Correctly evaluating reservoirs with thin laminations can be challenging. From a conventional perspective, this type of reservoir is often considered to be nonpay because of its low resistivity. Tensor models help improve resistivity using horizontal (RH) and vertical (RV) resistivity measurements from triaxial induction logging tools. In the absence of triaxial advanced measurements of RH and RV, tensor model equations using a conventional openhole (triple combo data) can be used. This approach is based on rearranging the tensor model with the Moran-Gianzero equation and using several assumptions for unique cases. This method explains the workflow to calculate sand resistivity correctly using only openhole data as well as calculating the anisotropic shale resistivity that is often estimated from nearby shales. A mathematical method is preferred to obtain consistent results for anisotropic shale resistivity parameters to reduce calculation uncertainty. Sensitivity analyses are created to provide a sense of how these parameters affect the results on sand resistivity. For a vertical well where relative dip is close to zero, RSd can be calculated without knowing the RshV. The same equation provides a 10% error on RSd at VLam<10% and relative dip <10°. At a higher relative dip and anisotropic shale resistivity, a cubic equation with a new coefficient is proposed. Sensitivity analyses are made to compare a true RSd and calculated RSd with changing RshH and RshV variables. The model demonstrates that a 10% change on RshH could cause a 30% error on RSd at VLam of 10%, while changes in RshV only begins to affect RSd up to 30% at VLam 70%. Graphical and mathematical methods are proposed to help prevent misestimating the RshH and RshV. The graphical method is preferred when a complete data set for all relative dip is available, while the mathematical method is preferred when the data set is limited. Unique cases where the RSd can be calculated as well as demonstrations on how anisotropic shale resistivity parameters can be determined using only conventional openhole (triple combo) data are highlighted. The additional set of constraints on the iteration of the cubic equation represents an improvement of the previous study, whereas the proposed method to determine the RshH and RshV helps prevent estimation errors of these parameters and helps improve RSd calculation accuracy.
{"title":"Practical Application of Tensor Model in Laminated Sand Shale Analysis","authors":"Aditya Ariewijaya","doi":"10.2118/197208-ms","DOIUrl":"https://doi.org/10.2118/197208-ms","url":null,"abstract":"\u0000 Correctly evaluating reservoirs with thin laminations can be challenging. From a conventional perspective, this type of reservoir is often considered to be nonpay because of its low resistivity. Tensor models help improve resistivity using horizontal (RH) and vertical (RV) resistivity measurements from triaxial induction logging tools. In the absence of triaxial advanced measurements of RH and RV, tensor model equations using a conventional openhole (triple combo data) can be used.\u0000 This approach is based on rearranging the tensor model with the Moran-Gianzero equation and using several assumptions for unique cases. This method explains the workflow to calculate sand resistivity correctly using only openhole data as well as calculating the anisotropic shale resistivity that is often estimated from nearby shales. A mathematical method is preferred to obtain consistent results for anisotropic shale resistivity parameters to reduce calculation uncertainty. Sensitivity analyses are created to provide a sense of how these parameters affect the results on sand resistivity.\u0000 For a vertical well where relative dip is close to zero, RSd can be calculated without knowing the RshV. The same equation provides a 10% error on RSd at VLam<10% and relative dip <10°. At a higher relative dip and anisotropic shale resistivity, a cubic equation with a new coefficient is proposed. Sensitivity analyses are made to compare a true RSd and calculated RSd with changing RshH and RshV variables. The model demonstrates that a 10% change on RshH could cause a 30% error on RSd at VLam of 10%, while changes in RshV only begins to affect RSd up to 30% at VLam 70%. Graphical and mathematical methods are proposed to help prevent misestimating the RshH and RshV. The graphical method is preferred when a complete data set for all relative dip is available, while the mathematical method is preferred when the data set is limited.\u0000 Unique cases where the RSd can be calculated as well as demonstrations on how anisotropic shale resistivity parameters can be determined using only conventional openhole (triple combo) data are highlighted. The additional set of constraints on the iteration of the cubic equation represents an improvement of the previous study, whereas the proposed method to determine the RshH and RshV helps prevent estimation errors of these parameters and helps improve RSd calculation accuracy.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"112 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86753760","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}
Leveraging dry wave monitoring technology to detect oil spills can contribute to quicker and more cost-effective oil spill rescue operations than leveraging in-water solutions or laser technology. Using X-band radar-based technology in combination with infrared-cameras is a proven method which supports both oil-spill surveillance and response. This technical paper highlights the physical material properties that make oil spill detection possible with a combined system of x-band radar technology and infrared cameras.
{"title":"Oil Spill Detection, Thickness Evaluation with Radar, Optical and Infrared Sensors","authors":"M. Vinther","doi":"10.2118/197562-ms","DOIUrl":"https://doi.org/10.2118/197562-ms","url":null,"abstract":"\u0000 Leveraging dry wave monitoring technology to detect oil spills can contribute to quicker and more cost-effective oil spill rescue operations than leveraging in-water solutions or laser technology. Using X-band radar-based technology in combination with infrared-cameras is a proven method which supports both oil-spill surveillance and response. This technical paper highlights the physical material properties that make oil spill detection possible with a combined system of x-band radar technology and infrared cameras.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86991506","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Cappuccio, S. Burrafato, A. Maliardi, G. R. Maccarini, Daniele Taccori, Riccardo Dalla Costa, L. Raunholt, Ø. Larsen
Early studies indicate a large potential of savings in rig time and elimination of manual operations on the drill floor, when introducing robotic drill-floor equipment on the drill floor. Robots can carry out pipe, casing and tool handling tasks in a safe, fast, consistent and precise manner. For obtaining a digitalized, fully automated drilling operation, electric robotic equipment is a key enabling technology. Since 2016, Eni has been directly involved, together with Canrig Robotics, in the technology development process for the robotic drill floor, being part of two Joint Industry Projects (JIPs) in Norway, named "Offshore Pilot of Drill Floor Robot" and "Demonstration of Automated Drilling Process Control". The aim of such projects is to install and test robotic equipment on rigs and to demonstrate the full automation of drilling operations through the integration with an advanced control system. A fully robotic drill floor requires state-of-the-art technological and industrial level innovation, which forms a basis for performing drilling & completion operations safely, reliably and consistently. This paper describes the results of a preliminary feasibility study performed by Eni in collaboration with Canrig Robotics concerning the installation of such equipment on two different rig designs, three land rigs and two drill ships, in order to find the best candidate(s). The analysis contains data collection, operational descriptions, modification and installation works, value propositions and business cases. The value proposition from using robotic equipment includes faster tripping due to consistent and seamless handling. A high number of manual operations can be saved by robotic handling of subs, pup joints, safety clamps etc. Stand-building can be made fully automated and can take place in parallel to e.g. drilling in the well center. Preliminary results show a significant potential improvement on KPIs, with an estimated time saving of 20 to 60 days per rig yearly. At the same time, HSE issues are widely mitigated, since operations can be performed effectively and consistently by robots, thus removing people from harm's way on the drill floor.
{"title":"Full Robotic Drill Floor as Advanced Rig Automation","authors":"P. Cappuccio, S. Burrafato, A. Maliardi, G. R. Maccarini, Daniele Taccori, Riccardo Dalla Costa, L. Raunholt, Ø. Larsen","doi":"10.2118/197854-ms","DOIUrl":"https://doi.org/10.2118/197854-ms","url":null,"abstract":"\u0000 Early studies indicate a large potential of savings in rig time and elimination of manual operations on the drill floor, when introducing robotic drill-floor equipment on the drill floor. Robots can carry out pipe, casing and tool handling tasks in a safe, fast, consistent and precise manner.\u0000 For obtaining a digitalized, fully automated drilling operation, electric robotic equipment is a key enabling technology.\u0000 Since 2016, Eni has been directly involved, together with Canrig Robotics, in the technology development process for the robotic drill floor, being part of two Joint Industry Projects (JIPs) in Norway, named \"Offshore Pilot of Drill Floor Robot\" and \"Demonstration of Automated Drilling Process Control\". The aim of such projects is to install and test robotic equipment on rigs and to demonstrate the full automation of drilling operations through the integration with an advanced control system.\u0000 A fully robotic drill floor requires state-of-the-art technological and industrial level innovation, which forms a basis for performing drilling & completion operations safely, reliably and consistently.\u0000 This paper describes the results of a preliminary feasibility study performed by Eni in collaboration with Canrig Robotics concerning the installation of such equipment on two different rig designs, three land rigs and two drill ships, in order to find the best candidate(s). The analysis contains data collection, operational descriptions, modification and installation works, value propositions and business cases.\u0000 The value proposition from using robotic equipment includes faster tripping due to consistent and seamless handling. A high number of manual operations can be saved by robotic handling of subs, pup joints, safety clamps etc. Stand-building can be made fully automated and can take place in parallel to e.g. drilling in the well center.\u0000 Preliminary results show a significant potential improvement on KPIs, with an estimated time saving of 20 to 60 days per rig yearly. At the same time, HSE issues are widely mitigated, since operations can be performed effectively and consistently by robots, thus removing people from harm's way on the drill floor.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84716016","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}
J. Maalouf, P. Benny, E. Cantarelli, Sultan Dahi Al-Hassani, I. Altameemi, S. Ahmed, O. Khan, Mariam Khaleel Al Hammadi, H. Zakaria, H. Aboujmeih
Ultrahigh-resolution electrical images (UHRIs) acquired with logging while drilling (LWD) tools have brought to light different side effects of using drilling tools such as rotary steerable systems (RSSs) and bits when drilling a horizontal borehole. This paper will go through the extensive analysis and simulations that followed, gathering data from almost thirty wells, to try and understand the root causes behind these side effects, along with the actions put in place to mitigate it. UHRIs were used while drilling a 6-in horizontal hole to achieve a 100% net-to-gross and perform advanced formation evaluation to optimize well production. Surprisingly, these images revealed more details: wellbore threading–a type of spiral–inside the formation. To understand the cause behind such marks, RSS and bit data was gathered from around thirty wells, compared, and analyzed. Simulations were run over months, considering rock types, drilling parameters, and bottom hole assembly (BHA) design to reproduce the issue and propose the best solution to prevent these events from reoccurring. After the data compilation, a trend emerged. Wellbore threading was observed in soft, high-porosity reservoir formations. It also appeared in tandem with controlled rate of penetration (ROP), low weight on bit (WOB), and a low steering ratio. At this point, advanced analysis and simulations were needed to determine the root cause of this phenomenon. A Finite Element Analysis (FEA) based 4D modeling software showed that the bit gauge pad length, combined with the RSS pad force, contributed to this threading. A pad pressure force higher than 7,000 N in conjunction with a short-gauge bit increased the likelihood of having this borehole deformation. Simulations comparing different size tapered and nominal bit gauge pad lengths were run to determine the effect on the borehole and on the steerability. Bit design is directly linked to the wellbore threading effect. It is more pronounced when associated with a powerful rotary steerable system and in a soft formation environment. However, altering a specific bit design can have a direct and undesirable effect on the steerability of the BHA. UHRI revealed details of borehole deformation that new drilling technologies are causing. It enabled an in-depth analysis of the different causes behind it, revealing ad-hoc solutions. Horizontal wells are being drilled in more challenging environments such as through thin formation layers, unpredictable geology, and unknown fluid movement. Detailed evaluation has a direct impact on the completion approach. But we also need to drill faster and more efficiently. The wellbore threading caused formation damage that masked information needed for formation evaluation. In a novel application of UHRI data, simulations gave birth to information which has been lacking and incentivized the development of new, formation-friendly technology.
{"title":"When Magnifying Your Reservoir Shows More than Expected Details: How Logging-While-Drilling Electrical Images were Used to Perfect Drilling Practices and Minimize Borehole Impact","authors":"J. Maalouf, P. Benny, E. Cantarelli, Sultan Dahi Al-Hassani, I. Altameemi, S. Ahmed, O. Khan, Mariam Khaleel Al Hammadi, H. Zakaria, H. Aboujmeih","doi":"10.2118/197782-ms","DOIUrl":"https://doi.org/10.2118/197782-ms","url":null,"abstract":"\u0000 Ultrahigh-resolution electrical images (UHRIs) acquired with logging while drilling (LWD) tools have brought to light different side effects of using drilling tools such as rotary steerable systems (RSSs) and bits when drilling a horizontal borehole. This paper will go through the extensive analysis and simulations that followed, gathering data from almost thirty wells, to try and understand the root causes behind these side effects, along with the actions put in place to mitigate it. UHRIs were used while drilling a 6-in horizontal hole to achieve a 100% net-to-gross and perform advanced formation evaluation to optimize well production. Surprisingly, these images revealed more details: wellbore threading–a type of spiral–inside the formation. To understand the cause behind such marks, RSS and bit data was gathered from around thirty wells, compared, and analyzed. Simulations were run over months, considering rock types, drilling parameters, and bottom hole assembly (BHA) design to reproduce the issue and propose the best solution to prevent these events from reoccurring. After the data compilation, a trend emerged. Wellbore threading was observed in soft, high-porosity reservoir formations. It also appeared in tandem with controlled rate of penetration (ROP), low weight on bit (WOB), and a low steering ratio. At this point, advanced analysis and simulations were needed to determine the root cause of this phenomenon. A Finite Element Analysis (FEA) based 4D modeling software showed that the bit gauge pad length, combined with the RSS pad force, contributed to this threading. A pad pressure force higher than 7,000 N in conjunction with a short-gauge bit increased the likelihood of having this borehole deformation. Simulations comparing different size tapered and nominal bit gauge pad lengths were run to determine the effect on the borehole and on the steerability. Bit design is directly linked to the wellbore threading effect. It is more pronounced when associated with a powerful rotary steerable system and in a soft formation environment. However, altering a specific bit design can have a direct and undesirable effect on the steerability of the BHA. UHRI revealed details of borehole deformation that new drilling technologies are causing. It enabled an in-depth analysis of the different causes behind it, revealing ad-hoc solutions.\u0000 Horizontal wells are being drilled in more challenging environments such as through thin formation layers, unpredictable geology, and unknown fluid movement. Detailed evaluation has a direct impact on the completion approach. But we also need to drill faster and more efficiently. The wellbore threading caused formation damage that masked information needed for formation evaluation. In a novel application of UHRI data, simulations gave birth to information which has been lacking and incentivized the development of new, formation-friendly technology.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87354380","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}
Dawood Al Kharusi, M. Cobanoglu, I. Shukri, Samiya Al Bulushi, Mohamed Helmy, Mahmood Al Housni, Sausan Al Khaziri, Abdullah Al Hinaai
A large rich gas condensate field in The Sultanate of Oman has been studied. 30 gas wells were drilled in the field producing 3 MMm3/d of gas and 450 m3/d of condensate from the Barik formation. Water production is negligible. A redevelopment study was initiated with value drivers focused on maximizing the gas and condensate development. New wide azimuth seismic (WAZ) was interpreted and integrated with new petrophysical realizations and geological concepts. This has resulted in a 20% drop in both the GIIP and the CIIP. Earlier wells results and cores when fully re-evaluated support this conclusion. Petrophysical reinterpretation combined with production testing (PLTs) and sampling (MDTs) showed two potential contact scenarios. The field can either be interpreted as having one GWC or it can be interpreted as having an oil rim with a GOC and an OWC. Both of these interpretations result in very different predictions regarding volumetric recoveries, future well locations, and number of wells to be drilled. Static and dynamic models based on these two broad realizations were then generated that capture all the known uncertainties. For the Gas development value driver, a depletion case scenario was studied. For the condensate development value driver, a study of IOR and EOR methods was initiated covering water injection and water alternating gas, nitrogen injection, huff and buff, produced gas injection, and CO2 injection. Wells and surface development concepts were also assessed for each of the development scenarios and the best option was then used in the economics evaluation.
{"title":"Challenges and Modeling Results of a Mature Rich Gas Condensate Field Redevelopment Study Applying Depletion and Multiple EOR Methods to Unlock Field Potential","authors":"Dawood Al Kharusi, M. Cobanoglu, I. Shukri, Samiya Al Bulushi, Mohamed Helmy, Mahmood Al Housni, Sausan Al Khaziri, Abdullah Al Hinaai","doi":"10.2118/197475-ms","DOIUrl":"https://doi.org/10.2118/197475-ms","url":null,"abstract":"\u0000 A large rich gas condensate field in The Sultanate of Oman has been studied. 30 gas wells were drilled in the field producing 3 MMm3/d of gas and 450 m3/d of condensate from the Barik formation. Water production is negligible. A redevelopment study was initiated with value drivers focused on maximizing the gas and condensate development.\u0000 New wide azimuth seismic (WAZ) was interpreted and integrated with new petrophysical realizations and geological concepts. This has resulted in a 20% drop in both the GIIP and the CIIP. Earlier wells results and cores when fully re-evaluated support this conclusion. Petrophysical reinterpretation combined with production testing (PLTs) and sampling (MDTs) showed two potential contact scenarios. The field can either be interpreted as having one GWC or it can be interpreted as having an oil rim with a GOC and an OWC. Both of these interpretations result in very different predictions regarding volumetric recoveries, future well locations, and number of wells to be drilled.\u0000 Static and dynamic models based on these two broad realizations were then generated that capture all the known uncertainties.\u0000 For the Gas development value driver, a depletion case scenario was studied. For the condensate development value driver, a study of IOR and EOR methods was initiated covering water injection and water alternating gas, nitrogen injection, huff and buff, produced gas injection, and CO2 injection.\u0000 Wells and surface development concepts were also assessed for each of the development scenarios and the best option was then used in the economics evaluation.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87495183","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Rashaid, C. Harrison, H. Ayyad, H. Dumont, E. Smythe, M. Sullivan, J. Meier, Shunsuke Fukagawa, Masaki Miyashita, B. Grant, Y. Morikami, Y. Kajikawa, Y. Maekawa, H. Tsuboi
The accuracy of the phase envelope calculated for a black oil sample strongly depends upon the quality and type of information used to optimize the equation of state (EOS). Possible inputs for EOS tuning include (but is not limited to) composition from a chromatogram or optical absorbance, density, saturation pressure (bubble or dew point pressure), and the relative volumes of liquid and gas. In this manuscript, we describe a workflow using a system of microsensors that our group has previously published that accurately measures fluid properties from which the phase envelopes of several black oil samples are calculated and refined.
{"title":"A Downhole Wireline Module for the Measurement of Bubble Point Pressure","authors":"M. Rashaid, C. Harrison, H. Ayyad, H. Dumont, E. Smythe, M. Sullivan, J. Meier, Shunsuke Fukagawa, Masaki Miyashita, B. Grant, Y. Morikami, Y. Kajikawa, Y. Maekawa, H. Tsuboi","doi":"10.2118/197927-ms","DOIUrl":"https://doi.org/10.2118/197927-ms","url":null,"abstract":"\u0000 The accuracy of the phase envelope calculated for a black oil sample strongly depends upon the quality and type of information used to optimize the equation of state (EOS). Possible inputs for EOS tuning include (but is not limited to) composition from a chromatogram or optical absorbance, density, saturation pressure (bubble or dew point pressure), and the relative volumes of liquid and gas. In this manuscript, we describe a workflow using a system of microsensors that our group has previously published that accurately measures fluid properties from which the phase envelopes of several black oil samples are calculated and refined.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83900802","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. Syofyan, A. I. Latief, M. A. A. Amoudi, S. Al-Shamsi, Asma Hassan Ali Bal Baheeth, Andrey Nestyagin, T. Al-Shabibi, B. Banihammad, Suvodip Dasgupta, L. Mosse, Abdullah Albuali
Carbonate reservoirs introduce challenge in providing accurate water saturation from conventional Archie equation. One of the reasons is due to the variability of the Archie cementation factor "m" because of complex and tortuous nature of these heterogeneous carbonates. The study was performed by integrating core and log data from advance measurements to understand the root cause and range of the variability and an attempt to link sedimentology and diagenetic facies to petrophysical groups. The Study focused on a carbonate reservoir with complex pore network. The formation resistivity factor (FRF) measurements were conducted with high-resolution sampling on a selected well. Each of FRF plug has associated porosity, permeability, thin sections, MICP, NMR and high-resolution dual energy micro CT scan. The m value from FRF is then plotted along the porosity-permeability plot. The capillary pressure parameters (entry pressure, slope, inflexion points) were extracted from MICP and relationship is plotted against m. Diagenetic facies described from the thin sections is compared versus m. Principal component analyses was conducted to identify factors relating to m. The uncertainty on water saturation associated to variable parameter m was assessed using Monte Carlo analysis on multiple wells. An advanced multi-frequency dielectric logging tool was run on couple of wells to provide variable water-phase tortuosity (MN) measurement. Specific analysis was performed to extract the variable m value from the measurement over limited zones, which has been derived from core "m" measurements. Several wells located on the flank of the reservoir below water level were evaluated. Dean stark measurements were performed on a well and used to validate the saturation calculation. It is obvious that the evaluated reservoir has high degree of heterogeneity as indicated by complex pore network with multi modal pore system as shown by the thin sections, MICP and plug CT Scan.
{"title":"Evaluating the Variability of the Archie Cementation Factor m in Heterogeneous Carbonates: A Case Study from a Lower Cretaceous Reservoir in UAE","authors":"S. Syofyan, A. I. Latief, M. A. A. Amoudi, S. Al-Shamsi, Asma Hassan Ali Bal Baheeth, Andrey Nestyagin, T. Al-Shabibi, B. Banihammad, Suvodip Dasgupta, L. Mosse, Abdullah Albuali","doi":"10.2118/197153-ms","DOIUrl":"https://doi.org/10.2118/197153-ms","url":null,"abstract":"\u0000 Carbonate reservoirs introduce challenge in providing accurate water saturation from conventional Archie equation. One of the reasons is due to the variability of the Archie cementation factor \"m\" because of complex and tortuous nature of these heterogeneous carbonates.\u0000 The study was performed by integrating core and log data from advance measurements to understand the root cause and range of the variability and an attempt to link sedimentology and diagenetic facies to petrophysical groups.\u0000 The Study focused on a carbonate reservoir with complex pore network. The formation resistivity factor (FRF) measurements were conducted with high-resolution sampling on a selected well. Each of FRF plug has associated porosity, permeability, thin sections, MICP, NMR and high-resolution dual energy micro CT scan. The m value from FRF is then plotted along the porosity-permeability plot. The capillary pressure parameters (entry pressure, slope, inflexion points) were extracted from MICP and relationship is plotted against m. Diagenetic facies described from the thin sections is compared versus m.\u0000 Principal component analyses was conducted to identify factors relating to m. The uncertainty on water saturation associated to variable parameter m was assessed using Monte Carlo analysis on multiple wells.\u0000 An advanced multi-frequency dielectric logging tool was run on couple of wells to provide variable water-phase tortuosity (MN) measurement. Specific analysis was performed to extract the variable m value from the measurement over limited zones, which has been derived from core \"m\" measurements.\u0000 Several wells located on the flank of the reservoir below water level were evaluated. Dean stark measurements were performed on a well and used to validate the saturation calculation.\u0000 It is obvious that the evaluated reservoir has high degree of heterogeneity as indicated by complex pore network with multi modal pore system as shown by the thin sections, MICP and plug CT Scan.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85802156","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}
Fikri Bashar Yalchiner, R. Agrawal, F. Kamal, Oussama Takieddine
In this study, a detailed finite element analysis methodology of a 180 m deck cargo/launch barge B42 for 32,000 MT topside load is described and results are presented. Using Finite Element Method (FEM) for large welded steel structures such as a deck cargo/launch barge has been quite challenging in past because the engineer had to observe the balance between solution accuracy and numerical efficiency. However, recent improvements in solver algorithms in FEM packages and increasing core processor numbers in computers enable engineers to include a lot more details to their FE model so that accurate stiffness and mass of the structure can be simulated. In this study, the entire barge is modelled in ANSYS Software using shell elements including longitudinal beams, stiffeners, flanges, base plates, skid tracks and outriggers. Two most critical load cases were analyzed; the first is the maximum hogging condition which occurs in the topside loadout sequence where the topside is entirely on barge deck towards stern. The second load being the maximum sagging case where the topside is at the final location on the deck of barge for transportation. Results of the detailed FE analysis confirmed the structural integrity of the barge showing all the stresses and displacements are below allowable limits for all load cases. Two main advantages were observed through detailed modelling of the entire barge. Firstly, a faster preprocessing time is as compared to shell-beam models. Secondly, increasing the mesh density in critical locations in global FE model will be equivalent to a sub-model in this case. Thus, eliminating the need for analyzing any detail separately.
{"title":"Detailed Finite Element Analysis of 180 M Deck Cargo / Launch Barge B42","authors":"Fikri Bashar Yalchiner, R. Agrawal, F. Kamal, Oussama Takieddine","doi":"10.2118/197548-ms","DOIUrl":"https://doi.org/10.2118/197548-ms","url":null,"abstract":"In this study, a detailed finite element analysis methodology of a 180 m deck cargo/launch barge B42 for 32,000 MT topside load is described and results are presented. Using Finite Element Method (FEM) for large welded steel structures such as a deck cargo/launch barge has been quite challenging in past because the engineer had to observe the balance between solution accuracy and numerical efficiency. However, recent improvements in solver algorithms in FEM packages and increasing core processor numbers in computers enable engineers to include a lot more details to their FE model so that accurate stiffness and mass of the structure can be simulated. In this study, the entire barge is modelled in ANSYS Software using shell elements including longitudinal beams, stiffeners, flanges, base plates, skid tracks and outriggers.\u0000 Two most critical load cases were analyzed; the first is the maximum hogging condition which occurs in the topside loadout sequence where the topside is entirely on barge deck towards stern. The second load being the maximum sagging case where the topside is at the final location on the deck of barge for transportation.\u0000 Results of the detailed FE analysis confirmed the structural integrity of the barge showing all the stresses and displacements are below allowable limits for all load cases. Two main advantages were observed through detailed modelling of the entire barge. Firstly, a faster preprocessing time is as compared to shell-beam models. Secondly, increasing the mesh density in critical locations in global FE model will be equivalent to a sub-model in this case. Thus, eliminating the need for analyzing any detail separately.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"106 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79558330","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}
In 2016, the IMO has decided that the global fuel Sulphur limit of 0.50% on marine fuel oil would enter into force on 1 January 2020 ("IMO 2020 Global Sulphur Cap"). It is one of the biggest challenges for the marine industry that it had experienced in the modern era for its magnitude and urgency. Then in 2018, the IMO adopted an initial strategy of the reduction of greenhouse gas emission from international shipping in 2018 ("IMO GHG Initial Strategy"). It is a landmark decision by the IMO as it envisions a reduction gross greenhouse gas emission from international shipping and phase them out entirely for the first time. The IMO GHG Initial Strategy is not imminent comparing with the IMO 2020 Global Sulphur Cap, but it would be more serious and strenuous for its technical difficulties or practicability. By this presentation, we are going to describe where we are and where we are headed as to this topic by illustrating history and background, on-going discussions and trend on incremental reinforcement of environmental restriction in the maritime sector, possible options and solutions and those innovation gaps and so on.
{"title":"IMO 2020 May Only Be A Beginning -Reinforcement of Maritime Environmental Regulations and Its Impact on Oil & Gas Industry","authors":"M. Nakano","doi":"10.2118/197116-ms","DOIUrl":"https://doi.org/10.2118/197116-ms","url":null,"abstract":"\u0000 In 2016, the IMO has decided that the global fuel Sulphur limit of 0.50% on marine fuel oil would enter into force on 1 January 2020 (\"IMO 2020 Global Sulphur Cap\"). It is one of the biggest challenges for the marine industry that it had experienced in the modern era for its magnitude and urgency. Then in 2018, the IMO adopted an initial strategy of the reduction of greenhouse gas emission from international shipping in 2018 (\"IMO GHG Initial Strategy\"). It is a landmark decision by the IMO as it envisions a reduction gross greenhouse gas emission from international shipping and phase them out entirely for the first time. The IMO GHG Initial Strategy is not imminent comparing with the IMO 2020 Global Sulphur Cap, but it would be more serious and strenuous for its technical difficulties or practicability. By this presentation, we are going to describe where we are and where we are headed as to this topic by illustrating history and background, on-going discussions and trend on incremental reinforcement of environmental restriction in the maritime sector, possible options and solutions and those innovation gaps and so on.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80941105","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}
Z. Alyousef, Othman Swaie, A. Alabdulwahab, S. Kokal
Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity. In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %. The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions
{"title":"Direct Thickening of Supercritical Carbon Dioxide Using CO2-Soluble Polymer","authors":"Z. Alyousef, Othman Swaie, A. Alabdulwahab, S. Kokal","doi":"10.2118/197185-ms","DOIUrl":"https://doi.org/10.2118/197185-ms","url":null,"abstract":"\u0000 Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity.\u0000 In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %.\u0000 The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"127 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82730632","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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