This document discusses several projects related to optimizing shale production through oriented perforation based on rock type identification. It proposes analyzing drilling and completion data over time to identify pressure differential issues and potential production compartments. Other projects discussed include evaluating new technologies for offshore developments by analyzing how they may impact development plans and reservoir types, justifying investments in isolated control zones to address reservoir issues, and building physical models of reservoirs to aid in instrumentation and dynamic simulation. The document also discusses regional environmental authorities' visions and a proposed methodology for evaluating production technologies under different environmental regulations.
"Drilling" often refers to all aspects of well construction, including drilling, completions, facilities, construction, the asset team, and other groups. Good performance measures drive performance and reduce conflict between these groups, while bad performance measures mislead and confuse. The first key to success is how to communicate drilling performance in terms that answer the questions of executives and managers, which requires a business-focused cross-functional process. The second key to success is to drive operational performance improvement, which requires a different set of measures with sufficient granularity to define actions. Over the past 10 years, a very workable system has evolved through various approaches used in drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance. It has proven that an effective performance measurement system which addresses both executive requirements and operational requirements can both deliver outstanding results, and also communicate those results, with remarkable value to the organization. The basic principles are widely applicable to areas other than drilling.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
The weakness of reservoir simulations is the lack of quantity and quality of the required input; their strength is the ability to vary one parameter at a time. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Adoption of the applied surface-backpressure types of managed pressure drilling (MPD) technologies in deepwater have mainly involved the use of a rotating control device (RCD). The RCD creates a closed drilling system in which the flow out of the well is diverted towards an automated MPD choke manifold (with a high-resolution mass flow meter) that aside from regulating backpressure also increases sensitivity and reduces reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drilling rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling (PMCD) and riser gas mitigation (RGM), has produced improvements not only in drillability and efficiency, but most importantly in process safety. Case histories on how MPD has performed will be presented on the following: • allowed drilling to reach target depth in rank wildcat deepwater wells that have formations prone to severe circulation losses and narrow mud weight windows; • increased drilling efficiency by minimizing non-productive time associated with downhole pressure-related problems and by allowing for the setting of deeper casing seats; • enhanced operational and process safety by allowing for immediate detection of kicks, losses and other critical downhole events. • provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream, and not after it has already broken out above the rig blow-out preventers (BOPs).
Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge.
This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations.
This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low permeability brown oil field was selected to retroactively demonstrate the workflows, as it had an evident workover campaign in late 2010 with subsequent production increase. Using data as of mid-2010, approximately 40 wells were identified as under-performing due to formation damage or water production problems, based on three days of analyses. The actual performance of the field three years later was then revealed along with the actual interventions performed. The selection of wells is compared to the selection suggested by the workflow, and the results of the interventions are shown. The field's projected recovery factor was increased by 5%, representing a gain of 1.4 million barrels of oil.
We are all familiar with the production systems through which reservoir fluids flow to reach our processing facilities. This is a journey characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. A monumental amount of research and development work has been invested towards better understanding multiphase flow behavior over the past fifty years. Yet, many challenges remain as we strive to optimize ever more complex production systems fraught with difficult flow assurance issues. Just how good is the science? And more importantly, how does this impact our bottom line? This lecture will discuss key concepts of multiphase flow leading to the current “state-of-the-art” models used today. Looking towards the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategies. Recommendations will be presented covering the top 5 areas of research necessary for these purposes. The economic impact of multiphase operations will be illustrated using two examples that provide insight towards maximizing asset value.
Mack Shippen is a Principal Engineer with Schlumberger in Houston, where he is responsible for the global business of the PIPESIM multiphase flow simulation software. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of reservoir and surface simulation models. He has served on a number of SPE committees and chaired the SPE Reprint Series on Offshore Multiphase Production Operations. He holds BS and MS degrees in Petroleum Engineering from Texas A&M University, where his research focused on multiphase flow modelling.
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
"Drilling" often refers to all aspects of well construction, including drilling, completions, facilities, construction, the asset team, and other groups. Good performance measures drive performance and reduce conflict between these groups, while bad performance measures mislead and confuse. The first key to success is how to communicate drilling performance in terms that answer the questions of executives and managers, which requires a business-focused cross-functional process. The second key to success is to drive operational performance improvement, which requires a different set of measures with sufficient granularity to define actions. Over the past 10 years, a very workable system has evolved through various approaches used in drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance. It has proven that an effective performance measurement system which addresses both executive requirements and operational requirements can both deliver outstanding results, and also communicate those results, with remarkable value to the organization. The basic principles are widely applicable to areas other than drilling.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
The weakness of reservoir simulations is the lack of quantity and quality of the required input; their strength is the ability to vary one parameter at a time. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Adoption of the applied surface-backpressure types of managed pressure drilling (MPD) technologies in deepwater have mainly involved the use of a rotating control device (RCD). The RCD creates a closed drilling system in which the flow out of the well is diverted towards an automated MPD choke manifold (with a high-resolution mass flow meter) that aside from regulating backpressure also increases sensitivity and reduces reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drilling rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling (PMCD) and riser gas mitigation (RGM), has produced improvements not only in drillability and efficiency, but most importantly in process safety. Case histories on how MPD has performed will be presented on the following: • allowed drilling to reach target depth in rank wildcat deepwater wells that have formations prone to severe circulation losses and narrow mud weight windows; • increased drilling efficiency by minimizing non-productive time associated with downhole pressure-related problems and by allowing for the setting of deeper casing seats; • enhanced operational and process safety by allowing for immediate detection of kicks, losses and other critical downhole events. • provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream, and not after it has already broken out above the rig blow-out preventers (BOPs).
Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge.
This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations.
This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low permeability brown oil field was selected to retroactively demonstrate the workflows, as it had an evident workover campaign in late 2010 with subsequent production increase. Using data as of mid-2010, approximately 40 wells were identified as under-performing due to formation damage or water production problems, based on three days of analyses. The actual performance of the field three years later was then revealed along with the actual interventions performed. The selection of wells is compared to the selection suggested by the workflow, and the results of the interventions are shown. The field's projected recovery factor was increased by 5%, representing a gain of 1.4 million barrels of oil.
We are all familiar with the production systems through which reservoir fluids flow to reach our processing facilities. This is a journey characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. A monumental amount of research and development work has been invested towards better understanding multiphase flow behavior over the past fifty years. Yet, many challenges remain as we strive to optimize ever more complex production systems fraught with difficult flow assurance issues. Just how good is the science? And more importantly, how does this impact our bottom line? This lecture will discuss key concepts of multiphase flow leading to the current “state-of-the-art” models used today. Looking towards the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategies. Recommendations will be presented covering the top 5 areas of research necessary for these purposes. The economic impact of multiphase operations will be illustrated using two examples that provide insight towards maximizing asset value.
Mack Shippen is a Principal Engineer with Schlumberger in Houston, where he is responsible for the global business of the PIPESIM multiphase flow simulation software. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of reservoir and surface simulation models. He has served on a number of SPE committees and chaired the SPE Reprint Series on Offshore Multiphase Production Operations. He holds BS and MS degrees in Petroleum Engineering from Texas A&M University, where his research focused on multiphase flow modelling.
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
Slide deck used during the SPE Live broadcast on 19 August 2020 with guest Doug Peacock, 2010-11 SPE Distinguished Lecturer and currently a Technical Director for GaffneyCline.
WATCH VIDEO: https://youtu.be/ykJhFkNUXqc
TRAINING COURSE: http://go.spe.org/peacockSPELIVE
The unitization process has evolved over the years and is now well established throughout the world with many countries having legislation for unitization.
Although there are generic agreements, each unitization agreement is unique and requires a wide range of issues to be considered.
Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs, small and large. Calculation and estimation of reserves continues to be a necessary process to properly assess the value and manage the development of an oil and gas producer’s assets. These methods of analysis, while generally done for different purposes, require knowledge and expertise by the analyst (typically a reservoir engineer) to arrive at meaningful and reliable results. Increasingly, the simulation tool is being incorporated into the reserves process. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This discussion highlights some of the important facets one should consider when applying numerical simulation methods to use for, or augment, reserves estimates. The main take away will be an appreciation for the areas to focus on to arrive at meaningful and defendable estimates of reserves that are based on reservoir models.
Each year, companies use averaged well production (type wells) to support billion dollar expenditures to buy and develop oil and gas resources. These type wells often have unrepresentative rate-time profiles and recoveries over-stated by as much as 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Literature related to constructing type wells is sparse and incomplete. This lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hind casting examples show that only small errors in recovery result when the type well construction combines historical and predicted production rates. This improvement results from using educated estimates (not intrinsic values) for months with no data to average, and from individual well forecast errors that offset one another. A Monte Carlo method incorporates risk and leads to better well selection and weighting factors, achieving more representative rate-time profiles. The recommended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is important because it makes little sense to risk recovery (e.g., P90 for proved reserves) when the application demands a different parameter such as present value. Type well construction methods are common, but they have errors that are difficult to detect. Evaluators are likely using type wells for financial analysis, facility design, cash flow prediction, reserve estimation and debt financing without knowledge of the inaccuracies and options to improve accuracy.
Heavy Oil recovery traditionally starts with depletion drive and (natural) waterdrive with very low recoveries as a result. As EOR technique, steam injection has been matured since the 1950s using CSS (cyclic steam stimulation), steam drive or steam flooding, and SAGD (steam assisted gravity drainage). The high energy cost of heating up the oil bearing formation to steam temperature and the associated high CO2 footprint make steam based technology less attractive today and many companies in the industry have been actively trying to find alternatives or improvements. As a result there are now many more energy efficient recovery technologies that can unlock heavy oil resources compared with only a decade ago. This presentation will discuss breakthrough alternatives to steam based recovery as well as incremental improvement options to steam injection techniques. The key message is the importance to consider these techniques because steam injection is costly and has a high CO2 footprint
Johan van Dorp holds an MSc in Experimental Physics from Utrecht University and joined Shell in 1981. He has served on several international assignments, mainly in petroleum and reservoir engineering roles. He recently led the extra heavy-oil research team at the Shell Technology Centre in Calgary, focusing on improved in-situ heavy-oil recovery technologies. Van Dorp also was Shell Group Principal Technical Expert in Thermal EOR and has been involved with most thermal projects in Shell throughout the world, including in California, Oman, the Netherlands, and Canada. He retired from Shell after more than 35 years in Oct 2016. Van Dorp (co-)authored 13 SPE papers on diverse subjects.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Reserve Estimation of Initial Oil and Gas by using Volumetric Method in Mann ...ijtsrd
This research paper is focused to estimate the current production rate of the wells and to predict field remaining reserves. The remaining reserve depends on the production points that selected to represent the real well behavior, the way of dealing with the production data, and the human errors that might happen during the life of the field. Reserves estimating methods are usually categorized into three families analogy, volumetric, and performance techniques. Reserve Estimators should utilize the particular methods, and the number of methods, which in their professional judgment are most appropriate given i the geographic location, formation characteristics and nature of the property or group of properties with respect to which reserves are being estimated ii the amount and quality of available data and iii the significance of such property or group of properties in relation to the oil and gas properties with respect to which reserves are being estimated. In this research paper, the calculation of collecting data and sample by volumetric method are suggested to estimate the oil and gas production rate with time by using the geological configuration and the historical production data from CD 3700 3800 sand in Mann Oil Field. San Win "Reserve Estimation of Initial Oil and Gas by using Volumetric Method in Mann Oil Field" Published in International Journal of Trend in Scientific Research and Development (ijtsrd), ISSN: 2456-6470, Volume-3 | Issue-5 , August 2019, URL: https://www.ijtsrd.com/papers/ijtsrd27945.pdfPaper URL: https://www.ijtsrd.com/engineering/petroleum-engineering/27945/reserve-estimation-of-initial-oil-and-gas-by-using-volumetric-method-in-mann-oil-field/san-win
PENNGLEN FIELD Development Plan (GULF of MEXICO)PaulOkafor6
A FDP designed with the goal to define the development scheme that allows the optimization of the hydrocarbon recovery at a minimal cost for project sanction
This was designed by MSc Students from the Institute of Petroleum Studies, UNIPORT/ IFP School, France
Field development plan, rate of production,SYED NAWAZ
It gives you an idea about an impact of reservoir damage on production rate
Hello Everyone,
Follow my youtube channel "PETROLEUM UNIVERSE" https://lnkd.in/gjZgb7E
For weekly brushing of basics follow me on linkedin
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Follow and Subscribe only if you like and try to circulate among your friends
Water coning is a serious issue for the oil and gas industry. This poses a big
concern regarding the costs that to be incurred for separation and equipment
capacity. Coning is the production of an unwanted phase with a desired phase. Over
the years, many techniques and control methods has been birthed, however, the issue
of coning can only be mitigated and not completely discharged. Reservoir and
production engineers need to understand the basic framework; the parameters that
greatly influence coning and how effective manipulation of it can deal with it. With the
introduction of horizontal wells, the production rate is two to four times that of
vertical wells, and coning is reduced and the breakthrough time is increased.
Numerous papers has been written regarding to coning and vertical wells, only a few
emphasize on horizontal wells and simultaneous water coning and gas coning. The
objective of this research is to study the post breakthrough performance in
simultaneous coning and a black oil simulator was use for the research. Sensitivity
analysis was carried out on: the production rate of oil (qt), horizontal permeability,
vertical permeability, perforation length, the height above perforation, extent of
reservoir area and the formation porosity. A generalized correlation was developed
for predicting coning behavior using non-linear analysis
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technol...ASC-HRSC
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technologies
This presentation was given at the AEHS 33rd Annual International Conference on Soils, Sediments, Water, and Energy on October 18, 2017, at UMASS, Amherst, Massachusetts
http://www.aehsfoundation.org/east-coast-conference.aspx
Session 15: Synergistic Remediation Technology Solutions
Day: Wednesday, October 18, 2017
Time: 1:30 PM - 5:00 PM
Location: Room 168
Session Type: Platform Session
Slide deck used during the SPE Live broadcast on 19 August 2020 with guest Doug Peacock, 2010-11 SPE Distinguished Lecturer and currently a Technical Director for GaffneyCline.
WATCH VIDEO: https://youtu.be/ykJhFkNUXqc
TRAINING COURSE: http://go.spe.org/peacockSPELIVE
The unitization process has evolved over the years and is now well established throughout the world with many countries having legislation for unitization.
Although there are generic agreements, each unitization agreement is unique and requires a wide range of issues to be considered.
Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs, small and large. Calculation and estimation of reserves continues to be a necessary process to properly assess the value and manage the development of an oil and gas producer’s assets. These methods of analysis, while generally done for different purposes, require knowledge and expertise by the analyst (typically a reservoir engineer) to arrive at meaningful and reliable results. Increasingly, the simulation tool is being incorporated into the reserves process. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This discussion highlights some of the important facets one should consider when applying numerical simulation methods to use for, or augment, reserves estimates. The main take away will be an appreciation for the areas to focus on to arrive at meaningful and defendable estimates of reserves that are based on reservoir models.
Each year, companies use averaged well production (type wells) to support billion dollar expenditures to buy and develop oil and gas resources. These type wells often have unrepresentative rate-time profiles and recoveries over-stated by as much as 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Literature related to constructing type wells is sparse and incomplete. This lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hind casting examples show that only small errors in recovery result when the type well construction combines historical and predicted production rates. This improvement results from using educated estimates (not intrinsic values) for months with no data to average, and from individual well forecast errors that offset one another. A Monte Carlo method incorporates risk and leads to better well selection and weighting factors, achieving more representative rate-time profiles. The recommended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is important because it makes little sense to risk recovery (e.g., P90 for proved reserves) when the application demands a different parameter such as present value. Type well construction methods are common, but they have errors that are difficult to detect. Evaluators are likely using type wells for financial analysis, facility design, cash flow prediction, reserve estimation and debt financing without knowledge of the inaccuracies and options to improve accuracy.
Heavy Oil recovery traditionally starts with depletion drive and (natural) waterdrive with very low recoveries as a result. As EOR technique, steam injection has been matured since the 1950s using CSS (cyclic steam stimulation), steam drive or steam flooding, and SAGD (steam assisted gravity drainage). The high energy cost of heating up the oil bearing formation to steam temperature and the associated high CO2 footprint make steam based technology less attractive today and many companies in the industry have been actively trying to find alternatives or improvements. As a result there are now many more energy efficient recovery technologies that can unlock heavy oil resources compared with only a decade ago. This presentation will discuss breakthrough alternatives to steam based recovery as well as incremental improvement options to steam injection techniques. The key message is the importance to consider these techniques because steam injection is costly and has a high CO2 footprint
Johan van Dorp holds an MSc in Experimental Physics from Utrecht University and joined Shell in 1981. He has served on several international assignments, mainly in petroleum and reservoir engineering roles. He recently led the extra heavy-oil research team at the Shell Technology Centre in Calgary, focusing on improved in-situ heavy-oil recovery technologies. Van Dorp also was Shell Group Principal Technical Expert in Thermal EOR and has been involved with most thermal projects in Shell throughout the world, including in California, Oman, the Netherlands, and Canada. He retired from Shell after more than 35 years in Oct 2016. Van Dorp (co-)authored 13 SPE papers on diverse subjects.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Reserve Estimation of Initial Oil and Gas by using Volumetric Method in Mann ...ijtsrd
This research paper is focused to estimate the current production rate of the wells and to predict field remaining reserves. The remaining reserve depends on the production points that selected to represent the real well behavior, the way of dealing with the production data, and the human errors that might happen during the life of the field. Reserves estimating methods are usually categorized into three families analogy, volumetric, and performance techniques. Reserve Estimators should utilize the particular methods, and the number of methods, which in their professional judgment are most appropriate given i the geographic location, formation characteristics and nature of the property or group of properties with respect to which reserves are being estimated ii the amount and quality of available data and iii the significance of such property or group of properties in relation to the oil and gas properties with respect to which reserves are being estimated. In this research paper, the calculation of collecting data and sample by volumetric method are suggested to estimate the oil and gas production rate with time by using the geological configuration and the historical production data from CD 3700 3800 sand in Mann Oil Field. San Win "Reserve Estimation of Initial Oil and Gas by using Volumetric Method in Mann Oil Field" Published in International Journal of Trend in Scientific Research and Development (ijtsrd), ISSN: 2456-6470, Volume-3 | Issue-5 , August 2019, URL: https://www.ijtsrd.com/papers/ijtsrd27945.pdfPaper URL: https://www.ijtsrd.com/engineering/petroleum-engineering/27945/reserve-estimation-of-initial-oil-and-gas-by-using-volumetric-method-in-mann-oil-field/san-win
PENNGLEN FIELD Development Plan (GULF of MEXICO)PaulOkafor6
A FDP designed with the goal to define the development scheme that allows the optimization of the hydrocarbon recovery at a minimal cost for project sanction
This was designed by MSc Students from the Institute of Petroleum Studies, UNIPORT/ IFP School, France
Field development plan, rate of production,SYED NAWAZ
It gives you an idea about an impact of reservoir damage on production rate
Hello Everyone,
Follow my youtube channel "PETROLEUM UNIVERSE" https://lnkd.in/gjZgb7E
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Water coning is a serious issue for the oil and gas industry. This poses a big
concern regarding the costs that to be incurred for separation and equipment
capacity. Coning is the production of an unwanted phase with a desired phase. Over
the years, many techniques and control methods has been birthed, however, the issue
of coning can only be mitigated and not completely discharged. Reservoir and
production engineers need to understand the basic framework; the parameters that
greatly influence coning and how effective manipulation of it can deal with it. With the
introduction of horizontal wells, the production rate is two to four times that of
vertical wells, and coning is reduced and the breakthrough time is increased.
Numerous papers has been written regarding to coning and vertical wells, only a few
emphasize on horizontal wells and simultaneous water coning and gas coning. The
objective of this research is to study the post breakthrough performance in
simultaneous coning and a black oil simulator was use for the research. Sensitivity
analysis was carried out on: the production rate of oil (qt), horizontal permeability,
vertical permeability, perforation length, the height above perforation, extent of
reservoir area and the formation porosity. A generalized correlation was developed
for predicting coning behavior using non-linear analysis
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technol...ASC-HRSC
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technologies
This presentation was given at the AEHS 33rd Annual International Conference on Soils, Sediments, Water, and Energy on October 18, 2017, at UMASS, Amherst, Massachusetts
http://www.aehsfoundation.org/east-coast-conference.aspx
Session 15: Synergistic Remediation Technology Solutions
Day: Wednesday, October 18, 2017
Time: 1:30 PM - 5:00 PM
Location: Room 168
Session Type: Platform Session
I have 2years of Experience as Planning Engineer in Featherlie office system, i Have experiance in Design also tools are AutoCAD and Solidworks, and I know about Production and Costing of sheet Metal Components as Mentioned in CV
வெற்றி = பணம் என்று வாதத்திற்கு ஒப்புக் கொண்டால்
அந்த பணத்தை அடைய CASH என்பதிற்கு பதிலாக KASH என்பதை
நீங்கள் வளர்த்தல் வேண்டும்.
அது என்ன KASH ?
K = KNOWLEDGE = அறிவு
A = ATTITUDE = மனப்பான்மை
S = SKILL = திறமை
H = HABIT = பழக்கம்
இவை தான் உங்கள் வெற்றியை தீர்மானிக்கும் .
ஏன்? எதற்கு? எங்கே? எப்பொழுது?
ஏன்?
உங்கள் வியாபார வளர்சிக்கு தேவையான தொழில் வளக்கலை.
எதற்கு?
1.விற்பனை அதிகரிக்க.....
2.மார்க்கெட்டிங் துறை சார்ந்த அனைத்து பிரச்சனைகளுக்கும் சரியான வழிகாட்டுதல்.
3.புதிய தயாரிப்புகளை சந்தைபடுத்த தேவையான ட்ரைனிங் .......
4.உங்கள் தயாரிப்புகளுக்கு தனி ப்ரண்ட் அங்கிகாரம் பெற தேவையான ட்ரைனிங் ....
5.ஸ்டார்ட் அப் தொழில் அமைப்புகளுக்கு தங்கள் தயாரிப்புகள் மார்க்கெட்டிங் செய்ய தேவையான அனைத்து மார்க்கெட்டிங் ட்ரைனிங் நாங்கள் உங்களுக்கு தருகிறோம்.
மனிதவளத்துறை சார்ந்த வழிகாட்டுதல்.
செயல் திறன் மேம்பாடு ஒன்று மட்டுமே உங்கள் தொழில் வெற்றிக்கு வழிவகுக்கும்.
1. நீங்கள் யார் உங்களுக்குள் இருக்கும் பிரச்சனைகளுக்கு சரியானவழிகாட்டுதல்.
2.உங்கள் முடிவு எடுக்கும் முறை ஒழுங்குபடுத்த
3.உங்கள் தாழ்வு மனப்பான்மை மாற
4.உங்கள் வியாபார வெற்றிக்கு தேவையான அனைத்து ட்ரைனிங் எங்களிடம் உள்ளது.
எங்கே?
உங்களுக்கா உங்களிடத்தில்.
எப்பொழுது?
உங்கள் வெற்றிக்கான நாளை நீங்களே தீர்மானியுங்கள்.
நாளைய அறிவு இன்றய வெற்றி.
அணுகவும்
கௌசிகா கன்சல்டண்சி ர.ராஜாராம் - 9865118262
kowshikaa2009@gmail.com
Status RH Promo - Acessem nosso Site o Confira nossos Trabalhos e Ações Promocionais - www.statusrhpromo.com - LIVE MARKETING
A Status RH Promo há mais de 12 anos atua nas áreas de Recursos Humanos, Gestão de Pessoas e Marketing Promocional no Rio Grande do Norte.
Principais Serviços: Recursos Humanos, Gestão de Pessoas, Marketing Promocional, Ações em PDV, Ações de Exomarketing e Endomarketing.
A empresa Status RH Promo possui cobertura e Suporte em todo o Rio Grande do Norte.
www.statusrhpromo.com
Il Giornale, Pronti per il mondo delle professioni - Speciale Diritto e Fisco...StudioCassone
Affrontare preparati le nuove sfide dell’universo lavorativo. L’importanza della consulenza e di una formazione dettagliata e completa per essere all’altezza di un sapere multidisciplinare. L’analisi di Giuseppe Cassone, fondatore ed amministratore di G11
The significance of Surface Logging For The Formation Evaluation Advance Surf...Evangelos Siskos
The significance of Surface Logging For The Formation Evaluation Advance Surface Logging Technology is a Master of Science Thesis presentation for the MSc in Oil & Gas Technology program at Eastern Macedonia and thrace Institute of Technology.
Breaking Paradigms in old Fields. Finding “the reservoir key” for Mature Fiel...Juan Diego Suarez Fromm
Two field examples will be presented, where after 50 years of development; fresh oil and gas were produced by changing some reservoir paradigms.
Upsides could be overlooked due to paradigms on field development. The successful one in terms of reserves and cost effective capital expenditure could be visualized as “finding the key for the field”. But as development takes place over many years (decades), the “key” should be a dynamic concept over time, correlated with technology availability, enabling us a better understanding of petroleum resources size, quality and distribution.
Drilling fluids are absolutely essential during the drilling process and considered the primary well control.
Know more now about such a very important component of the drilling process.
1. Shale Perforation Optimization
Oriented perforation (Stress/Strain) + Reservoir Rock Type Identification (FZI)
0
5
10
15
20
25
30
0 1 2 3 4 5
gas + clay
oil/gas
oil + sand
B
o
t
t
o
n
H
o
l
e
P
r
e
s
s
u
r
e
Interval with more potential to reduce gas production
and decrease production problems in shale reservoirs: Rock type window
Production potential
Project Objective: to propose a methodology to optimize
production thought oriented rock type perforation
Reservoir Pressure
2. Proposed Rock type Analysis
Reservoir Pressure
Bottom
Hole
Pressure
Rock type window ?
Oriented rock type perforation
Rock
Type
Rock Strength
Rock type vs. Rock Strength
Rock type window
3. Pressure Differential Project
To analyze Drilling & Completion Evolution trough time in the
Tectono/stratigraphic & dynamic framework to show up potential compartments
Y x y
x
y
x
y
x
y
x Y x
Year 1 Year 2 Year 3
Oil well
Gas
Water
M
a
p
v
i
e
w
c
r
o
s
s
s
e
c
t
i
o
n
Shale sand
Compartment due to production
Potential pressure
differential problem
A B
A
B
A
A C B
C
B
A D C B
A D C
B
Smart well
candidate
4. Technology Development Project
• Review of offshore Exploration &
development plans
• Technological Risk analysis
– To extrapolate exploration
geology risk analysis techniques
to evaluate production
technologies potential
application
– Identify variables (technology &
reservoir types scenarios) that
will have technical/economical
impact in their development
plans
Technology A
Technology B
Technology C
High Risk
Example Development Plan
Technology vs. Reservoir type framework
0
5
1 0
1 5
2 0
2 5
3 0
3 5
4 0
scena.1
scena.2
scena.3
v a r . 1
v a r . 2
v a r . 3
Sce. 3
Sce. 2
Sce. 1
5. 1,866’
1,320’
Development Plan with New Technology
1,866’
100
1000
10000
100000
RESERVES (MMBOE) 100%:11.1
CAPEX (MM$):35.2
DCFROI (%):24
F & D COST ($/BOE):3.15
BWPD
BOPDB
OPD
MCFPD
MULTILATERAL
DRILLING
CO2
INJECTION
Conventional wells Multilateral Wells
New Development
Plan with New
Technology
MTL Case Study
Carbonate
reservoir
6. Intelligent Wells. Isolated Control Zone (ICZ) Project
• How to justify Investment?
– Evaluation of current reservoir
problems that may be
prevent/reduce using ICZ
– Well design. ICZ size &
placement possibilities
– Evaluation of risk factors (choke
erosion, formation strength
variability, asphaltenes, sand
production, perforation design)
– ICZ cost/benefit & reliability
analysis
Reservoir Reservoir
Without ICZ With ICZ
+ $$$
To show technical/economical
benefits of the ICZ in the
same reservoir type scenario
> Technical Benefits
Discounted
Cash flow
< Technical Benefits
< Discounted
Cash flow
7. Instrumented Oilfield Project
If we have a 3D cube with good resolution, may we build a transparent physical
model at scale that represent the reservoir and their internal heterogeneities?
In this way:
•We can see the physical dimension and distribution
of the objects and we may see the fluid contacts
moving
•We may reduce uncertainty in the static model
•We may instrumented the reservoir using its truly
shape and heterogeneities.
•Operators may build their own particular static
model
•It can be used to simulate 4D (Drilling Simulator) and
dynamic process
Reservoir
Gas contact
Oil rim
Water Contact
8. Drilling cost
Completion cost
Simple
waterfr
ont
moveme
nt model
SIP 2.4
Valves/chokes:
Lifecycle
reliability
model,
SIP 1.4
+pressure drop
Random
geological
surprises
Simple
gasfront
moveme
nt model
SIP 2.4
Resid
ual
oil
mode
l?
SIP
2.4
LWD information
Surprise handling (FN)
Water breakout (SM)
Smart Assets Value Evaluation tool - Geological surprises evaluation using Monte Carlo simulation
Techno-Economic Decision support tools for technology
assessment
Injector
Producer
Target Fore cast: Surprise handling
rockstrength .54
Rocktypes .52
Rockwettability .49
layers .05
internal barriers .01
-1 -0.5 0 0.5 1
Measured byRank Correlation
Sensitivity ChartDecision
variables
Assumptions
Variability
Uncertainty
Forecast
Injector
Injection points
Valves/chokes
Zonal flow sensors
Producer
Drainage point
Valves/chokes producer
Permanent resistivity sensors
Interwell data
Distance between wells
Completed interval
Perforation
rock types
rock wettability
rock strenght
pore pressure
barriers
layers
Surprise handling
Water Breakout
9. Authorities Vision
Regional Environmental Impact – Region I
UNEP (United Nations environmental Program):
• Oil Pollution has a moderate impact on food security,
quantification and monitoring of this impact is needed
to avoid human health impact
• To Improve accidental response impact analysis of toxic
substances
NPD (Norwegian Petroleum Directorate), Ministry of Environment:
• Clean Technologies will be rewarded with subsidies
and tax allowances, main goal: zero discharge of solids
• To reduce water production to 50% with new technology
• Tools to measure, control and monitor environmental impact
OSPAR (Oslo-Paris environmental legislation):
• Improvement in each cycle of Offshore technology
management ( avoidance, reduction, re-use, recycling,
recovery, residue disposal)
• Waste management
SFT (Norwegian Pollution Control Authority):
• Prioritisation or substitution of hazardous substances
• Better quality control of local spills, reduce contamination
of estuaries and artic zones
10. Production Geology Approach applied to Environmental Risk
Assessment
• Reduction of Number of Wells
• Review of technological options and development plans to reduce the
environmental impact of
•Production /injection management
• Water / Gas Handling
• Zero Discharge Policy
• Improvement in the technology Management Life cycle ( avoidance,
reduction, re-use, recycling, recovery, disposal)
• Novel control, monitoring and measurement environmental Oil & Gas
Solutions
11. Production Technology Evaluation Methodology
Alaska, USA
Development plans under
environmental regulations
GOM
Improve productivity in Salt tectonic
Hidrates, Ultradeep water development
Mutilayer with pressure
differential
CANADA
North Sea ,UK (Pressure maintenance, oil rims, drainage optimization, contact movement monitoring, water/gas coning, hydrates)
Improvement drainage strategies, gas development, L/V pressure distribution and transmissibility,WAG, deeper waters, water/gas coning,sand control)
North and Norwegian Sea, Norway
Deepwater Exploratory
NIGERIA
VENEZUELA
WAG, potential offshore development
Pressure maintenance, gas development,monitoring water cuts, ANGOLA
CONGO
Deep water sand reservoirs
Deepwater plans
GUINEA
Fractured reservoir,ITALY
Deepwater Development plans,
BRAZIL
AUSTRALIA
Environmental regulations
Heavy oil underlying by strong aquifers
Oman
Production Geology Approach
Technical/Economical
Ranking matrix
(Technology vs.
Reservoir/Geology Scenarios)