It becomes evident today's Oil&Gas projects in average have higher electrical power demand than years back. In most cases technical decisions are to simply increase current to compensate power needs. Design ratings for operating and short-circuit currents of medium-voltage switchgear on generator voltage level are limiting grid design. This is the case especially for power islands. Stepping up generator voltage can be a perfect solution in particular for power grids feeding extended oil fields. Installing step-up transformers for each generator unit and working with a network voltage up to 33 kV or higher sometimes creates disposition to believe that this is a more expensive solution. A load-flow and short-circuit calculation for the main substation is required to properly size the switchgear and the other distribution equipment derived from planned grid arrangement and oil field process specific operation modes. It has also to be considered expected power supply quality, reliability and availability. A cost comparison will be based on total cost of ownership between the solution with main substation on generator voltage level of 11 kV and the solutions with step-up transformers up to 22 or up to 33 kV. This comparison will also include the additional heat losses of overhead lines or cables to and between the wellpads for a year of operation. When using higher voltages, there should be no limitation with respect to grid design and grid operation. Generally, the voltage level has to be adequate for the supply purpose. A network should be designed to avoid use of current limiters. With proper voltage level selection the bus sectionalizers can remain in NC position. It is possible that generator units are operated that loss of one set can be compensated to avoid any interruption of power supply. Power generation can be increased when feeding via transformers to higher voltage levels of switchgear. The Power Plant Switchgear will require only a reduced short-circuit level and lower design currents for busbars and feeders to achieve optimized grid design. Unit transformers between generators and switchgear will prevent any negative influence of ground faults from the grid to the generators. Also with respect to heat losses, maintenance, grid availability and reliability as well as aging the advantages are clearly on the higher voltage level. The required power grid will be assessed based on different voltage levels. The optimized solution for the oil field will be discussed in detail. Solution approach with higher voltage levels and optimized grid design will have reserves to deliver additional electrical power for extensions and also for operation in depletion mode. There are now oil fields which do not allow bridging distances between wellpads by means of overhead lines but by underground cabling because of environmental conditions. Considering this aspect in cost comparison between different grid designs and voltage levels the advantage fo
{"title":"Creating Optimal Power Supply for Extensive Onshore Oil Fields","authors":"W. Baerthlein, D. Audring","doi":"10.2118/192782-MS","DOIUrl":"https://doi.org/10.2118/192782-MS","url":null,"abstract":"\u0000 It becomes evident today's Oil&Gas projects in average have higher electrical power demand than years back. In most cases technical decisions are to simply increase current to compensate power needs. Design ratings for operating and short-circuit currents of medium-voltage switchgear on generator voltage level are limiting grid design. This is the case especially for power islands. Stepping up generator voltage can be a perfect solution in particular for power grids feeding extended oil fields.\u0000 Installing step-up transformers for each generator unit and working with a network voltage up to 33 kV or higher sometimes creates disposition to believe that this is a more expensive solution.\u0000 A load-flow and short-circuit calculation for the main substation is required to properly size the switchgear and the other distribution equipment derived from planned grid arrangement and oil field process specific operation modes. It has also to be considered expected power supply quality, reliability and availability.\u0000 A cost comparison will be based on total cost of ownership between the solution with main substation on generator voltage level of 11 kV and the solutions with step-up transformers up to 22 or up to 33 kV. This comparison will also include the additional heat losses of overhead lines or cables to and between the wellpads for a year of operation.\u0000 When using higher voltages, there should be no limitation with respect to grid design and grid operation. Generally, the voltage level has to be adequate for the supply purpose. A network should be designed to avoid use of current limiters. With proper voltage level selection the bus sectionalizers can remain in NC position. It is possible that generator units are operated that loss of one set can be compensated to avoid any interruption of power supply.\u0000 Power generation can be increased when feeding via transformers to higher voltage levels of switchgear. The Power Plant Switchgear will require only a reduced short-circuit level and lower design currents for busbars and feeders to achieve optimized grid design. Unit transformers between generators and switchgear will prevent any negative influence of ground faults from the grid to the generators. Also with respect to heat losses, maintenance, grid availability and reliability as well as aging the advantages are clearly on the higher voltage level. The required power grid will be assessed based on different voltage levels. The optimized solution for the oil field will be discussed in detail.\u0000 Solution approach with higher voltage levels and optimized grid design will have reserves to deliver additional electrical power for extensions and also for operation in depletion mode.\u0000 There are now oil fields which do not allow bridging distances between wellpads by means of overhead lines but by underground cabling because of environmental conditions. Considering this aspect in cost comparison between different grid designs and voltage levels the advantage fo","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84921606","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Hirano, Toshiyuki Sunaba, Manea Saeed Al Jaberi, Faisal Al Alawi
CO2 corrosion is a vital problem in oil and gas production. The carbon steel pipe can suffer a long-term use economically under the CO2 corrosion environment by choosing an appropriate corrosion inhibitor. The performance of several corrosion inhibitors at elevated temperature & high salinity CO2 rich condition was evaluated for a field application. The performance of corrosion inhibitors was evaluated with an electrochemical measurement namely Liner Polarization Resistance (LPR) and weight loss coupons in autoclaves. LPR measures in-situ corrosion rate and it shows the inhibitor adhesion behavior on the metal surface. In the weight loss test, test coupons were mounted in a rotating cage and immersed in the test solution for a week. Test solution was synthetic brines with Total Dissolved Solids (TDS) 17%. The test solution was aerated with CO2 at ambient temperature and pressure before the corrosion test. It is well known that the inhibitor efficiency is encumbered with many variables, such as temperature, pressure, pH, flow speed and chemical composition of the production fluid. Salt content of formation water varies dependent on the location. Sometimes a production water analysis of a Middle East oil well shows more than 10% by weight. The inhibitors evaluated here had the temperature tolerance up to 100 °C and the same was the maximum test temperature. Some corrosion inhibitors performed better at low temperature than at high temperature. They showed poor inhibitor efficiency in case of pre-corrosion with high salinity at high temperature condition. This study also confirmed the validity of ILSS (Inhibitor Likelihood Success Score) introduced by Crossland et al. The score which was later acknowledged by HSE Office (UK) provided a useful information for inhibitor selection for pipelines in various field conditions. Several corrosion testing procedures were carried out to confirm the associated impact with/without pre-corrosion on the overall performance of the corrosion inhibitors. It seems that high salinity affects the inhibitor adhesion competing with corrosion product. The pre-corrosion test is an indispensable step for a qualification of corrosion inhibitors for a high salinity field.
{"title":"Evaluation of Corrosion Inhibitor Performance Under High Temperature / High Salinity Sweet Conditions","authors":"S. Hirano, Toshiyuki Sunaba, Manea Saeed Al Jaberi, Faisal Al Alawi","doi":"10.2118/193016-MS","DOIUrl":"https://doi.org/10.2118/193016-MS","url":null,"abstract":"\u0000 CO2 corrosion is a vital problem in oil and gas production. The carbon steel pipe can suffer a long-term use economically under the CO2 corrosion environment by choosing an appropriate corrosion inhibitor. The performance of several corrosion inhibitors at elevated temperature & high salinity CO2 rich condition was evaluated for a field application.\u0000 The performance of corrosion inhibitors was evaluated with an electrochemical measurement namely Liner Polarization Resistance (LPR) and weight loss coupons in autoclaves. LPR measures in-situ corrosion rate and it shows the inhibitor adhesion behavior on the metal surface. In the weight loss test, test coupons were mounted in a rotating cage and immersed in the test solution for a week. Test solution was synthetic brines with Total Dissolved Solids (TDS) 17%. The test solution was aerated with CO2 at ambient temperature and pressure before the corrosion test.\u0000 It is well known that the inhibitor efficiency is encumbered with many variables, such as temperature, pressure, pH, flow speed and chemical composition of the production fluid. Salt content of formation water varies dependent on the location. Sometimes a production water analysis of a Middle East oil well shows more than 10% by weight. The inhibitors evaluated here had the temperature tolerance up to 100 °C and the same was the maximum test temperature. Some corrosion inhibitors performed better at low temperature than at high temperature. They showed poor inhibitor efficiency in case of pre-corrosion with high salinity at high temperature condition. This study also confirmed the validity of ILSS (Inhibitor Likelihood Success Score) introduced by Crossland et al. The score which was later acknowledged by HSE Office (UK) provided a useful information for inhibitor selection for pipelines in various field conditions.\u0000 Several corrosion testing procedures were carried out to confirm the associated impact with/without pre-corrosion on the overall performance of the corrosion inhibitors. It seems that high salinity affects the inhibitor adhesion competing with corrosion product. The pre-corrosion test is an indispensable step for a qualification of corrosion inhibitors for a high salinity field.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90062955","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}
Salvatore Spagnolo, Francesco Incollà, C. Guglielmo
Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit. The job included the complete path from design and operations definition to the ESP commissioning and follow-up. Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up. The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced. Major attention was given to HSEQ aspects in every phase. The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay. Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time. Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner. This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.
{"title":"First Successful Replacement of Fully Retrievable ESP by Slickline","authors":"Salvatore Spagnolo, Francesco Incollà, C. Guglielmo","doi":"10.2118/192839-MS","DOIUrl":"https://doi.org/10.2118/192839-MS","url":null,"abstract":"\u0000 Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit.\u0000 The job included the complete path from design and operations definition to the ESP commissioning and follow-up.\u0000 Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up.\u0000 The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced.\u0000 Major attention was given to HSEQ aspects in every phase.\u0000 The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay.\u0000 Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time.\u0000 Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner.\u0000 This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80866408","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}
Mahmoudreza Jazayeri Noushabadi, A. Brisset, S. Thibeau
Carbon Capture, Utilization and Storage (CCUS) accounts for around 14% of the cumulative emissions reductions needed through 2050 (IEA, 2016) in its 2°C scenario. Deep saline aquifers were recognized as the largest potential storage resource available worldwide for CO2 storage into geological formations. Securing the geological storage of CO2 is mandatory with this kind of project. Indeed, under specific conditions, the resulting pressure build-up of a CO2 injection into an aquifer can possibly lead to leak into shallow geological aquifers or atmosphere through preferential pathways such as geological faults and wells. The brine extraction is envisaged to decrease the reservoir pressure build-up while injecting CO2. In this study, an investigation was made to use a part of this extracted brine to increase the CO2 storage security by accelerating both residual and solubility trapping mechanisms through the deployment of water (W) alternative CO2 (G) injection (WAG_CCS) at field scale. If this alternative CO2 injection process gives interesting results, then this approach will also lead to the reduction of the duration of post-injection site monitoring. In addition, the WAG_CCS process may help increasing the sweep efficiency of CO2 by controlling the mobility ratio and consequently improving the storage capacity. Several WAG_CCS pattern models were simulated with Eclipse software to investigate the impact of the method. A real geological model of an aquifer (Sleipner model, public data) was used for the simulations. As simulation base case, the CO2 is injected into the aquifer through one injection well for a period of 25 years followed by a 3500 years post injection simulation. Several other injection scenarios are simulated where water (W) is extracted from the same formation and partly reinjected alternatively with CO2 (G). The injection period schedules are as follow: 3months(G)-3months(W) to 1year(G)-1year(W). The mobile gas volume (structural trapping) and residual gas volume and dissolved gas volume (solubility trapping) are compared for all simulated cases. An experimental design screening was implemented in order to investigate the impact of several parameters such as well numbers, permeability, critical gas saturation… The results of this study gave answers to the WAG_CCS process efficiency in CO2 geological storage. It can be concluded that it can (1) be efficient under realistic geological conditions; (2) speed up the capillary trapping mechanism; (3) accelerate the dissolution trapping mechanism; (4) control the CO2 mobility and increase the sweep efficiency of CO2; and (5) help to manage project risks. The water extraction from an aquifer during the CO2 storage is a subject which was already studied and proposed in several publications but the utilization of the extracted water is still a research subject. Extracted water desalinization, reinjection in depleted formations, surface dissolution of CO2 within the extracted water b
{"title":"Investigation of CO2 Storage Security Increase by Brine Alternative CO2 Injection WAG_CCS","authors":"Mahmoudreza Jazayeri Noushabadi, A. Brisset, S. Thibeau","doi":"10.2118/193250-MS","DOIUrl":"https://doi.org/10.2118/193250-MS","url":null,"abstract":"\u0000 Carbon Capture, Utilization and Storage (CCUS) accounts for around 14% of the cumulative emissions reductions needed through 2050 (IEA, 2016) in its 2°C scenario. Deep saline aquifers were recognized as the largest potential storage resource available worldwide for CO2 storage into geological formations. Securing the geological storage of CO2 is mandatory with this kind of project. Indeed, under specific conditions, the resulting pressure build-up of a CO2 injection into an aquifer can possibly lead to leak into shallow geological aquifers or atmosphere through preferential pathways such as geological faults and wells. The brine extraction is envisaged to decrease the reservoir pressure build-up while injecting CO2. In this study, an investigation was made to use a part of this extracted brine to increase the CO2 storage security by accelerating both residual and solubility trapping mechanisms through the deployment of water (W) alternative CO2 (G) injection (WAG_CCS) at field scale. If this alternative CO2 injection process gives interesting results, then this approach will also lead to the reduction of the duration of post-injection site monitoring. In addition, the WAG_CCS process may help increasing the sweep efficiency of CO2 by controlling the mobility ratio and consequently improving the storage capacity.\u0000 Several WAG_CCS pattern models were simulated with Eclipse software to investigate the impact of the method. A real geological model of an aquifer (Sleipner model, public data) was used for the simulations. As simulation base case, the CO2 is injected into the aquifer through one injection well for a period of 25 years followed by a 3500 years post injection simulation. Several other injection scenarios are simulated where water (W) is extracted from the same formation and partly reinjected alternatively with CO2 (G). The injection period schedules are as follow: 3months(G)-3months(W) to 1year(G)-1year(W). The mobile gas volume (structural trapping) and residual gas volume and dissolved gas volume (solubility trapping) are compared for all simulated cases.\u0000 An experimental design screening was implemented in order to investigate the impact of several parameters such as well numbers, permeability, critical gas saturation…\u0000 The results of this study gave answers to the WAG_CCS process efficiency in CO2 geological storage. It can be concluded that it can (1) be efficient under realistic geological conditions; (2) speed up the capillary trapping mechanism; (3) accelerate the dissolution trapping mechanism; (4) control the CO2 mobility and increase the sweep efficiency of CO2; and (5) help to manage project risks.\u0000 The water extraction from an aquifer during the CO2 storage is a subject which was already studied and proposed in several publications but the utilization of the extracted water is still a research subject. Extracted water desalinization, reinjection in depleted formations, surface dissolution of CO2 within the extracted water b","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81079374","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 suggested the use of asymmetrical six phase induction motors instead of the conventional three phase motors for safety critical equipment to improve the overall system reliability. The rule of thumb is that a single fault should not be able to draw safety critical equipment out of service. Multi-phase machine in general and six phase machine in particular are able to continue running with one phase or more open circuit. The ability of multi-phase machines even to start under fault is another useful feature. Statistically, the main reason for losing one of the motor phases is the single open gate transistor fault. The defected phase is entirely disregarded, and then the current in the rest of phases which still functioning is optimized. Consequently, if minimum copper loss criterion is applied, the paid penalty is 50% additional losses that leads to motor derating, if not pre-designed with proper safety factor. This paper introduces an alternative post fault control strategy, which allows the usage of the entire healthy power electronic switches. An achievement of reducing the post fault increase in stator copper losses to 25% is realized.
{"title":"Increased Reliability Using Asymmetrical Six Phase Induction Motor with Double Isolated Neutral","authors":"Elhussien A. Mahmoud","doi":"10.2118/193151-MS","DOIUrl":"https://doi.org/10.2118/193151-MS","url":null,"abstract":"\u0000 This work suggested the use of asymmetrical six phase induction motors instead of the conventional three phase motors for safety critical equipment to improve the overall system reliability. The rule of thumb is that a single fault should not be able to draw safety critical equipment out of service. Multi-phase machine in general and six phase machine in particular are able to continue running with one phase or more open circuit. The ability of multi-phase machines even to start under fault is another useful feature. Statistically, the main reason for losing one of the motor phases is the single open gate transistor fault. The defected phase is entirely disregarded, and then the current in the rest of phases which still functioning is optimized. Consequently, if minimum copper loss criterion is applied, the paid penalty is 50% additional losses that leads to motor derating, if not pre-designed with proper safety factor. This paper introduces an alternative post fault control strategy, which allows the usage of the entire healthy power electronic switches. An achievement of reducing the post fault increase in stator copper losses to 25% is realized.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82041236","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}
Abu Al Bukhoosh (ABK) is an oil and gas field located 180 kilometers away from the Abu Dhabi's coast and has been in operation since 1974. The complex was gradually developed over the past forty years, and has some aging platforms and facilities. As a consequence the problems related to Asset Integrity is one of the most important with regards to Operations Risk Management. Repairs or intervention activities must have very specific and rigorous plans for addressing barriers to prevent uncontrollable loss of containment from the wellbore to the external environment. Hence continuous monitoring and integrity management of the field is mandatory for long-term profitability and HSE performance in an aging asset like ABK. Asset Integrity is usually well covered during technical discussions and meetings, and is usually considered as a subject matter expert topic. However Asset Integrity and its associated technological risks are usually less discussed during general events involving the whole organization. This is more limited to operational safety KPI's, the protection of the environment and the prevention of accidents to people. These are easier topics to discuss and are more suited to the corporate communication materials.
Abu Al Bukhoosh (ABK)是一个油气田，距离阿布扎比海岸180公里，自1974年以来一直在运营。该综合体是在过去四十年中逐步发展起来的，有一些老化的平台和设施。因此，与资产完整性相关的问题是运营风险管理中最重要的问题之一。维修或干预活动必须有非常具体和严格的计划来解决障碍，以防止从井筒到外部环境的不可控制的密封泄漏。因此，对于像ABK这样的老旧资产来说，为了长期盈利和HSE表现，必须对油田进行持续监测和完整性管理。资产完整性通常在技术讨论和会议中被很好地涵盖，并且通常被认为是一个主题专家主题。然而，在涉及整个组织的一般事件中，通常很少讨论资产完整性及其相关的技术风险。这更局限于操作安全KPI，保护环境和防止人员事故。这些是比较容易讨论的话题，也更适合公司沟通材料。
{"title":"GIS: The Global Risk Mapping Towards Digital","authors":"Benoit Gouviez, B. George, Mouna Nizar","doi":"10.2118/192977-MS","DOIUrl":"https://doi.org/10.2118/192977-MS","url":null,"abstract":"\u0000 Abu Al Bukhoosh (ABK) is an oil and gas field located 180 kilometers away from the Abu Dhabi's coast and has been in operation since 1974. The complex was gradually developed over the past forty years, and has some aging platforms and facilities.\u0000 As a consequence the problems related to Asset Integrity is one of the most important with regards to Operations Risk Management. Repairs or intervention activities must have very specific and rigorous plans for addressing barriers to prevent uncontrollable loss of containment from the wellbore to the external environment. Hence continuous monitoring and integrity management of the field is mandatory for long-term profitability and HSE performance in an aging asset like ABK.\u0000 Asset Integrity is usually well covered during technical discussions and meetings, and is usually considered as a subject matter expert topic. However Asset Integrity and its associated technological risks are usually less discussed during general events involving the whole organization. This is more limited to operational safety KPI's, the protection of the environment and the prevention of accidents to people. These are easier topics to discuss and are more suited to the corporate communication materials.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"35 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79624081","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}
Hooisweng Ow, Sehoon Chang, Gawain Thomas, Rena Shi, Wei Wang, Hsieh Chen, M. Poitzsch, A. Abdel-Fattah
We are developing an integrated, real-time system for deploying Advanced Tracers cost-effectively in a ubiquitous and potentially long-term way. This campaign is for the sake of increasing the oil recovery factor in large waterflooded reservoirs through improved optimization of the water injection for oil production. This paper explains key features of this novel system and reports main results from the ongoing field test of our second-generation tracer material and detection methodology. Existing inter-well tracers require elaborate laboratory processing for analysis and are not compatible with ubiquitous or real-time deployment. Additionally, conventional tracer material and service costs are not economically viable for widespread and long-term deployment; also, available material barcodes compatible with carbonate reservoirs may be inadequate to monitor dozens of wells simultaneously. Our system addresses all of these inadequacies using novel materials and detection methods, with detailed modeling studies providing strong justification of the financial benefit of this tracer deployment through quantification of increased oil recovery from waterflooded reservoirs. Key elements of this new inter-well Advanced Tracers system include: An optically-detectable tracer material that can in principle be detected in real-time or near real-time at low limits of detection (LODs), even in the presence of background oil in producing water by means of an intrinsic oil background-subtraction method. The material also has high mobility in high-salinity carbonate reservoirs.A rich palette of tracer barcodes (potentially 50 - 100 or more) to enable simultaneous injection and sampling in dozens of nearby wells.Modeling feasibility studies, performed on an ensemble of different reservoir geometries and with sensitivity analyses, showing that including routine inter-well tracer data along with injection and production rates improves the history match quality and therefore, the optimization of the water injection and oil extraction rates so as to achieve a few percent increase in net present values (NPV). Recent field tests of the detectability and discrimination of injected prototype tracer materials will be described. This work adapts novel technology development at the state of the art of modern nanotechnology and bioanalysis to the long-term reservoir stewardship objectives. The integrated, real-time tracer-detection system promises financial benefits through increased NPV and/or ultimate recovery factor via better optimization of water injection.
{"title":"First Deployment of a Novel Advanced Tracers System for Improved Waterflood Recovery Optimization","authors":"Hooisweng Ow, Sehoon Chang, Gawain Thomas, Rena Shi, Wei Wang, Hsieh Chen, M. Poitzsch, A. Abdel-Fattah","doi":"10.2118/192598-MS","DOIUrl":"https://doi.org/10.2118/192598-MS","url":null,"abstract":"\u0000 We are developing an integrated, real-time system for deploying Advanced Tracers cost-effectively in a ubiquitous and potentially long-term way. This campaign is for the sake of increasing the oil recovery factor in large waterflooded reservoirs through improved optimization of the water injection for oil production. This paper explains key features of this novel system and reports main results from the ongoing field test of our second-generation tracer material and detection methodology.\u0000 Existing inter-well tracers require elaborate laboratory processing for analysis and are not compatible with ubiquitous or real-time deployment. Additionally, conventional tracer material and service costs are not economically viable for widespread and long-term deployment; also, available material barcodes compatible with carbonate reservoirs may be inadequate to monitor dozens of wells simultaneously. Our system addresses all of these inadequacies using novel materials and detection methods, with detailed modeling studies providing strong justification of the financial benefit of this tracer deployment through quantification of increased oil recovery from waterflooded reservoirs.\u0000 Key elements of this new inter-well Advanced Tracers system include: An optically-detectable tracer material that can in principle be detected in real-time or near real-time at low limits of detection (LODs), even in the presence of background oil in producing water by means of an intrinsic oil background-subtraction method. The material also has high mobility in high-salinity carbonate reservoirs.A rich palette of tracer barcodes (potentially 50 - 100 or more) to enable simultaneous injection and sampling in dozens of nearby wells.Modeling feasibility studies, performed on an ensemble of different reservoir geometries and with sensitivity analyses, showing that including routine inter-well tracer data along with injection and production rates improves the history match quality and therefore, the optimization of the water injection and oil extraction rates so as to achieve a few percent increase in net present values (NPV).\u0000 Recent field tests of the detectability and discrimination of injected prototype tracer materials will be described.\u0000 This work adapts novel technology development at the state of the art of modern nanotechnology and bioanalysis to the long-term reservoir stewardship objectives. The integrated, real-time tracer-detection system promises financial benefits through increased NPV and/or ultimate recovery factor via better optimization of water injection.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90717776","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Sompongchaiyakul, S. Bureekul, Siriphorn Sombatjinda
More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations). Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.
{"title":"Impact of Natural Gas Exploration and Production on Mercury Concentrations in Surface Sediment of the Gulf of Thailand","authors":"P. Sompongchaiyakul, S. Bureekul, Siriphorn Sombatjinda","doi":"10.2118/192739-MS","DOIUrl":"https://doi.org/10.2118/192739-MS","url":null,"abstract":"\u0000 More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations).\u0000 Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88815134","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. D. Lullo, C. Passucci, K. Hester, R. Zaffaroni, R. Reinhart
Pipeline in-line inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12" offshore line, a significant amount of wax deposits was expected and a series hydro-mechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs. Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool. In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss. The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to re-create the line elevation, profile with limited a priori information.
{"title":"Use of Miniaturized Sensors to Optimize Cleaning Operations for In-Line Inspection of a Subsea Pipeline","authors":"A. D. Lullo, C. Passucci, K. Hester, R. Zaffaroni, R. Reinhart","doi":"10.2118/193010-MS","DOIUrl":"https://doi.org/10.2118/193010-MS","url":null,"abstract":"\u0000 Pipeline in-line inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12\" offshore line, a significant amount of wax deposits was expected and a series hydro-mechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs.\u0000 Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool.\u0000 In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss.\u0000 The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to re-create the line elevation, profile with limited a priori information.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86292282","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}
Amit Kumar, Ahmed Al Dahmani, Shaheen Kunhi, Asif Iqbal, M. Amad, T. Morrow
During field inspection of Christmas (X-mas) trees in a giant oil offshore field in Abu Dhabi, a small subset of wells were reported to be severely corroded on X-mas tree studded outlets imposing high HSE risks due to possible loss of containment. A holistic analysis was conducted to identify corroded X-mas trees, establish the root-cause of corrosion and recommend a remedial action plan to control future corrosion damage and reduce HSE risk exposure. Advanced modeling tools and lab tests were used to analyze the flow behavior and field samples, respectively. Advanced modeling was performed to analyze inorganic scale potential, identify flow regimes and calculate corrosion rates in the X-mas trees to correlate with operating conditions. Solid samples from X-mas trees were analyzed using advanced microscopy techniques to identify the elemental composition and phases. Water samples were also analyzed to check bacteria content. Available data on historical operating conditions, modeling and lab analysis results were segregated into in-favor and against factors for each of the mechanisms to identify the potential root-cause of corrosion. Modeling results were used in conjunction with actual field data such as corrosion feature morphology, historical operating conditions, etc. to evaluate corrosion damage. Based on corrosion feature morphology, wells were categorized into different groups to compare the flow behavior and operating conditions with observed corrosion patterns. A thorough analysis of corrosion feature morphology and operating conditions identified flow-induced localized corrosion (FILC) as the root-cause of corrosion in severely corroded X-mas trees. X-mas tree design, fluid properties and operating parameters such as well head pressure (WHP), wellhead temperature (WHT) and flow rate were found to be key contributing factors of accelerated corrosion. Results of computational fluid dynamics (CFD) modeling showed that the horizontal section of X-mas tree is exposed to higher turbulence, water wetting and transient gas bubble formation/collapse phenomena than the vertical section due to changes in flow direction and gravity effects. Several mitigation strategies were implemented to control corrosion in the X-mas tree flange area, and reduce likelihood of leakage through the X-mas tree flange. Findings from this work led to development of an Excel based tool which can be used to assess and predict the corrosion risks to X-tree based on operating conditions.
{"title":"Holistic Study to Identify Root-Cause of Corrosion in Christmas Trees of Oil Producer Wells","authors":"Amit Kumar, Ahmed Al Dahmani, Shaheen Kunhi, Asif Iqbal, M. Amad, T. Morrow","doi":"10.2118/192663-MS","DOIUrl":"https://doi.org/10.2118/192663-MS","url":null,"abstract":"\u0000 During field inspection of Christmas (X-mas) trees in a giant oil offshore field in Abu Dhabi, a small subset of wells were reported to be severely corroded on X-mas tree studded outlets imposing high HSE risks due to possible loss of containment. A holistic analysis was conducted to identify corroded X-mas trees, establish the root-cause of corrosion and recommend a remedial action plan to control future corrosion damage and reduce HSE risk exposure.\u0000 Advanced modeling tools and lab tests were used to analyze the flow behavior and field samples, respectively. Advanced modeling was performed to analyze inorganic scale potential, identify flow regimes and calculate corrosion rates in the X-mas trees to correlate with operating conditions. Solid samples from X-mas trees were analyzed using advanced microscopy techniques to identify the elemental composition and phases. Water samples were also analyzed to check bacteria content. Available data on historical operating conditions, modeling and lab analysis results were segregated into in-favor and against factors for each of the mechanisms to identify the potential root-cause of corrosion. Modeling results were used in conjunction with actual field data such as corrosion feature morphology, historical operating conditions, etc. to evaluate corrosion damage. Based on corrosion feature morphology, wells were categorized into different groups to compare the flow behavior and operating conditions with observed corrosion patterns.\u0000 A thorough analysis of corrosion feature morphology and operating conditions identified flow-induced localized corrosion (FILC) as the root-cause of corrosion in severely corroded X-mas trees. X-mas tree design, fluid properties and operating parameters such as well head pressure (WHP), wellhead temperature (WHT) and flow rate were found to be key contributing factors of accelerated corrosion. Results of computational fluid dynamics (CFD) modeling showed that the horizontal section of X-mas tree is exposed to higher turbulence, water wetting and transient gas bubble formation/collapse phenomena than the vertical section due to changes in flow direction and gravity effects. Several mitigation strategies were implemented to control corrosion in the X-mas tree flange area, and reduce likelihood of leakage through the X-mas tree flange. Findings from this work led to development of an Excel based tool which can be used to assess and predict the corrosion risks to X-tree based on operating conditions.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82643891","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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