S. Jouenne, J. Anfray, P. Cordelier, K. Mateen, D. Levitt, I. Souilem, P. Marchal, C. Lemaitre, L. Choplin, Jonathon Nesvik, T. Waldman
Rules of thumb that are used in the industry for polymer-flooding projects tend to limit the distance over which hydrolyzed poly-acrylamide polymers can be transported in pipelines without under-going significant degradation. However, in sensitive environments, such as offshore facilities where footprint minimization is required, centralization of the polymer-hydration process and long-distance transport may be desirable. More-reliable rules are required to de-sign the pipe network and to estimate mechanical degradation of polymers during transport in turbulent conditions.In this work, we present evidence in the form of empirical large-scale pipeline experiments and theoretical development refuting the claim that polymer pipeline transport is limited by mechanical degradation. Our work concludes that mechanical degradation oc-curs at a critical velocity, which increases as a function of pipe di-ameter. Provided the critical velocity is not reached in a given pipe, there is no limit to the distance over which polymer solution can be transported. In addition, the drag reduction of viscous polymer solutions was measured as a function of pipe length, pipe diameter, fluid ve-locity, and polymer concentration. An envelope was defined to fix the minimum and maximum drag reductions expected for a given velocity in larger pipes. For pipes with diameters varying between 14 and 22 in. at a velocity greater than 1 m/s, the drag-reduction percentage is anticipated to be between 55 and 80%. A more- refined model was developed to predict drag reduction with less uncertainty. In conclusion, classical design rules applied for water transport (fluid velocity < 3 m/s) can be applied to the design of a polymer network. Therefore, for tertiary polymer projects, the existing water-injection network should be compatible with the mechanical requirements of polymer transportation. For secondary polymer projects, changing the rules of design by taking into account the high level of drag reduction should bring some economy to the pipe design and installation
{"title":"Degradation (or Lack Thereof) and Drag Reduction of HPAM Solutions During Transport in Turbulent Flow in Pipelines","authors":"S. Jouenne, J. Anfray, P. Cordelier, K. Mateen, D. Levitt, I. Souilem, P. Marchal, C. Lemaitre, L. Choplin, Jonathon Nesvik, T. Waldman","doi":"10.2118/169699-PA","DOIUrl":"https://doi.org/10.2118/169699-PA","url":null,"abstract":"Rules of thumb that are used in the industry for polymer-flooding projects tend to limit the distance over which hydrolyzed poly-acrylamide polymers can be transported in pipelines without under-going significant degradation. However, in sensitive environments, such as offshore facilities where footprint minimization is required, centralization of the polymer-hydration process and long-distance transport may be desirable. More-reliable rules are required to de-sign the pipe network and to estimate mechanical degradation of polymers during transport in turbulent conditions.In this work, we present evidence in the form of empirical large-scale pipeline experiments and theoretical development refuting the claim that polymer pipeline transport is limited by mechanical degradation. Our work concludes that mechanical degradation oc-curs at a critical velocity, which increases as a function of pipe di-ameter. Provided the critical velocity is not reached in a given pipe, there is no limit to the distance over which polymer solution can be transported. In addition, the drag reduction of viscous polymer solutions was measured as a function of pipe length, pipe diameter, fluid ve-locity, and polymer concentration. An envelope was defined to fix the minimum and maximum drag reductions expected for a given velocity in larger pipes. For pipes with diameters varying between 14 and 22 in. at a velocity greater than 1 m/s, the drag-reduction percentage is anticipated to be between 55 and 80%. A more- refined model was developed to predict drag reduction with less uncertainty. In conclusion, classical design rules applied for water transport (fluid velocity < 3 m/s) can be applied to the design of a polymer network. Therefore, for tertiary polymer projects, the existing water-injection network should be compatible with the mechanical requirements of polymer transportation. For secondary polymer projects, changing the rules of design by taking into account the high level of drag reduction should bring some economy to the pipe design and installation","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"4 1","pages":"80-92"},"PeriodicalIF":0.0,"publicationDate":"2015-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84898116","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}
{"title":"Taking on the Technical Challenges of Sour Gas Processing","authors":"P. Boschee","doi":"10.2118/1214-0021-OGF","DOIUrl":"https://doi.org/10.2118/1214-0021-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"404 1","pages":"21-25"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79745209","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Al-Maamari, M. Sueyoshi, M. Tasaki, Kojima Keisuke, K. Okamura
Summary Polymer-enhanced-oil-recovery (EOR) operation has been implemented for the production of oil from difficult mature oil fields in Oman. The polymer used to sweep oil toward production wells in this EOR technique is resulting in the generation of polymer-flood produced water (PFPW) of increasing viscosity. Current methods of treating oilfield produced water must be reconsidered for the effective treatment of PFPW of such changing quality. In a previous study, the use of polyaluminum chloride (PAC) was proposed for the coagulation of oil in produced water to be separated by flotation and filtration. As such, laboratory tests were conducted to evaluate the applicability of PAC and other chemicals for treatment of PFPW with higher viscosity than ordinary oilfield-produced water. These tests indicated clearly that aluminum sulfate (AS) was more effective for treatment of such higherviscosity water. A pilot plant developed during the earlier study was used to conduct coagulation/flocculation-, flotation-, filtration-, and adsorption-treatment trials for PFPW from an oil field at which polymer EOR was under way. For the final trial, the inlet PFPW viscosity was 1.4 cp at 40°C and oil concentration was greater than 200 mg/L. AS was applied for the coagulation/flocculation and flotation stages, and was found to be effective in reducing oil concentration to 1 mg/L. Filtration and adsorption stages resulted in further improvement of water quality. Most of the polymer used for EOR was believed to have been removed along with oil and suspended solids.
{"title":"Polymer Flood Produced Water Treatment Trials","authors":"R. Al-Maamari, M. Sueyoshi, M. Tasaki, Kojima Keisuke, K. Okamura","doi":"10.2118/172024-PA","DOIUrl":"https://doi.org/10.2118/172024-PA","url":null,"abstract":"Summary Polymer-enhanced-oil-recovery (EOR) operation has been implemented for the production of oil from difficult mature oil fields in Oman. The polymer used to sweep oil toward production wells in this EOR technique is resulting in the generation of polymer-flood produced water (PFPW) of increasing viscosity. Current methods of treating oilfield produced water must be reconsidered for the effective treatment of PFPW of such changing quality. In a previous study, the use of polyaluminum chloride (PAC) was proposed for the coagulation of oil in produced water to be separated by flotation and filtration. As such, laboratory tests were conducted to evaluate the applicability of PAC and other chemicals for treatment of PFPW with higher viscosity than ordinary oilfield-produced water. These tests indicated clearly that aluminum sulfate (AS) was more effective for treatment of such higherviscosity water. A pilot plant developed during the earlier study was used to conduct coagulation/flocculation-, flotation-, filtration-, and adsorption-treatment trials for PFPW from an oil field at which polymer EOR was under way. For the final trial, the inlet PFPW viscosity was 1.4 cp at 40°C and oil concentration was greater than 200 mg/L. AS was applied for the coagulation/flocculation and flotation stages, and was found to be effective in reducing oil concentration to 1 mg/L. Filtration and adsorption stages resulted in further improvement of water quality. Most of the polymer used for EOR was believed to have been removed along with oil and suspended solids.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"54 1","pages":"89-100"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90395077","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Voldsund, Tuong-Van Nguyen, B. Elmegaard, I. S. Ertesvåg, S. Kjelstrup
Oil and gas extraction have been responsible for 25—28% of the total greenhouse gas emissions in Norway the last 10 years. The part from offshore oil and gas processing, including power production, flaring, and cold ventilation on production platforms, accounted for 20—22%. Exergy analysis is a method for systematic assessment of potential to perform work. It gives the possibility to identify where in a process inefficiencies occur: both losses to the surroundings and internal irreversibilities, and can be used as a tool for pinpointing improvement potential and for evaluation of industrial processes. When used in the petroleum sector, this can motivate more efficient oil and gas extraction, leading to a better utilisation of the resources and less greenhouse gas emissions.The objectives of this thesis were to: (i) establish exergy analyses of the oil and gas processing plants on different types of North Sea platforms; (ii) identify and discuss improvement potentials for each case, compare them and draw general conclusions if possible; and (iii) define meaningful thermodynamic performance parameters for evaluation of the platforms.Four real platforms (Platforms A—D) and one generic platform of the North Sea type were simulated with the process simulators Aspen HYSYS and Aspen Plus. The real platforms were simulated using process data provided by the oil companies. The generic platform was simulated based on literature data, with six different feed compositions (Cases 1—6). These five platforms presented different process conditions; they differed for instance by their exported products, gas-to-oil ratios, reservoir characteristics and recovery strategies.Exergy analyses were carried out, and it was shown that for the cases studied in this work, the power consumption was in the range of 5.5—30 MW, or 20—660 MJ/Sm3 o.e. exported. The heat demand was very small and covered by electric heating for two of the platforms, and higher, but low enough to be covered by waste heat recovery from the power turbines and by heat integration between process streams, for the other three platforms. The main part of the power was consumed by compressors in the gas treatment section for all cases, except Platform B and Case 4 of the generic model. Platform B had lower pressures in the products than in the feeds, resulting in a low compression demand. Case 4 of the generic model had a high content of heavy hydrocarbons in the feed, resulting in large power demand in the oil export pumping section. The recompression and oil pumping sections appeared to be the other major power consumers, together with the seawater injection system, if installed.The total exergy destruction was in the range of 12—32 MW, or 43—517 MJ/Sm3 o.e. exported. Most exergy destruction was related to pressure increase or decrease. Exergy destruction in the gas treatment section made up 8—57% of the total amount, destruction in the recompression section accounted for 11—29%, while 10—28% took place
{"title":"Thermodynamic Performance Indicators for Offshore Oil and Gas Processing: Application to Four North Sea Facilities","authors":"M. Voldsund, Tuong-Van Nguyen, B. Elmegaard, I. S. Ertesvåg, S. Kjelstrup","doi":"10.2118/171565-PA","DOIUrl":"https://doi.org/10.2118/171565-PA","url":null,"abstract":"Oil and gas extraction have been responsible for 25—28% of the total greenhouse gas emissions in Norway the last 10 years. The part from offshore oil and gas processing, including power production, flaring, and cold ventilation on production platforms, accounted for 20—22%. Exergy analysis is a method for systematic assessment of potential to perform work. It gives the possibility to identify where in a process inefficiencies occur: both losses to the surroundings and internal irreversibilities, and can be used as a tool for pinpointing improvement potential and for evaluation of industrial processes. When used in the petroleum sector, this can motivate more efficient oil and gas extraction, leading to a better utilisation of the resources and less greenhouse gas emissions.The objectives of this thesis were to: (i) establish exergy analyses of the oil and gas processing plants on different types of North Sea platforms; (ii) identify and discuss improvement potentials for each case, compare them and draw general conclusions if possible; and (iii) define meaningful thermodynamic performance parameters for evaluation of the platforms.Four real platforms (Platforms A—D) and one generic platform of the North Sea type were simulated with the process simulators Aspen HYSYS and Aspen Plus. The real platforms were simulated using process data provided by the oil companies. The generic platform was simulated based on literature data, with six different feed compositions (Cases 1—6). These five platforms presented different process conditions; they differed for instance by their exported products, gas-to-oil ratios, reservoir characteristics and recovery strategies.Exergy analyses were carried out, and it was shown that for the cases studied in this work, the power consumption was in the range of 5.5—30 MW, or 20—660 MJ/Sm3 o.e. exported. The heat demand was very small and covered by electric heating for two of the platforms, and higher, but low enough to be covered by waste heat recovery from the power turbines and by heat integration between process streams, for the other three platforms. The main part of the power was consumed by compressors in the gas treatment section for all cases, except Platform B and Case 4 of the generic model. Platform B had lower pressures in the products than in the feeds, resulting in a low compression demand. Case 4 of the generic model had a high content of heavy hydrocarbons in the feed, resulting in large power demand in the oil export pumping section. The recompression and oil pumping sections appeared to be the other major power consumers, together with the seawater injection system, if installed.The total exergy destruction was in the range of 12—32 MW, or 43—517 MJ/Sm3 o.e. exported. Most exergy destruction was related to pressure increase or decrease. Exergy destruction in the gas treatment section made up 8—57% of the total amount, destruction in the recompression section accounted for 11—29%, while 10—28% took place","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"16 1","pages":"51-63"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85991159","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}
{"title":"Spar Innovations: Thinking Inside the Box Reaps Savings","authors":"W. Furlow","doi":"10.2118/1214-0026-OGF","DOIUrl":"https://doi.org/10.2118/1214-0026-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"87 1","pages":"26-29"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90493928","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Lai, Di Zhang, D. Dong, S. Chi, M. H. Todorovic, R. Gupta, L. Garces, Satish Gunturi, R. Datta, T. Wijekoon, C. Sihler, S. Rocke, Kristin Moe Elgsaas, Elise Savarit, A. Anbarasu, Joseph Song Manguelle, J. Pappas
Summary Subsea processing has been increasingly accepted by the offshore oil and gas industry as a solution to boost production and reduce cost. Accordingly, the subsea power demand is growing to support various processing loads, including pumps and compressors. Depending on the application, the power rating of a field ranges from tens of kilowatts to tens of megawatts, and the step-out distance ranges from a few kilometers to hundreds of kilometers. Considering the hostile and remote environment, a reliable subsea electrical-power system that is suitable for subsea deployment is clearly desired. This paper presents a modular direct-current electrical-power system that is designed for use in a subsea field with medium or long step-out distance. The proposed system consists of multiple modular converters in the subsea station to achieve the required power-conversion functions. It features high reliability, high flexibility, and reduced installation weight. The system operation and protection are presented, and the performance is verified by a laboratory-scale demonstration.
{"title":"A Modular Subsea Direct-Current Electrical-Power System","authors":"R. Lai, Di Zhang, D. Dong, S. Chi, M. H. Todorovic, R. Gupta, L. Garces, Satish Gunturi, R. Datta, T. Wijekoon, C. Sihler, S. Rocke, Kristin Moe Elgsaas, Elise Savarit, A. Anbarasu, Joseph Song Manguelle, J. Pappas","doi":"10.2118/171564-PA","DOIUrl":"https://doi.org/10.2118/171564-PA","url":null,"abstract":"Summary Subsea processing has been increasingly accepted by the offshore oil and gas industry as a solution to boost production and reduce cost. Accordingly, the subsea power demand is growing to support various processing loads, including pumps and compressors. Depending on the application, the power rating of a field ranges from tens of kilowatts to tens of megawatts, and the step-out distance ranges from a few kilometers to hundreds of kilometers. Considering the hostile and remote environment, a reliable subsea electrical-power system that is suitable for subsea deployment is clearly desired. This paper presents a modular direct-current electrical-power system that is designed for use in a subsea field with medium or long step-out distance. The proposed system consists of multiple modular converters in the subsea station to achieve the required power-conversion functions. It features high reliability, high flexibility, and reduced installation weight. The system operation and protection are presented, and the performance is verified by a laboratory-scale demonstration.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"112 1","pages":"64-79"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87781250","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}
Summary Elaborated models, such as those used for simulation purposes [e.g., in the OLGA® simulator (Bendiksen et al. 1991)], cannot be used for model-based control design because these models use too many state variables and the model equations are not usually available for the user. The focus of this paper is on deriving simple, dynamical models with few state variables that capture the essential dynamic behavior for control. We propose a new simplified dynamic model for severe-slugging flow in pipeline/riser systems. The proposed model, together with five other simplified models found in the literature, are compared with results from the OLGA simulator. The new model can be extended to other cases, and we consider also a well/ pipeline/riser system. The proposed simple models are able to represent the main dynamics of severe-slugging flow and compare well with experiments and OLGA simulations.
{"title":"Simplified Dynamic Models for Control of Riser Slugging in Offshore Oil Production","authors":"E. Jahanshahi, S. Skogestad","doi":"10.2118/172998-PA","DOIUrl":"https://doi.org/10.2118/172998-PA","url":null,"abstract":"Summary Elaborated models, such as those used for simulation purposes [e.g., in the OLGA® simulator (Bendiksen et al. 1991)], cannot be used for model-based control design because these models use too many state variables and the model equations are not usually available for the user. The focus of this paper is on deriving simple, dynamical models with few state variables that capture the essential dynamic behavior for control. We propose a new simplified dynamic model for severe-slugging flow in pipeline/riser systems. The proposed model, together with five other simplified models found in the literature, are compared with results from the OLGA simulator. The new model can be extended to other cases, and we consider also a well/ pipeline/riser system. The proposed simple models are able to represent the main dynamics of severe-slugging flow and compare well with experiments and OLGA simulations.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"1 1","pages":"80-88"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82969724","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}
It is common knowledge that hydraulic fracturing operations require a lot of water, and as they have become a more vital element of the oil and gas industry, sourcing this water has proven to be a challenge for companies operating in tough terrain. Drought plagues much of the United States, a country with significant hydraulic fracturing activity, and operators have to take hydrology concerns into consideration when constructing facilities in these environments. In most cases, the solution means recycling produced and flowback water and diminishing, or eliminating altogether, the need for fresh water. Depending on the region and its specific challenges, operators are finding unique ways to address the water issue. In the past couple of years, new facilities have been built or repurposed with new technologies that may affect how companies work in water-stressed shale plays in the future. Where are these new facilities with these new technologies, and how will they help operators solve the problem of finding water to use in an expanding sector of the industry? Hydrology The competition for water from users in fracturing and other users is high. According to Ceres, a nonprofit organization that focuses on water scarcity, 41% of wells in the US are in regions with extreme water stress, or areas where more than 80% of available water is being drawn by municipal, agricultural, and industrial users. Although hydraulic fracturing usually accounts for less than 2% of a state’s overall water usage, the figure can be much higher in some locations (Freyman and Salmon 2013).
{"title":"Unconventional Resources: New Facilities Find Solutions to Limited Water Sources","authors":"S. Whitfield","doi":"10.2118/1214-0011-OGF","DOIUrl":"https://doi.org/10.2118/1214-0011-OGF","url":null,"abstract":"It is common knowledge that hydraulic fracturing operations require a lot of water, and as they have become a more vital element of the oil and gas industry, sourcing this water has proven to be a challenge for companies operating in tough terrain. Drought plagues much of the United States, a country with significant hydraulic fracturing activity, and operators have to take hydrology concerns into consideration when constructing facilities in these environments. In most cases, the solution means recycling produced and flowback water and diminishing, or eliminating altogether, the need for fresh water. Depending on the region and its specific challenges, operators are finding unique ways to address the water issue. In the past couple of years, new facilities have been built or repurposed with new technologies that may affect how companies work in water-stressed shale plays in the future. Where are these new facilities with these new technologies, and how will they help operators solve the problem of finding water to use in an expanding sector of the industry? Hydrology The competition for water from users in fracturing and other users is high. According to Ceres, a nonprofit organization that focuses on water scarcity, 41% of wells in the US are in regions with extreme water stress, or areas where more than 80% of available water is being drawn by municipal, agricultural, and industrial users. Although hydraulic fracturing usually accounts for less than 2% of a state’s overall water usage, the figure can be much higher in some locations (Freyman and Salmon 2013).","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"23 1","pages":"11-20"},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87151680","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 few weeks ago, I noticed that someone had viewed my LinkedIn profile. We all have had this happen, and often it will be recruiters or business development professionals looking for contacts, or people who wish to remain anonymous for some reason. (Really? Do not be so sneaky.) But once in a blue moon, it will be an individual from your past with whom you have lost contact. For a brief moment, you take a trip down memory lane and reflect on how that person influenced you. Fortunately, most are positive influences and the recollection brightens your day. The viewer of my profile was one of my first bosses, Keith. He was the senior vice president of sales and marketing for a defense contractor in southern California, where I started my career almost 30 years ago. I remember him being larger than life in both size and presence. He was intimidating initially, but I soon came to realize that although his personality was strong, his management style was fair. He would certainly bust your chops when you made a mistake (I made a lot), but he would also ensure that you recognized the lesson learned from the mistake. I remember submitting an expense report in the early tenure of my position on Keith’s team. Because I was in the field for long periods of time, Keith permitted me to replace a few articles of ruined clothing. The company’s comptroller paged me one afternoon (Al Gore was still inventing the Internet, so email was not yet an option) and proceeded to chew me out for not complying with company procedures. When Keith heard about this, “it hit the fan” and he dressed down the comptroller with me listening to the conference call. The discussion included the signature for approval and why the issue was being addressed with me. After the call, I knew that my boss “had my back.” He looked out for his team. It gave me confidence in executing my job, knowing that no matter how I might mess up ... he would support me. A few years later, another boss affected my career development. Bill was a stickler for the correct writing of reports. Automatic spelling and/or grammar check did not exist on computer programs, so we were left to our own devices to “get it right.” Initially, Bill returned my reports, marked up with red ink and appearing as if they had been used to clean up a gruesome scene from a movie. Over time, I seemed to be getting the hang of it and the red markings became less frequent. It was a challenge to submit a report and to see how few comments were returned. I am fortunate to have been guided and molded by Keith, Bill, and others and have drawn upon their mentoring and management styles throughout my career and in interactions with junior colleagues.
{"title":"The Value of Mentoring in Career Development","authors":"Brad Nelson","doi":"10.2118/1014-0007-OGF","DOIUrl":"https://doi.org/10.2118/1014-0007-OGF","url":null,"abstract":"A few weeks ago, I noticed that someone had viewed my LinkedIn profile. We all have had this happen, and often it will be recruiters or business development professionals looking for contacts, or people who wish to remain anonymous for some reason. (Really? Do not be so sneaky.) But once in a blue moon, it will be an individual from your past with whom you have lost contact. For a brief moment, you take a trip down memory lane and reflect on how that person influenced you. Fortunately, most are positive influences and the recollection brightens your day. The viewer of my profile was one of my first bosses, Keith. He was the senior vice president of sales and marketing for a defense contractor in southern California, where I started my career almost 30 years ago. I remember him being larger than life in both size and presence. He was intimidating initially, but I soon came to realize that although his personality was strong, his management style was fair. He would certainly bust your chops when you made a mistake (I made a lot), but he would also ensure that you recognized the lesson learned from the mistake. I remember submitting an expense report in the early tenure of my position on Keith’s team. Because I was in the field for long periods of time, Keith permitted me to replace a few articles of ruined clothing. The company’s comptroller paged me one afternoon (Al Gore was still inventing the Internet, so email was not yet an option) and proceeded to chew me out for not complying with company procedures. When Keith heard about this, “it hit the fan” and he dressed down the comptroller with me listening to the conference call. The discussion included the signature for approval and why the issue was being addressed with me. After the call, I knew that my boss “had my back.” He looked out for his team. It gave me confidence in executing my job, knowing that no matter how I might mess up ... he would support me. A few years later, another boss affected my career development. Bill was a stickler for the correct writing of reports. Automatic spelling and/or grammar check did not exist on computer programs, so we were left to our own devices to “get it right.” Initially, Bill returned my reports, marked up with red ink and appearing as if they had been used to clean up a gruesome scene from a movie. Over time, I seemed to be getting the hang of it and the red markings became less frequent. It was a challenge to submit a report and to see how few comments were returned. I am fortunate to have been guided and molded by Keith, Bill, and others and have drawn upon their mentoring and management styles throughout my career and in interactions with junior colleagues.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"16 1","pages":"7-8"},"PeriodicalIF":0.0,"publicationDate":"2014-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80848477","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}
{"title":"LLOG’s Delta House - Who Dat Writ Large","authors":"W. Furlow","doi":"10.2118/1014-0030-OGF","DOIUrl":"https://doi.org/10.2118/1014-0030-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"1 1","pages":"30-32"},"PeriodicalIF":0.0,"publicationDate":"2014-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89897123","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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