Heterogeneus deep carbonate reservoirs require enhanced development strategies to maximize reservoir contact and ultimately to increase the recovery factor. In some complex carbonate reservoirs, conventional strategies for reservoir development are not always the best choice and new technologies have to be applied to optimize the reservoir development. In such cases, underbalanced coiled tubing drilling (UBCTD) has proven to be a suitable approach to exploit more complex reservoir areas, where conventional drilling and stimulation techniques no always meet well productivity expectations. The UBCTD technology consists of drilling a well with a drilling fluid pressure lower than the reservoir pressure, which tends to minimize the formation damage. Due to the underbalanced condition imposed in the wellbore, the well is allowed to flow naturally during drilling, while its productivity is measured. Another technique that accompanies this strategy is called bio-steering, in which cuttings are inspected while drilling to detect micro-fossils from the reservoir. Based on the real-time well productivity and the micro-fossils appearance, the well trajectory can be adjusted and corrected during drilling to chase the good wellbore productivity layers. A number of wells has been drilled using this strategy with encouraging results so far, which opens a great window to continue exploiting the reservoirs under development. With this technology, multilateral placement is possible with a high degree of accuracy across thin reservoir layers, which maximize the reservoir contact and increases the well productivity. This work presents a general description of this technology as well as present a successful field case including all stages from well planning to well execution and testing.
{"title":"Application of Underbalanced Coiled Tubing Drilling Technology to Enhance Gas Production in Deep Carbonate Reservoirs","authors":"Pablo Guizada, Z. Rahim, Bodour Aliraani","doi":"10.2118/192786-MS","DOIUrl":"https://doi.org/10.2118/192786-MS","url":null,"abstract":"\u0000 Heterogeneus deep carbonate reservoirs require enhanced development strategies to maximize reservoir contact and ultimately to increase the recovery factor. In some complex carbonate reservoirs, conventional strategies for reservoir development are not always the best choice and new technologies have to be applied to optimize the reservoir development. In such cases, underbalanced coiled tubing drilling (UBCTD) has proven to be a suitable approach to exploit more complex reservoir areas, where conventional drilling and stimulation techniques no always meet well productivity expectations.\u0000 The UBCTD technology consists of drilling a well with a drilling fluid pressure lower than the reservoir pressure, which tends to minimize the formation damage. Due to the underbalanced condition imposed in the wellbore, the well is allowed to flow naturally during drilling, while its productivity is measured. Another technique that accompanies this strategy is called bio-steering, in which cuttings are inspected while drilling to detect micro-fossils from the reservoir. Based on the real-time well productivity and the micro-fossils appearance, the well trajectory can be adjusted and corrected during drilling to chase the good wellbore productivity layers.\u0000 A number of wells has been drilled using this strategy with encouraging results so far, which opens a great window to continue exploiting the reservoirs under development. With this technology, multilateral placement is possible with a high degree of accuracy across thin reservoir layers, which maximize the reservoir contact and increases the well productivity. This work presents a general description of this technology as well as present a successful field case including all stages from well planning to well execution and testing.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75729336","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}
3D geocellular static models are the key input for fluid flow simulations with the main aim to predict the future reservoir performance for a particular recovery scheme. Since the predictability of the dynamic model depends on the quality of the geocellular model, it is imperative that the input data, the modelling workflow, methodologies and approaches are verified and validated prior to the sanction of the geocellular model. The objective of this paper is therefore to discuss the process of performing quality assurance and quality control (QA/QC) of 3D geocellular models exhibiting real field examples from the Middle East carbonate reservoirs. 3D static models are built using data from multiple sources, at different scales and with different degrees of uncertainty. The validation and reconciliation of all the data is of paramount importance. The procedure to build any geological model is very similar provided all the data is available. Some variations in the procedure are expected depending on the complexity of the phenomena to model, but must of the time workflows divert based on data quality and data availability. In this paper we discuss the use of key validation checks for each step of the modelling process taking into account the data quality and field maturity, namely for the 1)- structural framework modelling, 2)- facies modelling, 3)- porosity modelling, 4)- permeability modelling, 5)- rock type modelling, 6)- water saturation modelling, 7)- upscaling and 8)- uncertainty analysis. The use and validation of the applicability of secondary variables in the petrophysical modelling, such as acoustic impedance from seismic inversion, is also addressed. From the analysis of multiple geocellular models, inconsistencies were detected at different stages of the modelling process, starting from the well surveying with implications to horizontal well positioning within the framework, to the modelling of facies and petrophysical properties, with inconsistencies on variogram model parameters. Also, the validation of the velocity modelling and time-depth conversion used for the structural framework was validated by comparing FWLs depths against spill points. Furthermore, the quality of the facies model could be verified against regional facies belt maps (similar variogram azimuths are expected) while the validation of the permeability scale-up at well level could be achieved by reconciling with well test kh data. These are just a few examples of the material discussed in this paper. The novelty of the quality assurance process pertained to 3D geological models is the identification of appropriate metrics with key performance indicators for each step in the modelling workflow. At the end of the QA/QC process the models are ranked in quality and technical gaps identified for subsequent model improvement. Guidelines and best practices are also presented in this paper.
{"title":"Quality Control of 3D GeoCellular Models: Examples from UAE Carbonate Reservoirs","authors":"J. Gomes, Humberto Parra, Dipankar Ghosh","doi":"10.2118/193128-MS","DOIUrl":"https://doi.org/10.2118/193128-MS","url":null,"abstract":"\u0000 3D geocellular static models are the key input for fluid flow simulations with the main aim to predict the future reservoir performance for a particular recovery scheme. Since the predictability of the dynamic model depends on the quality of the geocellular model, it is imperative that the input data, the modelling workflow, methodologies and approaches are verified and validated prior to the sanction of the geocellular model. The objective of this paper is therefore to discuss the process of performing quality assurance and quality control (QA/QC) of 3D geocellular models exhibiting real field examples from the Middle East carbonate reservoirs.\u0000 3D static models are built using data from multiple sources, at different scales and with different degrees of uncertainty. The validation and reconciliation of all the data is of paramount importance. The procedure to build any geological model is very similar provided all the data is available. Some variations in the procedure are expected depending on the complexity of the phenomena to model, but must of the time workflows divert based on data quality and data availability. In this paper we discuss the use of key validation checks for each step of the modelling process taking into account the data quality and field maturity, namely for the 1)- structural framework modelling, 2)- facies modelling, 3)- porosity modelling, 4)- permeability modelling, 5)- rock type modelling, 6)- water saturation modelling, 7)- upscaling and 8)- uncertainty analysis. The use and validation of the applicability of secondary variables in the petrophysical modelling, such as acoustic impedance from seismic inversion, is also addressed.\u0000 From the analysis of multiple geocellular models, inconsistencies were detected at different stages of the modelling process, starting from the well surveying with implications to horizontal well positioning within the framework, to the modelling of facies and petrophysical properties, with inconsistencies on variogram model parameters. Also, the validation of the velocity modelling and time-depth conversion used for the structural framework was validated by comparing FWLs depths against spill points. Furthermore, the quality of the facies model could be verified against regional facies belt maps (similar variogram azimuths are expected) while the validation of the permeability scale-up at well level could be achieved by reconciling with well test kh data. These are just a few examples of the material discussed in this paper.\u0000 The novelty of the quality assurance process pertained to 3D geological models is the identification of appropriate metrics with key performance indicators for each step in the modelling workflow. At the end of the QA/QC process the models are ranked in quality and technical gaps identified for subsequent model improvement. Guidelines and best practices are also presented in this paper.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"106 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74504008","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}
Fabio Gonzalez, Doris L. González, Steve P. Carmichael, C. Stewart, M. Pietrobon, Francisco Orlando Garzon
Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment. Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis. A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates. This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.
{"title":"A Success Story of Production Improvement in a Deepwater GoM Field Based on Integration of Surveillance Techniques","authors":"Fabio Gonzalez, Doris L. González, Steve P. Carmichael, C. Stewart, M. Pietrobon, Francisco Orlando Garzon","doi":"10.2118/192843-MS","DOIUrl":"https://doi.org/10.2118/192843-MS","url":null,"abstract":"\u0000 Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment.\u0000 Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.\u0000 A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates.\u0000 This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73634969","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}
Acquiring seismic data with S4 (Single Source, Single Sensor) is proven technology and it has many advantages over the conventional source and receiver array acquisition type. The array has an intra array statics issue when deployed on large elevation variation such as sand dunes and attenuating higher frequencies as well. S4 with denser spatial sampling with smaller shotline and receiver line spacing could jointly with seismic data broader bandwidth to improve interpreting many seismic details such faults, fractures, tiny stratigraphic features resolution. A debate was raised locally about the value of acquiring seismic data with S4, if only for the sake of acquiring seismic data with shorter time duration compare to the too much equipment needed for array acquisition type that consumes longer time in general. Alternatively, S4 really bring a real value of information and producing an outstanding seismic volume for amenable interpretation with confidence that will lead to utilize the seismic data to help in optimizing the well trajectories placement. This high density broadband 3D seismic acquired survey with fully sampled wave-field data has used the latest acquisition and imaging technologies, it has delivered critical information that can help to reduce drilling risks and to support future 4D reservoir monitoring which improved signal to noise ratio when compared with legacy dataset. An advance seismic processing workflow is tailored to improve the final image quality, and to preserve the azimuthal amplitude variation with offset and azimuth, which in turn can lead to the derivation of intrinsic rock property attributes for better reservoir characterization. A multi azimuth Prestack depth migration approach resolved most of the effects of heterogeneities in the shallow part and in the velocity field, which sometimes can be misinterpreted as azimuthal anisotropy.
{"title":"How Broadband, High Dense, Full Azimuth & Point Source Point Receiver Acquisition Improves Seismic Interpretation in Onshore Abu Dhabi","authors":"S. Al-Naqbi, A. Elila, J. Vargas, M. Mahgoub","doi":"10.2118/192948-MS","DOIUrl":"https://doi.org/10.2118/192948-MS","url":null,"abstract":"\u0000 Acquiring seismic data with S4 (Single Source, Single Sensor) is proven technology and it has many advantages over the conventional source and receiver array acquisition type. The array has an intra array statics issue when deployed on large elevation variation such as sand dunes and attenuating higher frequencies as well. S4 with denser spatial sampling with smaller shotline and receiver line spacing could jointly with seismic data broader bandwidth to improve interpreting many seismic details such faults, fractures, tiny stratigraphic features resolution. A debate was raised locally about the value of acquiring seismic data with S4, if only for the sake of acquiring seismic data with shorter time duration compare to the too much equipment needed for array acquisition type that consumes longer time in general. Alternatively, S4 really bring a real value of information and producing an outstanding seismic volume for amenable interpretation with confidence that will lead to utilize the seismic data to help in optimizing the well trajectories placement.\u0000 This high density broadband 3D seismic acquired survey with fully sampled wave-field data has used the latest acquisition and imaging technologies, it has delivered critical information that can help to reduce drilling risks and to support future 4D reservoir monitoring which improved signal to noise ratio when compared with legacy dataset.\u0000 An advance seismic processing workflow is tailored to improve the final image quality, and to preserve the azimuthal amplitude variation with offset and azimuth, which in turn can lead to the derivation of intrinsic rock property attributes for better reservoir characterization. A multi azimuth Prestack depth migration approach resolved most of the effects of heterogeneities in the shallow part and in the velocity field, which sometimes can be misinterpreted as azimuthal anisotropy.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82119947","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. Mishra, A. Anurag, Mohammed Al Balooshi, Khalid Javid, R. Sinha, Ghassan Al-Hashmy, K. Hosany, C. Mills, M. Basioni, Abdulla Al-Blooshi, F. A. Aryani, J. Mandl, Suvodip Dasgupta, I. Raina, Humair Ali, Jaja Uruzula Abdulrahim, Baraka Al-Afeefi, F. Hollaender
Recent appraisal drilling undertaken by ADNOC in offshore Abu Dhabi has focussed on evaluation of the Middle Jurassic to Permian Deep Gas reservoir sequences. These formations are characterised by low porosity and permeability and typically contain either dry gas or gas condensate fluids. These appraisal activities form part of a larger program leading to development of these resources. Principal uncertainties addressed by appraisal drilling include determining fluid characteristics, reservoir properties and ultimately well deliverability. This paper uses one such recently drilled (typical) appraisal well as an example of the workflow employed. Exploration drilling of the Middle Jurassic to Permian reservoirs in this field dates back to 1984 and utilised available logging tools and techniques of the time. The current appraisal drilling program built on the results of this work and utilizes the latest available technology and interpretation techniques to both quantify reservoir and fluid properties and minimise subsurface development uncertainties. Typical data acquisition programs includes: conventional coring, advanced mud log data acquisition, triple-combo wireline data, borehole image data, elemental spectroscopy, azimuthal dipole sonic data and formation pressure measurements/samples. The formation evaluation program involved careful analysis and integration of this data to decide at first on formation sampling points and then subsequently testing zones. This approach necessitated the involvement of multiple stakeholders (end-users as well as people performing the interpretation) and required close communication to facilitate rapid, informed, decision making at key stages of the project execution. These different types of data become available at differing times during the course of drilling a well with the earlier acquired data informing the decision-making process on subsequent data acquisition. The first data to come in were the "mud logs" which includes drilling parameters (such as Rate of Penetration) and gas chromatography. This data provides an initial indication of potential zones of interest, along with fluid type. Following acquisition of wireline data, a "quicklook" formation evaluation was integrated with earlier geological analysis to determine the formation pressure and fluid sampling points. Combined together, these results formed the basis of an integrated reservoir and saturating fluid interpretation leading to the selection of perforation intervals for well testing. Effective implementation of this work flow requires a collaborative approach combined with ongoing data integration. This process of consultation across multiple subsurface disciplines and stepwise evaluation guiding future data acquisition requires a certain degree of evaluation flexibility but ultimately results in better decisions. The philosophy of integrating multiple data sources and disciplines in a collaborative evaluation and decision-making work f
{"title":"Appraising the Middle Jurassic in a New Field in Offshore Abu Dhabi: A Comprehensive and Integrated Approach","authors":"A. Mishra, A. Anurag, Mohammed Al Balooshi, Khalid Javid, R. Sinha, Ghassan Al-Hashmy, K. Hosany, C. Mills, M. Basioni, Abdulla Al-Blooshi, F. A. Aryani, J. Mandl, Suvodip Dasgupta, I. Raina, Humair Ali, Jaja Uruzula Abdulrahim, Baraka Al-Afeefi, F. Hollaender","doi":"10.2118/193338-MS","DOIUrl":"https://doi.org/10.2118/193338-MS","url":null,"abstract":"\u0000 Recent appraisal drilling undertaken by ADNOC in offshore Abu Dhabi has focussed on evaluation of the Middle Jurassic to Permian Deep Gas reservoir sequences. These formations are characterised by low porosity and permeability and typically contain either dry gas or gas condensate fluids. These appraisal activities form part of a larger program leading to development of these resources. Principal uncertainties addressed by appraisal drilling include determining fluid characteristics, reservoir properties and ultimately well deliverability. This paper uses one such recently drilled (typical) appraisal well as an example of the workflow employed.\u0000 Exploration drilling of the Middle Jurassic to Permian reservoirs in this field dates back to 1984 and utilised available logging tools and techniques of the time. The current appraisal drilling program built on the results of this work and utilizes the latest available technology and interpretation techniques to both quantify reservoir and fluid properties and minimise subsurface development uncertainties. Typical data acquisition programs includes: conventional coring, advanced mud log data acquisition, triple-combo wireline data, borehole image data, elemental spectroscopy, azimuthal dipole sonic data and formation pressure measurements/samples. The formation evaluation program involved careful analysis and integration of this data to decide at first on formation sampling points and then subsequently testing zones. This approach necessitated the involvement of multiple stakeholders (end-users as well as people performing the interpretation) and required close communication to facilitate rapid, informed, decision making at key stages of the project execution.\u0000 These different types of data become available at differing times during the course of drilling a well with the earlier acquired data informing the decision-making process on subsequent data acquisition. The first data to come in were the \"mud logs\" which includes drilling parameters (such as Rate of Penetration) and gas chromatography. This data provides an initial indication of potential zones of interest, along with fluid type. Following acquisition of wireline data, a \"quicklook\" formation evaluation was integrated with earlier geological analysis to determine the formation pressure and fluid sampling points.\u0000 Combined together, these results formed the basis of an integrated reservoir and saturating fluid interpretation leading to the selection of perforation intervals for well testing. Effective implementation of this work flow requires a collaborative approach combined with ongoing data integration. This process of consultation across multiple subsurface disciplines and stepwise evaluation guiding future data acquisition requires a certain degree of evaluation flexibility but ultimately results in better decisions.\u0000 The philosophy of integrating multiple data sources and disciplines in a collaborative evaluation and decision-making work f","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":"79483514","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Clair field is the largest discovered oilfield on the UK continental shelf (UKCS) but has high reservoir uncertainty associated with a complex natural fracture network. The field area covers over 200 sq km with an estimated STOIIP of 7 billion barrels. The scale and complexity of the reservoir has led to a phased multi-platform development. Phase 1 started production in 2005 with 20 wells drilled prior to an extended drill break. Five new wells (A21 to A25) were drilled and brought online during 2016/17 which increased platform production by c.70%. The new wells incorporated historic lessons to mitigate the risk of wellbore instability in the overburden and be robust to the dynamic uncertainties of the fractured reservoir. Many of the well outcomes and risk events were predicted and mitigated effectively, however the new wells still provided some surprises. This paper presents a summary of the lessons from the historic Clair development wells which underpinned the recent drilling campaign and additional field understanding provided by the new well results. New insights include a narrower overburden drilling window and zonal isolation challenges within the reservoir.
{"title":"Clair Phase 1: The Evolving Development of a Complex Fractured Field","authors":"M. Webster","doi":"10.2118/193242-MS","DOIUrl":"https://doi.org/10.2118/193242-MS","url":null,"abstract":"\u0000 The Clair field is the largest discovered oilfield on the UK continental shelf (UKCS) but has high reservoir uncertainty associated with a complex natural fracture network. The field area covers over 200 sq km with an estimated STOIIP of 7 billion barrels. The scale and complexity of the reservoir has led to a phased multi-platform development.\u0000 Phase 1 started production in 2005 with 20 wells drilled prior to an extended drill break. Five new wells (A21 to A25) were drilled and brought online during 2016/17 which increased platform production by c.70%. The new wells incorporated historic lessons to mitigate the risk of wellbore instability in the overburden and be robust to the dynamic uncertainties of the fractured reservoir. Many of the well outcomes and risk events were predicted and mitigated effectively, however the new wells still provided some surprises.\u0000 This paper presents a summary of the lessons from the historic Clair development wells which underpinned the recent drilling campaign and additional field understanding provided by the new well results. New insights include a narrower overburden drilling window and zonal isolation challenges within the reservoir.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85104184","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. Brioschi, Luca Cadei, Luca Del Monaco, M. Raffone, M. Montini, A. Bianco
The current oil and gas market context is characterised by low prices, high uncertainties and a subsequent reduction in new investments. This leads to an ever-increasing attention towards more efficient exploitation of resources. This scenario underlines the need for existing assets production optimization, especially for deep-water applications. This paper presents the methodology of an innovative integrated production optimization tool and presents the results obtained in a real application on a deep-water asset. The optimization tool aggregates in a single integrated platform all the different aspects of the asset, from well performances to topside process simulation through gathering system thermo-hydraulic calculations. It effortlessly orchestrates several pieces of software that model the different parts of the asset. Those are typically used by different disciplines, such as reservoir, well area, flow assurance, process and operations. Therefore, the tool promotes the essential collaborations between disciplines. The production optimization is based on genetic algorithms and is able to increase the production of an asset respecting all the operative and flow-assurance constraints. The optimization was applied on a deep-water field, posing particular attention on the delicate ecosystem that is the gas lifecycle of an FPSO. In this case, a global and holistic approach is of paramount importance: in fact, the gas associated to the oil production plays a role in the hydraulics of the pipelines and after being dehydrated and compressed, is used as fuel gas, as gas for wells artificial lifting and for re-injection into the reservoir. The application resulted in a global optimisation of the gas utilization and had manifold impacts. Firstly, it resulted in an increase in oil production. Secondly, a reduction in the overall gas lift led to a more energy efficient use of the compressors. Finally, a higher use of the gas for re-injection resulted more effective for pressure maintenance. As a consequence of the theoretical study, the optimization actions identified by the tool lead to a successful application in the field. This paper presents a novel approach to overall asset optimization that integrates different engineering disciplines. The approach accounts for the overall gas balance of an FPSO from bottom hole to separation, lifting and re-injection.
{"title":"Integrated Optimization of the Overall Gas Mass Balance in a Deep-Water Production System","authors":"S. Brioschi, Luca Cadei, Luca Del Monaco, M. Raffone, M. Montini, A. Bianco","doi":"10.2118/193265-MS","DOIUrl":"https://doi.org/10.2118/193265-MS","url":null,"abstract":"\u0000 The current oil and gas market context is characterised by low prices, high uncertainties and a subsequent reduction in new investments. This leads to an ever-increasing attention towards more efficient exploitation of resources. This scenario underlines the need for existing assets production optimization, especially for deep-water applications. This paper presents the methodology of an innovative integrated production optimization tool and presents the results obtained in a real application on a deep-water asset.\u0000 The optimization tool aggregates in a single integrated platform all the different aspects of the asset, from well performances to topside process simulation through gathering system thermo-hydraulic calculations. It effortlessly orchestrates several pieces of software that model the different parts of the asset. Those are typically used by different disciplines, such as reservoir, well area, flow assurance, process and operations. Therefore, the tool promotes the essential collaborations between disciplines. The production optimization is based on genetic algorithms and is able to increase the production of an asset respecting all the operative and flow-assurance constraints.\u0000 The optimization was applied on a deep-water field, posing particular attention on the delicate ecosystem that is the gas lifecycle of an FPSO. In this case, a global and holistic approach is of paramount importance: in fact, the gas associated to the oil production plays a role in the hydraulics of the pipelines and after being dehydrated and compressed, is used as fuel gas, as gas for wells artificial lifting and for re-injection into the reservoir. The application resulted in a global optimisation of the gas utilization and had manifold impacts. Firstly, it resulted in an increase in oil production. Secondly, a reduction in the overall gas lift led to a more energy efficient use of the compressors. Finally, a higher use of the gas for re-injection resulted more effective for pressure maintenance. As a consequence of the theoretical study, the optimization actions identified by the tool lead to a successful application in the field.\u0000 This paper presents a novel approach to overall asset optimization that integrates different engineering disciplines. The approach accounts for the overall gas balance of an FPSO from bottom hole to separation, lifting and re-injection.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89282557","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}
Venugopal Bakthavachsalam, G. Buendia, Haitham Al Hashimi
Maintaining flare tip health is essential to ensure safe disposal of flammable hydrocarbons in any oil and gas industries. This paper presents best practices (from operation, to maintenance and inspection) to ensure the health of large flare tips. The flare tip mixes flammable fluids and air into the required concentration and velocity to maintain stable ignition and combustion. These flare tips are vulnerable to damages caused by burn backs that may result in serious threats to plant safety & integrity, as well as exorbitant replacement costs. We will outline how we comprehensively mitigated thermal buckling failures in HP flare tips to improve the asset life and availability of these safety critical flare systems. In the past, we recorded frequent flare tip failures in the four stage HP flare system of trains 3 & 4. Replacement of these expensive tips was planned during major turnarounds. Meanwhile, the root cause analysis revealed that the thermal bucking tip failures can be attributed to "burn back". Inadequate purge gas flow, poor reliability of burn back detectors, inadequate design, control measures and project specifications were identified as causes for the burn back. It was recommended to replace the fuel gas as a purge gas medium with nitrogen. This permanently preserved the integrity of the flare tips, while avoiding fuel gas wastage. In addition, the following best practices were recommended to maintain a healthy flare system. Improve the design and reliability of burn back detectorsChange the inspection approach to thermographic surveysImprove the pilot flame, burn back detectors and alarm system to provide low flow alarms for purge gas The implementation of these recommendations enhanced the asset life and availability of the safety critical flare system, as proven by the thermographic survey, which shows colder operating conditions of the flare tips.
{"title":"Maintaining Flare Tip Health","authors":"Venugopal Bakthavachsalam, G. Buendia, Haitham Al Hashimi","doi":"10.2118/192961-MS","DOIUrl":"https://doi.org/10.2118/192961-MS","url":null,"abstract":"\u0000 Maintaining flare tip health is essential to ensure safe disposal of flammable hydrocarbons in any oil and gas industries. This paper presents best practices (from operation, to maintenance and inspection) to ensure the health of large flare tips. The flare tip mixes flammable fluids and air into the required concentration and velocity to maintain stable ignition and combustion. These flare tips are vulnerable to damages caused by burn backs that may result in serious threats to plant safety & integrity, as well as exorbitant replacement costs.\u0000 We will outline how we comprehensively mitigated thermal buckling failures in HP flare tips to improve the asset life and availability of these safety critical flare systems. In the past, we recorded frequent flare tip failures in the four stage HP flare system of trains 3 & 4. Replacement of these expensive tips was planned during major turnarounds. Meanwhile, the root cause analysis revealed that the thermal bucking tip failures can be attributed to \"burn back\". Inadequate purge gas flow, poor reliability of burn back detectors, inadequate design, control measures and project specifications were identified as causes for the burn back.\u0000 It was recommended to replace the fuel gas as a purge gas medium with nitrogen. This permanently preserved the integrity of the flare tips, while avoiding fuel gas wastage. In addition, the following best practices were recommended to maintain a healthy flare system. Improve the design and reliability of burn back detectorsChange the inspection approach to thermographic surveysImprove the pilot flame, burn back detectors and alarm system to provide low flow alarms for purge gas\u0000 The implementation of these recommendations enhanced the asset life and availability of the safety critical flare system, as proven by the thermographic survey, which shows colder operating conditions of the flare tips.","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":"86850665","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}
T. Ferrari, N. Rossetti, Ahmed Abdulkareim Al-Ameiry, Francesco Anzelini, Haitham Salmeen
Same as other energy-intensive industries, ADNOC LNG is looking at the development of energy-efficiency solutions aimed to improve production process sustainability while maintaining effectiveness and competitiveness. The conversion of waste heat into useful power represents a viable and profitable solution to hit these targets. The possibility to implement an ORC-based heat recovery system as a replacement of an open-cycle gas turbine in Das Island facility has been investigated. The study evolved in two main phases. The first one was aimed to identify the most suitable waste heat sources present on site. This included the quantification of the waste heat sources needed to achieve the forecasted power demand while complying with layout constrains. The second one was directed to the technical and economic analysis of different heat recovery configurations, in order to understand the best ORC solution. The outcome of the second phase constitutes the reference business case that will be used to compare the ORC with the alternative power production technology, i.e. an open-cycle gas turbine. With a view to the commissioning of new projects in Das Island and the resulting power consumption increase, ADNOC LNG was originally planning to cover this extra power demand by installing a new open-cycle gas turbine. Given the presence on site of other several open-cycle gas turbines, a waste-heat-to-power solution appeared to be an alternative and feasible solution. The ORC technology, thanks to the use of an organic working fluid, is able to recover the exhaust gas sensible heat and produce power, resulting in a simple power plant with extremely low operation and maintenance costs, high availability, simplicity of operation and no water consumption if an air-cooled condenser solution is selected. Depending on the combination of gas turbines considered for heat recovery in Das Island, the ORC power output can reach up to 30+ MW el., covering a not-negligible portion of Das Island electrical consumption and allowing considerable fuel savings, computed in 10 MMSCFD of fuel gas that can be saved and thus re-allocated to produce useful gas products. The study showed that the ORC solution is viable and can produce the required power at the allocated plot area, which was reserved for the open-cycle gas turbine. Das Island case study represents one of the first systematic analysis aimed at the integration of an ORC-based heat recovery system within an existing LNG facility. The results of the investigation appear very promising: with a computed LCOE < 30 USD/MWh and breakeven of 3 years, the ORC embodies a possible alternative to traditional power-production technologies. This type of project would be the first in the Region, making ADNOC LNG a pioneer of the technology.
{"title":"Waste Heat to Power Through Organic Rankine Cycle ORC Technology: Das Island Case Study","authors":"T. Ferrari, N. Rossetti, Ahmed Abdulkareim Al-Ameiry, Francesco Anzelini, Haitham Salmeen","doi":"10.2118/193050-MS","DOIUrl":"https://doi.org/10.2118/193050-MS","url":null,"abstract":"\u0000 Same as other energy-intensive industries, ADNOC LNG is looking at the development of energy-efficiency solutions aimed to improve production process sustainability while maintaining effectiveness and competitiveness. The conversion of waste heat into useful power represents a viable and profitable solution to hit these targets. The possibility to implement an ORC-based heat recovery system as a replacement of an open-cycle gas turbine in Das Island facility has been investigated.\u0000 The study evolved in two main phases. The first one was aimed to identify the most suitable waste heat sources present on site. This included the quantification of the waste heat sources needed to achieve the forecasted power demand while complying with layout constrains. The second one was directed to the technical and economic analysis of different heat recovery configurations, in order to understand the best ORC solution. The outcome of the second phase constitutes the reference business case that will be used to compare the ORC with the alternative power production technology, i.e. an open-cycle gas turbine.\u0000 With a view to the commissioning of new projects in Das Island and the resulting power consumption increase, ADNOC LNG was originally planning to cover this extra power demand by installing a new open-cycle gas turbine. Given the presence on site of other several open-cycle gas turbines, a waste-heat-to-power solution appeared to be an alternative and feasible solution. The ORC technology, thanks to the use of an organic working fluid, is able to recover the exhaust gas sensible heat and produce power, resulting in a simple power plant with extremely low operation and maintenance costs, high availability, simplicity of operation and no water consumption if an air-cooled condenser solution is selected. Depending on the combination of gas turbines considered for heat recovery in Das Island, the ORC power output can reach up to 30+ MW el., covering a not-negligible portion of Das Island electrical consumption and allowing considerable fuel savings, computed in 10 MMSCFD of fuel gas that can be saved and thus re-allocated to produce useful gas products. The study showed that the ORC solution is viable and can produce the required power at the allocated plot area, which was reserved for the open-cycle gas turbine.\u0000 Das Island case study represents one of the first systematic analysis aimed at the integration of an ORC-based heat recovery system within an existing LNG facility. The results of the investigation appear very promising: with a computed LCOE < 30 USD/MWh and breakeven of 3 years, the ORC embodies a possible alternative to traditional power-production technologies. This type of project would be the first in the Region, making ADNOC LNG a pioneer of the technology.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86295007","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}
Rakhat Almetayev, Muna Al Hosani, S. Ameri, A. Mutawa, Mushtaq Ahmad Hussain, Jobin Abraham, M. Saleh, Ayoub Hadj-moussa, Khoa Pham Dang Le
Drilling fluid losses while drilling a mature cretaceous limestone reservoir unit (Formation A) has been worsening over years with reservoir depletion and lack of pressure support. New drilling methods were needed to eliminate or reduce total losses and the associated non-productive time with them. Nitrified Managed Pressure Drilling proposed to help in mitigating losses and reducing non-productive-time. This paper explains the challenge, details the solution that was proposed to tackle, and discusses the results of the application. Nitrified Managed Pressure Drilling (MPD) decreases the Equivalent Circulation Density (ECD) below the lowest possible static mud weight (water) and at the same time deals safely with any unintended hydrocarbon influxes while drilling the reservoir 6″ hole section. The well data was analysed and modelled with different Nitrogen pumping rates and Surface Back Pressure (SBP) to determine the best rates that a mitigates losses but at the same time prevent hydrocarbon influxes. A closed-Loop drilling system proposed utilizing rotating control device, a separation package, and locally produced membrane Nitrogen allowed to manage the annular hydraulic pressure profile accordingly and mitigate the total losses scenario eliminating the wait on water time Rigorous planning and disciplined execution have led to safe and successful conclusion with no QHSE issues encountered. The designed Nitrified Managed Pressure Drilling solution succeeded in preventing the drilling fluid losses in the reservoir section by reducing the overbalance pressure of the drilling mud from 700 psi to 250 psi, which resulted in the elimination of 3 days of the rig's non-productive-time related to waiting on water. The closed-loop system coupled with a precise data acquisition and monitoring system has helped in maintaining a slight overbalance condition over the reservoir preventing any unintended hydrocarbon influxes to the surface. The lessons learned captured from this operation have contributed to the optimization of the Nitrified MPD in (Formation A) and to the overall MPD implementation in ADNOC fields. This paper displays the first application of nitrified managed pressure drilling in the United Arab Emirates. The equipment design and planning have accounted for many different scenarios, as this type of drilling technology enables more precise wellbore pressure management with less interruptions to drilling ahead
{"title":"First Nitrified Managed Pressure Drilling Application in United Arab Emirates","authors":"Rakhat Almetayev, Muna Al Hosani, S. Ameri, A. Mutawa, Mushtaq Ahmad Hussain, Jobin Abraham, M. Saleh, Ayoub Hadj-moussa, Khoa Pham Dang Le","doi":"10.2118/193025-MS","DOIUrl":"https://doi.org/10.2118/193025-MS","url":null,"abstract":"\u0000 Drilling fluid losses while drilling a mature cretaceous limestone reservoir unit (Formation A) has been worsening over years with reservoir depletion and lack of pressure support. New drilling methods were needed to eliminate or reduce total losses and the associated non-productive time with them. Nitrified Managed Pressure Drilling proposed to help in mitigating losses and reducing non-productive-time. This paper explains the challenge, details the solution that was proposed to tackle, and discusses the results of the application.\u0000 Nitrified Managed Pressure Drilling (MPD) decreases the Equivalent Circulation Density (ECD) below the lowest possible static mud weight (water) and at the same time deals safely with any unintended hydrocarbon influxes while drilling the reservoir 6″ hole section. The well data was analysed and modelled with different Nitrogen pumping rates and Surface Back Pressure (SBP) to determine the best rates that a mitigates losses but at the same time prevent hydrocarbon influxes. A closed-Loop drilling system proposed utilizing rotating control device, a separation package, and locally produced membrane Nitrogen allowed to manage the annular hydraulic pressure profile accordingly and mitigate the total losses scenario eliminating the wait on water time\u0000 Rigorous planning and disciplined execution have led to safe and successful conclusion with no QHSE issues encountered. The designed Nitrified Managed Pressure Drilling solution succeeded in preventing the drilling fluid losses in the reservoir section by reducing the overbalance pressure of the drilling mud from 700 psi to 250 psi, which resulted in the elimination of 3 days of the rig's non-productive-time related to waiting on water. The closed-loop system coupled with a precise data acquisition and monitoring system has helped in maintaining a slight overbalance condition over the reservoir preventing any unintended hydrocarbon influxes to the surface. The lessons learned captured from this operation have contributed to the optimization of the Nitrified MPD in (Formation A) and to the overall MPD implementation in ADNOC fields.\u0000 This paper displays the first application of nitrified managed pressure drilling in the United Arab Emirates. The equipment design and planning have accounted for many different scenarios, as this type of drilling technology enables more precise wellbore pressure management with less interruptions to drilling ahead","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83910954","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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