioned issue. The well ATL-4 was drilled in March 2019. As this operation requires a drill ship, it was decided to perform workovers in wells ATL-2 and ATL-3 to replace the in-well ESPs and install the by-pass valves in the well's production string.
{"title":"Robust Artificial Lift Solution for Ultra-Deepwater Heavy Oil Atlanta Field","authors":"B. Cavalcante, P. Rocha, M. Santos, A. Tavares, S. J. A. Neto, Joao Siqueira Matos, M. Marsili","doi":"10.4043/29828-ms","DOIUrl":"https://doi.org/10.4043/29828-ms","url":null,"abstract":"\u0000 Most of the artificial lift strategies in deepwater environments require sophisticated and robust solutions, aiming to improve the system's run life and reliability. Due to that, oil companies choose only trustable technology and field-proven solutions for artificial lift design. This is the case of Atlanta Field's artificial lift project, with electrical submersible pumps (ESP) installed at more than 1,550 m water depth, to produce heavy oil.\u0000 For Atlanta Field, the ESP must handle high viscous oil and emulsions at high flow rates to be economically feasible. To achieve this goal, it was deployed one of the most powerful ESP in the world with 1,550 HP induction motor and more than one hundred pump stages into the well. This is the largest ESP in-well successfully installed in Brazil.\u0000 The artificial lift strategy adopted for Atlanta Field was an in-well ESP as primary method and an artificial lift skid (ALS) installed on the seabed for back-up. When the primary method fails, there is no in-well ESP replacement, because of high costs involved with workover and the back-up system becomes the main one. When the back-up system fails, the replacement of the pumping module is done by an AHTS equipped with active compensate crane for subsea installation. In this way, replacement costs are much lower than those needed to replace pumps inside the wells.\u0000 So far, this artificial lift strategy has proven to be reliable and project results will be discussed in this paper. Strategies to optimize production will be addressed and observations regarding free gas ESP pumping will be made.\u0000 After a period producing, the in-well ESP have failed, and the ALS became the main system to produce both wells, as planned. The project faced some challenges with ALS operation, since there was an expressive flow restriction in the in-well ESP. Experimental tests were permeformed to better determine the pressure drop caused by the flow through the pump stages and to propose a solution to the production restriction. By-pass valves were adopted in the project to avoid the mentioned issue.\u0000 The well ATL-4 was drilled in March 2019. As this operation requires a drill ship, it was decided to perform workovers in wells ATL-2 and ATL-3 to replace the in-well ESPs and install the by-pass valves in the well's production string.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"15 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":"124649094","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}
I. Petri, A. C. S. Mota, V. Barbosa, A. Martins, C. D. Sá, M. S. Pereira, C. Ataíde
The disposal of drill cuttings in offshore operations has become a critical issue considering the increasing restrictions imposed by environmental legislation. When reservoir formations are reached in the drilling phase, cuttings contaminated with both drilling fluid and crude oil return to surface. Due to the presence of oil, which may contain toxic and non-biodegradable pollutants like polyaromatic hydrocarbons, specific discharde restrictions are usually applied. In this scope, microwave drying is proposed as a treatment method for drill cuttings contaminated with petroleum. In other words, this work aims to show how microwave drying technology can be a promising alternative in the treatment of drill cuttings originated from oil and gas reservoirs. First, a set of published results that reinforce the use of this technology in the drying of cuttings is presented. Then, a set of experiments that evaluated the efficiency of microwave drying of drill cuttings contaminated with petroleum of different API gravity was carried out. As expected, the microwave treatment of cuttings contaminated with light gravity oil presented lower residual contents than the heavy oil ones once light oil samples contain lighter hydrocarbons, which present lower boiling temperatures. Additionally, the remediation of oil-contaminated cuttings was promising, showing that it was possible to reach residual oil contents under 1% in mass after applying specific energies around 1.15 kWh/kg.
{"title":"Microwave Drying of Reservoir Drilled Cuttings","authors":"I. Petri, A. C. S. Mota, V. Barbosa, A. Martins, C. D. Sá, M. S. Pereira, C. Ataíde","doi":"10.4043/29964-ms","DOIUrl":"https://doi.org/10.4043/29964-ms","url":null,"abstract":"\u0000 The disposal of drill cuttings in offshore operations has become a critical issue considering the increasing restrictions imposed by environmental legislation. When reservoir formations are reached in the drilling phase, cuttings contaminated with both drilling fluid and crude oil return to surface. Due to the presence of oil, which may contain toxic and non-biodegradable pollutants like polyaromatic hydrocarbons, specific discharde restrictions are usually applied. In this scope, microwave drying is proposed as a treatment method for drill cuttings contaminated with petroleum. In other words, this work aims to show how microwave drying technology can be a promising alternative in the treatment of drill cuttings originated from oil and gas reservoirs. First, a set of published results that reinforce the use of this technology in the drying of cuttings is presented. Then, a set of experiments that evaluated the efficiency of microwave drying of drill cuttings contaminated with petroleum of different API gravity was carried out. As expected, the microwave treatment of cuttings contaminated with light gravity oil presented lower residual contents than the heavy oil ones once light oil samples contain lighter hydrocarbons, which present lower boiling temperatures. Additionally, the remediation of oil-contaminated cuttings was promising, showing that it was possible to reach residual oil contents under 1% in mass after applying specific energies around 1.15 kWh/kg.","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":"121466128","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The scale and productive life of associated gas from subsalt production and small offshore gas reservoirs in remote areas, has made economic justification difficult for dedicated onshore processing facilities with associated subsea pipelines. Floating LNG (FLNG) offer freedom from the subsea pipeline, but the biggest have been designed for specific large fields. Another approach is to build flexibility into the design of the FLNG facility, potentially increasing the initial CAPEX of the unit, instead of targeting a specific field. This approach allows the CAPEX to be amortized across multiple offshore fields, avoiding a stranded investment. This paper addresses topsides where flexibility in topsides processing units is advantageous for pursuit of multiple marginal fields over the life of the FLNG asset, focusing on the 4.5 to 9 MSm3/day (160 to 330 MMSCFD) of natural gas liquefied to 1 to 2 million tonnes per annum of LNG. Standardizing modular designs for FLNG processing units, provides opportunities to build or retrofit the FLNG facility in smaller yards and can reduce project schedule and costs associated with the design and construction of the FLNG facility. Considering future relocation of the floating unit to other fields, requires some flexibility in the initial design to reduce future changes, without negatively impacting first field performance. Using this approach, producing gas from marginal offshore fields could be a viable option by utilizing small or mid-scale FLNG to liquefy gas, using one facility to liquefy serially multiple marginal fields.
{"title":"Mid-Scale FLNG Production Unit for Marginal Fields","authors":"K. Tierling, M. Mahdavian","doi":"10.4043/29827-ms","DOIUrl":"https://doi.org/10.4043/29827-ms","url":null,"abstract":"\u0000 The scale and productive life of associated gas from subsalt production and small offshore gas reservoirs in remote areas, has made economic justification difficult for dedicated onshore processing facilities with associated subsea pipelines. Floating LNG (FLNG) offer freedom from the subsea pipeline, but the biggest have been designed for specific large fields.\u0000 Another approach is to build flexibility into the design of the FLNG facility, potentially increasing the initial CAPEX of the unit, instead of targeting a specific field. This approach allows the CAPEX to be amortized across multiple offshore fields, avoiding a stranded investment.\u0000 This paper addresses topsides where flexibility in topsides processing units is advantageous for pursuit of multiple marginal fields over the life of the FLNG asset, focusing on the 4.5 to 9 MSm3/day (160 to 330 MMSCFD) of natural gas liquefied to 1 to 2 million tonnes per annum of LNG.\u0000 Standardizing modular designs for FLNG processing units, provides opportunities to build or retrofit the FLNG facility in smaller yards and can reduce project schedule and costs associated with the design and construction of the FLNG facility. Considering future relocation of the floating unit to other fields, requires some flexibility in the initial design to reduce future changes, without negatively impacting first field performance.\u0000 Using this approach, producing gas from marginal offshore fields could be a viable option by utilizing small or mid-scale FLNG to liquefy gas, using one facility to liquefy serially multiple marginal fields.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"9 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":"132784840","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}
Luan Rios Campos, P. Nogueira, E. G. S. Nascimento
Different parameters of a fully convolutional network (FCN) are experimented to evaluate which combination predicts sound velocity models from a single configuration of seismic modeling. The evaluation is made considering some fixed parameters of the deep learning model, such as number of epochs, batch size and loss function, but with variations of the optimizer and activation function. The considered optimizers were RMSprop, Adam and Adamax, whilst the activations functions were the Rectified Linear Unit (ReLU), Leaky ReLU, Exponential Linear Unit (ELU) and Parametric ReLU (PReLU). Five metrics were used to evaluate the model during the testing stage: R2, Pearson's r, factor of two, mean absolute error and mean squared error. To the extent of these experiments, it was found that the optimizers have much more influence than the activation functions when determining the resolution of the output model. The best combination was the one using the PReLU activation function with the Adamax optimizer.
{"title":"Tuning a Fully Convolutional Network for Velocity Model Estimation","authors":"Luan Rios Campos, P. Nogueira, E. G. S. Nascimento","doi":"10.4043/29904-ms","DOIUrl":"https://doi.org/10.4043/29904-ms","url":null,"abstract":"\u0000 Different parameters of a fully convolutional network (FCN) are experimented to evaluate which combination predicts sound velocity models from a single configuration of seismic modeling. The evaluation is made considering some fixed parameters of the deep learning model, such as number of epochs, batch size and loss function, but with variations of the optimizer and activation function. The considered optimizers were RMSprop, Adam and Adamax, whilst the activations functions were the Rectified Linear Unit (ReLU), Leaky ReLU, Exponential Linear Unit (ELU) and Parametric ReLU (PReLU). Five metrics were used to evaluate the model during the testing stage: R2, Pearson's r, factor of two, mean absolute error and mean squared error. To the extent of these experiments, it was found that the optimizers have much more influence than the activation functions when determining the resolution of the output model. The best combination was the one using the PReLU activation function with the Adamax optimizer.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"190 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":"116401875","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}
Typical ship-like floating bodies, for certain operating conditions, may experience large slamming loads in the bow or aft parts of the vessel. In addition to the local structural damages induced by slamming, a significant global hull vibration might also be excited. This vibratory response, referred to as whipping phenomenon, is usually not considered in the offshore industry, in particular in the design of ship shaped FPSOs. However, in case of resonance with slender structures such as the flare tower, these effects can have a strong influence on the fatigue performance at the interface between the FPSO’s hull and those structures. The objective of the work presented in this paper is to assess the influence of these effects on the total fatigue damage. Numerical modelling of whipping is extremely complex from several aspects and only approximate models exist today. For this study, a state of the art whipping model is used, which couples the hydrodynamic loads (linear diffraction and radiation, nonlinear incident and slamming) with dynamic structural response of the floating body. The hydrodynamic part of the model includes a weakly nonlinear diffraction-radiation tool which is supplemented by a modified Logvinovich model for slamming. These hydrodynamic models are fully coupled with the structural vessel dynamics which are represented by a simplified finite element model. Direct assessment of hot spot stresses are performed on refined fatigue models. Typical FPSO’s design includes the flare tower installed in the fore part, where the accelerations induced by the hull girder global vibrations are the highest. If the natural frequency of the flare tower is close to the natural frequency of the hull girder, significant flare vibrations might occur. In addition, spread moored FPSOs receive wave loads from 360 degrees and since typical FPSOs’ hull shape is similar to oil tankers’ hull shape, its stern flare is relatively larger flare than its bow flare. If waves come from the stern and FPSO’s draft is shallow, hull vibration induced by stern slamming might be large. The present work evaluates the influence of these vibrations on the flare tower structural response. The deterministic results are used within a dedicated methodology allowing for the evaluation of fatigue life of the structural details. This work proposes an innovative methodology for including the influence of highly nonlinear loads, such as slamming induced whipping, in the structural fatigue assessment of offshore structures.
{"title":"Influence of Whipping on the Structural Response of the Flare Tower Foundations of a Typical Spread Moored FPSO","authors":"A. Benhamou, J. Shimazaki, Fabrice Bontemps","doi":"10.4043/29865-ms","DOIUrl":"https://doi.org/10.4043/29865-ms","url":null,"abstract":"\u0000 Typical ship-like floating bodies, for certain operating conditions, may experience large slamming loads in the bow or aft parts of the vessel. In addition to the local structural damages induced by slamming, a significant global hull vibration might also be excited. This vibratory response, referred to as whipping phenomenon, is usually not considered in the offshore industry, in particular in the design of ship shaped FPSOs. However, in case of resonance with slender structures such as the flare tower, these effects can have a strong influence on the fatigue performance at the interface between the FPSO’s hull and those structures. The objective of the work presented in this paper is to assess the influence of these effects on the total fatigue damage.\u0000 Numerical modelling of whipping is extremely complex from several aspects and only approximate models exist today. For this study, a state of the art whipping model is used, which couples the hydrodynamic loads (linear diffraction and radiation, nonlinear incident and slamming) with dynamic structural response of the floating body. The hydrodynamic part of the model includes a weakly nonlinear diffraction-radiation tool which is supplemented by a modified Logvinovich model for slamming. These hydrodynamic models are fully coupled with the structural vessel dynamics which are represented by a simplified finite element model. Direct assessment of hot spot stresses are performed on refined fatigue models.\u0000 Typical FPSO’s design includes the flare tower installed in the fore part, where the accelerations induced by the hull girder global vibrations are the highest. If the natural frequency of the flare tower is close to the natural frequency of the hull girder, significant flare vibrations might occur. In addition, spread moored FPSOs receive wave loads from 360 degrees and since typical FPSOs’ hull shape is similar to oil tankers’ hull shape, its stern flare is relatively larger flare than its bow flare. If waves come from the stern and FPSO’s draft is shallow, hull vibration induced by stern slamming might be large. The present work evaluates the influence of these vibrations on the flare tower structural response. The deterministic results are used within a dedicated methodology allowing for the evaluation of fatigue life of the structural details.\u0000 This work proposes an innovative methodology for including the influence of highly nonlinear loads, such as slamming induced whipping, in the structural fatigue assessment of offshore structures.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"179 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":"116446440","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}
During offshore drilling operations, the disposal of drill cuttings and associated residual drilling fluid is determined by regulatory constraints, which are usually based on environmental risk. The environmental risk of drill cuttings disposal options is influenced strongly by the location of the well, the level of residual drilling fluid, and the type of drilling fluid. The International Association of Oil & Gas Producers (IOGP) has divided drilling base fluids into water-based drilling fluids (WBDFs) and non-aqueous drilling fluids (NADFs), which are categorized as Group I: High Aromatic Content, Group II: Medium Aromatic Content, and Group III: Low/Negligible Aromatic Content. Group III fluids encompass many types of fluids with low or undetectable levels of aromatic, including olefins, synthetic paraffins, and enhanced mineral oils. Laboratory testing and post-drilling environmental surveys clearly show the difference between WBDFs, Group I and Group III NADFs. However, despite laboratory studies differentiating the various Group III fluids, this differentiation is not clearly observable in single-well environmental monitoring studies. The objectives of this research are (1) to model the environmental risk from offshore drill cuttings discharge with several different Group III drilling base fluids, (2) to determine the impact of formation oil on the calculated environmental risk, and (3) to assess the use of modeling to differentiate drilling base fluids. In this project, DREAM (Dose-related Risk and Effect Assessment Model) was used to simulate the environmental risk from drill cuttings discharge with different drilling base fluids under identical discharge conditions of bore hole diameter, retention on cuttings (ROC), particle size distribution, current, etc. The drilling fluids modeled are: diesel (Group I), four Group III fluids (internal olefin, two enhanced mineral oils, and a synthetic paraffin), and water-based fluid (WBDF), as well as formation oil on cuttings. Benthic environmental risk is quantified using four factors that potentially impact sediment organisms: chemical stress (toxicity), burial, change in sediment grain size, and oxygen depletion due to biodegradation of chemicals present in the drilling base fluid. The modeling results presented in this paper support the differentiation between different drilling fluids and provides insight into the primary drivers of risk. For all fluids, grain size and burial posed small risk in this modeling scenario. As expected, the largest risk was predicted for diesel based on chemical toxicity while the smallest was for WBDF. Most WBDF toxicity impacts are in the water column and not the sediment. Group III NADFs, except for one enhanced mineral oil, had similar risk, but the main risk contributors were different. For the enhanced mineral oils and synthetic paraffin, chemical toxicity influenced overall risk; internal olefins did not exert risk from chemical toxicity. For all Group I
在海上钻井作业中，钻屑和相关残余钻井液的处置取决于监管约束，这通常是基于环境风险。钻屑处理方案的环境风险很大程度上受井位、残留钻井液水平和钻井液类型的影响。国际石油和天然气生产商协会(IOGP)将钻井基液分为水基钻井液(WBDFs)和非水基钻井液(NADFs)，分别为一类:高芳烃含量，二类:中等芳烃含量，三类:低芳烃含量。第三类流体包括许多类型的流体，其芳烃含量很低或检测不到，包括烯烃、合成石蜡和增强矿物油。实验室测试和钻后环境调查清楚地显示了wbdf、I组和III组nadf之间的差异。然而，尽管实验室研究区分了各种III类流体，但在单井环境监测研究中并不能清楚地观察到这种区分。本研究的目的是:(1)用几种不同的III类钻井基液对海上钻井岩屑排放的环境风险进行建模，(2)确定地层油对计算的环境风险的影响，(3)评估建模在区分钻井基液方面的应用。本项目采用DREAM (Dose-related Risk and Effect Assessment Model，剂量相关风险与效应评估模型)，模拟了在相同井筒直径、岩屑滞留量(ROC)、粒径分布、电流等排放条件下，不同钻井基液排放岩屑的环境风险。模拟的钻井液包括:柴油(第一类)、四种第三类流体(内部烯烃、两种增强型矿物油和一种合成石蜡)、水基流体(WBDF)以及岩屑上的地层油。底栖生物环境风险是通过四个可能影响沉积物生物的因素来量化的:化学压力(毒性)、埋藏、沉积物粒度的变化，以及由于钻井基液中化学物质的生物降解而导致的氧气消耗。本文中提出的建模结果支持对不同钻井液的区分，并提供了对风险主要驱动因素的洞察。对于所有流体，颗粒大小和埋藏在该建模情景中构成的风险很小。正如预期的那样，根据化学毒性预测柴油的风险最大，而WBDF的风险最小。大多数WBDF毒性影响是在水柱而不是沉积物中。除一种增强型矿物油外，第三组nadf具有相似的风险，但主要风险因素不同。对于增强型矿物油和合成石蜡，化学毒性影响总体风险;内部烯烃没有化学毒性风险。对于所有III类nadf，排放物质造成环境风险的主要因素是基液中有机负荷降解导致的氧气消耗，可生物降解的III类液体越多，预计风险就越高。这种较高的预测风险评估与环境调查结果背道而驰。DREAM的一个缺点是无法适应厌氧生物降解，这导致预测的污染时间很长，与环境监测结果不符。虽然DREAM用于比较流体，但模型的输出应在现有环境研究和操作人员经验的背景下进行评估。
{"title":"Modeled Environmental Risk of Offshore Drill Cuttings Discharges with Different Drilling Base Fluids","authors":"D. Lyon, M. Smit, Burnell Lee, B. Conley","doi":"10.4043/29835-ms","DOIUrl":"https://doi.org/10.4043/29835-ms","url":null,"abstract":"\u0000 During offshore drilling operations, the disposal of drill cuttings and associated residual drilling fluid is determined by regulatory constraints, which are usually based on environmental risk. The environmental risk of drill cuttings disposal options is influenced strongly by the location of the well, the level of residual drilling fluid, and the type of drilling fluid. The International Association of Oil & Gas Producers (IOGP) has divided drilling base fluids into water-based drilling fluids (WBDFs) and non-aqueous drilling fluids (NADFs), which are categorized as Group I: High Aromatic Content, Group II: Medium Aromatic Content, and Group III: Low/Negligible Aromatic Content. Group III fluids encompass many types of fluids with low or undetectable levels of aromatic, including olefins, synthetic paraffins, and enhanced mineral oils. Laboratory testing and post-drilling environmental surveys clearly show the difference between WBDFs, Group I and Group III NADFs. However, despite laboratory studies differentiating the various Group III fluids, this differentiation is not clearly observable in single-well environmental monitoring studies. The objectives of this research are (1) to model the environmental risk from offshore drill cuttings discharge with several different Group III drilling base fluids, (2) to determine the impact of formation oil on the calculated environmental risk, and (3) to assess the use of modeling to differentiate drilling base fluids.\u0000 In this project, DREAM (Dose-related Risk and Effect Assessment Model) was used to simulate the environmental risk from drill cuttings discharge with different drilling base fluids under identical discharge conditions of bore hole diameter, retention on cuttings (ROC), particle size distribution, current, etc. The drilling fluids modeled are: diesel (Group I), four Group III fluids (internal olefin, two enhanced mineral oils, and a synthetic paraffin), and water-based fluid (WBDF), as well as formation oil on cuttings. Benthic environmental risk is quantified using four factors that potentially impact sediment organisms: chemical stress (toxicity), burial, change in sediment grain size, and oxygen depletion due to biodegradation of chemicals present in the drilling base fluid.\u0000 The modeling results presented in this paper support the differentiation between different drilling fluids and provides insight into the primary drivers of risk. For all fluids, grain size and burial posed small risk in this modeling scenario. As expected, the largest risk was predicted for diesel based on chemical toxicity while the smallest was for WBDF. Most WBDF toxicity impacts are in the water column and not the sediment. Group III NADFs, except for one enhanced mineral oil, had similar risk, but the main risk contributors were different. For the enhanced mineral oils and synthetic paraffin, chemical toxicity influenced overall risk; internal olefins did not exert risk from chemical toxicity. For all Group I","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":"122024024","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}
Priscila Reis da Silva, T. A. Silva, E. R. Nicolosi, Carlos Abraham de Knegt Miranda
The environmental aspect can be critical in the decision-making process at the onset of offshore E&P projects, especially in sensitive areas. Thus, we developed a methodological framework and a web tool to support the selection of technological and locational alternatives in subsea system installation and decommissioning activities. This framework relies on the assessment of environmental pressures and biological sensitivities. Our model's main assumption is that an activity can cause a number of environmental pressures, which can have different effects on each environmental component (habitats or biological groups). In the end, a potential environmental impact of a technology can be the result of its pressures on the components at a location. The work relied on experts' judgement and it was based on some previously established criteria for the classification of these environmental pressures and components' sensitivities. Scores were set and ranked in these assessments and a formula calculated the potential environmental impact of each activity/technology. A web tool called SCENARIO was developed to incorporate these results in a user-friendly interface, where one can compare scenarios made up with different technological options and different habitats or biological groups. This tool points out the potential environmental impact of each available choice. It also details how each component relates to that impact. Finally, one can acknowledge the environmental performance of its own scenario choices within the range of the best and worst possible alternatives. The tool was tested and proved to be technically sound and capable of contributing effectively to support the decision making process in the environmental aspects of offshore E&P subsea projects. It is also flexible to incorporate any pressure review, new activities and technological updates whenever necessary.
{"title":"Potential Environmental Impacts of Subsea System Installation and Decommissioning: A New Tool for Comparison of Locational and Technological Alternatives in the Oil & Gas Industry","authors":"Priscila Reis da Silva, T. A. Silva, E. R. Nicolosi, Carlos Abraham de Knegt Miranda","doi":"10.4043/29891-ms","DOIUrl":"https://doi.org/10.4043/29891-ms","url":null,"abstract":"\u0000 The environmental aspect can be critical in the decision-making process at the onset of offshore E&P projects, especially in sensitive areas. Thus, we developed a methodological framework and a web tool to support the selection of technological and locational alternatives in subsea system installation and decommissioning activities. This framework relies on the assessment of environmental pressures and biological sensitivities. Our model's main assumption is that an activity can cause a number of environmental pressures, which can have different effects on each environmental component (habitats or biological groups). In the end, a potential environmental impact of a technology can be the result of its pressures on the components at a location. The work relied on experts' judgement and it was based on some previously established criteria for the classification of these environmental pressures and components' sensitivities. Scores were set and ranked in these assessments and a formula calculated the potential environmental impact of each activity/technology. A web tool called SCENARIO was developed to incorporate these results in a user-friendly interface, where one can compare scenarios made up with different technological options and different habitats or biological groups. This tool points out the potential environmental impact of each available choice. It also details how each component relates to that impact. Finally, one can acknowledge the environmental performance of its own scenario choices within the range of the best and worst possible alternatives. The tool was tested and proved to be technically sound and capable of contributing effectively to support the decision making process in the environmental aspects of offshore E&P subsea projects. It is also flexible to incorporate any pressure review, new activities and technological updates whenever necessary.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"39 11","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120821631","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}
We have conducted research with 50 E&P companies to identify the emerging technologies that would have the potential to disrupt oil and gas industry in the next three to five years. Examples of these technologies include: Aerial Data Gathering & Interpretations, Artificial Intelligence including Machine & Deep Learning, Biosciences including DNA Sequencing CRISPR Editing, Blockchain, Micro fluidics, Digital Twin 2.0., Nanotechnology, Natural Language Processing, Quantum Computing, and 3D Printing. The scope of this research will include identification of those disrupting technologies, field level tactical applications of those technologies and use cases, the potential impact of those technologies voted by the 50 operators, and required conditions for top selected technologies to flourish. In this paper we will not review an individual technology to utmost technical depth but we will provide a portfolio view of emerging technologies and their level of impact on the industry. The foresight into the future technological disruptions is critical for the E&P companies who are investing millions of dollars each year in upgrading their equipment and infrastructure. Without this foresight, much of their investments could rapidly become obsolete. Our approach involved deep interviews with subject matter experts within 50 oil companies to collect a database of interests and needs by them. Then we investigated more than 150 technology innovators and startups to identify disruptive solutions that could match those particular needs of the operators. Finally, we brought the top selected technologies in touch with the operators in a one full day workshop to high-grade and discuss the implications. We have reviewed 20 technology trends that have the potential to be disruptive and found out that 5 of these technology trends attracted and were viewed as top areas for disruption by 80% of the operators. We also found out that a few of these technology themes are more fundamental and the enablers for the broader set of disruptions to happen, while a number of them are more secondary or consequential. Up to this date all research on frontier technologies that could have an impact on oil and gas industry have been studied academically and/or by industry on a one by one basis. This paper for the first time collects a statistically valid interpretation on the importance of these technologies by the resource holders themselves and takes a portfolio view on emerging technologies versus the silo view that makes it difficult to prioritize resources and technology roadmaps. This will benefit all stakeholders of the oil and gas industry ranging from operators, innovators, investors, and to the resource holder nations in large.
{"title":"A Deep Dive into Disruptive Technologies in the Oil and Gas Industry","authors":"David Wishnow, Hosseini Azar, Maziar Pashaei Rad","doi":"10.4043/29779-ms","DOIUrl":"https://doi.org/10.4043/29779-ms","url":null,"abstract":"\u0000 We have conducted research with 50 E&P companies to identify the emerging technologies that would have the potential to disrupt oil and gas industry in the next three to five years. Examples of these technologies include: Aerial Data Gathering & Interpretations, Artificial Intelligence including Machine & Deep Learning, Biosciences including DNA Sequencing CRISPR Editing, Blockchain, Micro fluidics, Digital Twin 2.0., Nanotechnology, Natural Language Processing, Quantum Computing, and 3D Printing.\u0000 The scope of this research will include identification of those disrupting technologies, field level tactical applications of those technologies and use cases, the potential impact of those technologies voted by the 50 operators, and required conditions for top selected technologies to flourish.\u0000 In this paper we will not review an individual technology to utmost technical depth but we will provide a portfolio view of emerging technologies and their level of impact on the industry.\u0000 The foresight into the future technological disruptions is critical for the E&P companies who are investing millions of dollars each year in upgrading their equipment and infrastructure. Without this foresight, much of their investments could rapidly become obsolete.\u0000 Our approach involved deep interviews with subject matter experts within 50 oil companies to collect a database of interests and needs by them.\u0000 Then we investigated more than 150 technology innovators and startups to identify disruptive solutions that could match those particular needs of the operators.\u0000 Finally, we brought the top selected technologies in touch with the operators in a one full day workshop to high-grade and discuss the implications.\u0000 We have reviewed 20 technology trends that have the potential to be disruptive and found out that 5 of these technology trends attracted and were viewed as top areas for disruption by 80% of the operators. We also found out that a few of these technology themes are more fundamental and the enablers for the broader set of disruptions to happen, while a number of them are more secondary or consequential.\u0000 Up to this date all research on frontier technologies that could have an impact on oil and gas industry have been studied academically and/or by industry on a one by one basis. This paper for the first time collects a statistically valid interpretation on the importance of these technologies by the resource holders themselves and takes a portfolio view on emerging technologies versus the silo view that makes it difficult to prioritize resources and technology roadmaps. This will benefit all stakeholders of the oil and gas industry ranging from operators, innovators, investors, and to the resource holder nations in large.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"7 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":"128409756","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper describes the use of a Downhole Temperature Sensor Array, during a commingled Drill Stem Test, to accurately determine the density of the produced fluids. In a typical Drill Stem Test, using only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced fluid density calculated would be erroneous. Accurate calculation of the produced fluid densities is of great importance to the reservoir engineer since it forms a critical component of the equations of state used in the modelling of the reservoir. The main purpose of this paper is to show that knowledge of the produced fluid densities from each of the perforated intervals provides a more robust calculation of the zonal flowrate contributions using conservation of mass principles. In this case study, the well was produced across three intervals with the deepest perforated interval producing a fluid with a higher density than the shallower perforated intervals. The higher density of the produced fluid from this deeper interval caused the wellbore fluids to slug during the flow periods with a measureable response in the pressure and temperature data. If this difference in the fluid properties is not taken into account then the zonal allocation flowrate will be in error since it relies on the density and specific heat capacity. Qualitative assessment of the temperature array data identified the producing zones and clearly highlighted the different fluid interfaces in detail that would remain hidden if relying solely on the pressure gauges. This method is enabled by the deployment of a Downhole Temperature Sensor Array consisting of an array of discrete electronic temperature sensors alongside the TCP guns, generating continuous thermal profiles across the three intervals. This is augmented by a wireless data system of pressure points. All the data is collected real time throughout the entire Drill Stem Test.
{"title":"Determining Produced Fluid Properties for Accurate Production Profiling During a Drill Stem Test Using Thermal Imaging Technology.","authors":"D. Lavery, D. Fyfe, A. Hasan","doi":"10.4043/29749-ms","DOIUrl":"https://doi.org/10.4043/29749-ms","url":null,"abstract":"\u0000 This paper describes the use of a Downhole Temperature Sensor Array, during a commingled Drill Stem Test, to accurately determine the density of the produced fluids. In a typical Drill Stem Test, using only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced fluid density calculated would be erroneous.\u0000 Accurate calculation of the produced fluid densities is of great importance to the reservoir engineer since it forms a critical component of the equations of state used in the modelling of the reservoir. The main purpose of this paper is to show that knowledge of the produced fluid densities from each of the perforated intervals provides a more robust calculation of the zonal flowrate contributions using conservation of mass principles.\u0000 In this case study, the well was produced across three intervals with the deepest perforated interval producing a fluid with a higher density than the shallower perforated intervals. The higher density of the produced fluid from this deeper interval caused the wellbore fluids to slug during the flow periods with a measureable response in the pressure and temperature data. If this difference in the fluid properties is not taken into account then the zonal allocation flowrate will be in error since it relies on the density and specific heat capacity. Qualitative assessment of the temperature array data identified the producing zones and clearly highlighted the different fluid interfaces in detail that would remain hidden if relying solely on the pressure gauges.\u0000 This method is enabled by the deployment of a Downhole Temperature Sensor Array consisting of an array of discrete electronic temperature sensors alongside the TCP guns, generating continuous thermal profiles across the three intervals. This is augmented by a wireless data system of pressure points. All the data is collected real time throughout the entire Drill Stem Test.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"1 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":"129192322","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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