Z. Channa, Salama Al Qubaisi, Ahmed Khaleefa Al-Neaimi, Ahmed Mahfoudh Al Syari, Omar Yousef Al-Shehhi, Salman. F. Nofal, M. Khan, Fazeel Ahmed, Hocine Khemisa, Mohamed Al Feky, Mahmoud Abdel-Aziz, Freddy Gutieirrez, Ahmed Fayyad Obeid
In the case study field, most of the wells are being completed with dual strings where there is no accessibility in the upper zone (short string). This leads to no well intervention in the future if there is any gas or water breakthrough or in some cases the formation collapse. However, formation collapse was recently observed in the certain dense (impermeable) layers which are liable to hole collapse when in contact with HCl acid during stimulation operation hence resulting in hole plugging. This leads to losing the production / injection from the upper zone and requires rig workover to clean out and recomplete the well. This phenonmenon was further confirmed by several experiments performed on different core samples in the Lab. A quick and cost effective solution was looked into and found that 4-1/2" liner, called "drop-off", can be run and set in the upper drain of the well to avoid any future breakthroughs or hole collapse. 4-1/2" drop-off liner was successfully run in multiple wells and proved to be very efficient. This cost effective innovative technique resulted in restoring the wellbore stability and help in sustaining the production from the upper drain.
{"title":"An Innovative Technique to Sustain Well Performance","authors":"Z. Channa, Salama Al Qubaisi, Ahmed Khaleefa Al-Neaimi, Ahmed Mahfoudh Al Syari, Omar Yousef Al-Shehhi, Salman. F. Nofal, M. Khan, Fazeel Ahmed, Hocine Khemisa, Mohamed Al Feky, Mahmoud Abdel-Aziz, Freddy Gutieirrez, Ahmed Fayyad Obeid","doi":"10.2118/192832-MS","DOIUrl":"https://doi.org/10.2118/192832-MS","url":null,"abstract":"\u0000 In the case study field, most of the wells are being completed with dual strings where there is no accessibility in the upper zone (short string). This leads to no well intervention in the future if there is any gas or water breakthrough or in some cases the formation collapse. However, formation collapse was recently observed in the certain dense (impermeable) layers which are liable to hole collapse when in contact with HCl acid during stimulation operation hence resulting in hole plugging. This leads to losing the production / injection from the upper zone and requires rig workover to clean out and recomplete the well. This phenonmenon was further confirmed by several experiments performed on different core samples in the Lab. A quick and cost effective solution was looked into and found that 4-1/2\" liner, called \"drop-off\", can be run and set in the upper drain of the well to avoid any future breakthroughs or hole collapse. 4-1/2\" drop-off liner was successfully run in multiple wells and proved to be very efficient. This cost effective innovative technique resulted in restoring the wellbore stability and help in sustaining the production from the upper drain.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"114 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78156264","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}
Recently Al-Saedi and Flori et al. (2018a) studied the potential of low salinity alternating steam flooding (LSASF) in laboratory Berea sandstone cores and the results were promising for increasing heavy oil recovery. In this study, we applied the new LSASF method on oil-impregnated reservoir sandstone cores from the Bartlesville sandstone reservoir in eastern Kansas. These samples contain high viscous oil up to 600 cp. Combining low salinity water (LS water) flooding and steam flooding is a novel idea which takes advantage of the relative strengths of both methods. LS water has been extensively studied by many researchers with promising results. Steamflooding is also much studied for applications particularly in heavy oil fields where recovery is increased by reducing the oil viscosity. The density difference between steam and heavy oil raises difficult problems in some reservoirs that can only be solved by injecting water with steam. In particular, those problems are gravity override, channeling, and early breakthrough. In this study, numerous reservoir sandstone cores were retrieved from the Bartlesville sandstone reservoir and cleaned, dried, vacuumed, and saturated with formation water (FW) that was identical to the reservoir FW. The water was displaced with a heavy crude oil to achieve Swi, and pre–aged for five weeks at 90°C. These cores were then flooded with 2 PV FW and then followed by different cycles of LS water + steam. A variety of LS water salinities were used (d4FW, d8FW, and d40FW). The laboratory experiments showed that optimum recovery is achieved by diluting the FW 40 times and using the same water in a shorter steam cycle. The oil recovery was 70.6% of the OOIP, which represents a quite high percentage of oil recovery in heavy oil reservoirs. The results of contact angle showed that the cores flooded using the novel LSASF were shifted to more water–wet conditions. Chemical analyses showed that using this novel LS water plus steam method improves recovery by enhancing the permeability of the rock, reducing precipitation caused by LS water flooding, and increasing dissolution of minerals which increased oil recovery. We also developed the LS water alternating steam flood in order to gather the benefits of LS water itself and to reduce oil viscosity by steam and prevent the aforementioned steam problems by using LS water.
{"title":"Coupling Low Salinity Water Flooding and Steam Flooding for Heavy Oil in Sandstone Reservoirs; Low Salinity-Alternating-Steam Flooding LSASF: A Novel EOR Technique","authors":"N. A. Hasan, R. Flori, Alsaba Mortadha","doi":"10.2118/192981-MS","DOIUrl":"https://doi.org/10.2118/192981-MS","url":null,"abstract":"\u0000 Recently Al-Saedi and Flori et al. (2018a) studied the potential of low salinity alternating steam flooding (LSASF) in laboratory Berea sandstone cores and the results were promising for increasing heavy oil recovery. In this study, we applied the new LSASF method on oil-impregnated reservoir sandstone cores from the Bartlesville sandstone reservoir in eastern Kansas. These samples contain high viscous oil up to 600 cp.\u0000 Combining low salinity water (LS water) flooding and steam flooding is a novel idea which takes advantage of the relative strengths of both methods. LS water has been extensively studied by many researchers with promising results. Steamflooding is also much studied for applications particularly in heavy oil fields where recovery is increased by reducing the oil viscosity. The density difference between steam and heavy oil raises difficult problems in some reservoirs that can only be solved by injecting water with steam. In particular, those problems are gravity override, channeling, and early breakthrough.\u0000 In this study, numerous reservoir sandstone cores were retrieved from the Bartlesville sandstone reservoir and cleaned, dried, vacuumed, and saturated with formation water (FW) that was identical to the reservoir FW. The water was displaced with a heavy crude oil to achieve Swi, and pre–aged for five weeks at 90°C. These cores were then flooded with 2 PV FW and then followed by different cycles of LS water + steam. A variety of LS water salinities were used (d4FW, d8FW, and d40FW).\u0000 The laboratory experiments showed that optimum recovery is achieved by diluting the FW 40 times and using the same water in a shorter steam cycle. The oil recovery was 70.6% of the OOIP, which represents a quite high percentage of oil recovery in heavy oil reservoirs. The results of contact angle showed that the cores flooded using the novel LSASF were shifted to more water–wet conditions. Chemical analyses showed that using this novel LS water plus steam method improves recovery by enhancing the permeability of the rock, reducing precipitation caused by LS water flooding, and increasing dissolution of minerals which increased oil recovery. We also developed the LS water alternating steam flood in order to gather the benefits of LS water itself and to reduce oil viscosity by steam and prevent the aforementioned steam problems by using LS water.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82308245","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}
Recent advancements in well design and completion technology have been tested in unconventional resource plays with wide variety of results. This paper discusses the evolution and performance analysis of the different well designs in a tight unconventional oil play in North America. A brief description is given of the different chronological well types in the play (i.e. standard horizontal wells, multi-lateral wells, and extended reach horizontal wells). The performance of such advanced wells is analyzed. The flow regimes encountered around multi-lateral and extended reach horizontal wells are described using diagnostic plots of time rate and pressure (TRP) data. These regimes are related to Arps exponent b-factor. So far, there is little information of such flow regimes or the ranges of b-factor for multi-lateral wells in tight unconventional plays. In multi-lateral and extended reach horizontal wells, a period of frac water cleaning may be seen at the initial production. Apparent early bilinear or linear flow regimes might be observed afterwards. In this tight oil play, later multi-phase effects dominate the flow regimes and cause deviations from the early bilinear and linear flow. Late second linear flow regime is not seen in the analyzed data of standard horizontal wells, multi-lateral wells, or extended reach horizontal wells. In this play, multi-phase effects cause late time lower b-factor. In many instances, late time b-factor is lower than 1. This work emphasizes on the reserves estimation of these modern wells in this play. Extended reach horizontal wells have shown better late time b-factor and normalized Initial Production of 90 days "IP90" per lateral length compared to multi-lateral wells. This might give an indication of the higher completion efficiency in the extended reach horizontal wells. Based on this work, Extended reach horizontal wells have higher Estimated Ultimate Recovery "EUR" compared to both multi-lateral and standard horizontal wells. Development of unconventional plays by drilling longer single lateral horizontal wells while reducing the inter frac stages spacing is becoming the norm. This work helps to decipher the performance of multi-lateral and extended reach wells in unconventional plays. This leads to improving the development concepts and reserves evaluation methods of these modern wells in unconventional formations.
{"title":"Deciphering the Performance of Multi-Lateral and Extended Reach Wells for Reserves Evaluation in Unconventional Resource Plays","authors":"A. Abdelmawla","doi":"10.2118/192993-MS","DOIUrl":"https://doi.org/10.2118/192993-MS","url":null,"abstract":"\u0000 Recent advancements in well design and completion technology have been tested in unconventional resource plays with wide variety of results. This paper discusses the evolution and performance analysis of the different well designs in a tight unconventional oil play in North America. A brief description is given of the different chronological well types in the play (i.e. standard horizontal wells, multi-lateral wells, and extended reach horizontal wells). The performance of such advanced wells is analyzed. The flow regimes encountered around multi-lateral and extended reach horizontal wells are described using diagnostic plots of time rate and pressure (TRP) data. These regimes are related to Arps exponent b-factor. So far, there is little information of such flow regimes or the ranges of b-factor for multi-lateral wells in tight unconventional plays.\u0000 In multi-lateral and extended reach horizontal wells, a period of frac water cleaning may be seen at the initial production. Apparent early bilinear or linear flow regimes might be observed afterwards. In this tight oil play, later multi-phase effects dominate the flow regimes and cause deviations from the early bilinear and linear flow. Late second linear flow regime is not seen in the analyzed data of standard horizontal wells, multi-lateral wells, or extended reach horizontal wells. In this play, multi-phase effects cause late time lower b-factor. In many instances, late time b-factor is lower than 1.\u0000 This work emphasizes on the reserves estimation of these modern wells in this play. Extended reach horizontal wells have shown better late time b-factor and normalized Initial Production of 90 days \"IP90\" per lateral length compared to multi-lateral wells. This might give an indication of the higher completion efficiency in the extended reach horizontal wells.\u0000 Based on this work, Extended reach horizontal wells have higher Estimated Ultimate Recovery \"EUR\" compared to both multi-lateral and standard horizontal wells. Development of unconventional plays by drilling longer single lateral horizontal wells while reducing the inter frac stages spacing is becoming the norm.\u0000 This work helps to decipher the performance of multi-lateral and extended reach wells in unconventional plays. This leads to improving the development concepts and reserves evaluation methods of these modern wells in unconventional formations.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76437012","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 objective of this paper is to describe experiments conducted to investigate osmosis as a mechanism for low-salinity enhanced oil recovery (EOR). For this purpose, an experiment was designed to facilitate enhanced oil recovery by osmosis-induced connate water expansion, while at the same time reducing the contributions of other proposed low-salinity mechanisms. Considerations were also made to achieve osmotic water transport rates comparable to what is expected at reservoir temperature. The correlation between enhanced oil recovery and the surface-to-volume ratio was of particular interest. Because the osmotic pressure gradients occur over distances comparable to the pore size, it is plausible that fluid redistribution due to osmosis would lead to a fairly local redistribution of oil, and thereby have a small impact on overall enhanced recovery in the field. However, near exposed surfaces, this local redistribution may result in oil production. Previous investigations of osmosis as an underlying low-salinity mechanism have consisted of visualization experiments, where water transport and oil movement under influence of osmotic gradients have been observed. Our experiments are intended to increase the understanding of the relative importance of osmosis in both small-scale low-salinity experiment results, and for field-scale low-salinity flooding. In the experiments, oil-wet sandstone samples with different surface-to-volume ratios were saturated with high-salinity water and oil to irreducible water saturation. The samples were first left to spontaneous imbibe in high-salinity water and afterward in low-salinity water. Additional oil production from spontaneous imbibition of low-salinity was recorded and compared with the surface-to-volume ratio. The experiment was performed twice, at both ambient and elevated temperatures. The experiments at ambient temperature resulted in increased oil production values of 8-22% of pore volume by low-salinity spontaneous imbibition. No clear correlation was found between increased oil recovery and the surface-to-volume ratio. A correlation was, however, seen between increased oil production and the pore volume. Thus, increased oil production by low-salinity imbibition seems to be proportionate to the pore volume. The experiments at elevated temperature resulted in low values of increased oil production by low-salinity spontaneous imbibition, and the values do not seem to correlate with either surface area or pore volume. The low response is believed to be caused by thermal effects from repeated heating and cooling of the samples during the preparations. Our results cannot dismiss osmosis as an important mechanism for low-salinity EOR. Possible explanations for the correlation between increased oil production and pore volume are hysteresis and simultaneous connate water expansion throughout the core.
{"title":"Experimental Investigation of Osmosis as a Mechanism for Low-Salinity EOR","authors":"Erik Norrud Pollen, C. Berg","doi":"10.2118/192753-MS","DOIUrl":"https://doi.org/10.2118/192753-MS","url":null,"abstract":"\u0000 The objective of this paper is to describe experiments conducted to investigate osmosis as a mechanism for low-salinity enhanced oil recovery (EOR). For this purpose, an experiment was designed to facilitate enhanced oil recovery by osmosis-induced connate water expansion, while at the same time reducing the contributions of other proposed low-salinity mechanisms. Considerations were also made to achieve osmotic water transport rates comparable to what is expected at reservoir temperature.\u0000 The correlation between enhanced oil recovery and the surface-to-volume ratio was of particular interest. Because the osmotic pressure gradients occur over distances comparable to the pore size, it is plausible that fluid redistribution due to osmosis would lead to a fairly local redistribution of oil, and thereby have a small impact on overall enhanced recovery in the field. However, near exposed surfaces, this local redistribution may result in oil production.\u0000 Previous investigations of osmosis as an underlying low-salinity mechanism have consisted of visualization experiments, where water transport and oil movement under influence of osmotic gradients have been observed. Our experiments are intended to increase the understanding of the relative importance of osmosis in both small-scale low-salinity experiment results, and for field-scale low-salinity flooding.\u0000 In the experiments, oil-wet sandstone samples with different surface-to-volume ratios were saturated with high-salinity water and oil to irreducible water saturation. The samples were first left to spontaneous imbibe in high-salinity water and afterward in low-salinity water. Additional oil production from spontaneous imbibition of low-salinity was recorded and compared with the surface-to-volume ratio. The experiment was performed twice, at both ambient and elevated temperatures.\u0000 The experiments at ambient temperature resulted in increased oil production values of 8-22% of pore volume by low-salinity spontaneous imbibition. No clear correlation was found between increased oil recovery and the surface-to-volume ratio. A correlation was, however, seen between increased oil production and the pore volume. Thus, increased oil production by low-salinity imbibition seems to be proportionate to the pore volume.\u0000 The experiments at elevated temperature resulted in low values of increased oil production by low-salinity spontaneous imbibition, and the values do not seem to correlate with either surface area or pore volume. The low response is believed to be caused by thermal effects from repeated heating and cooling of the samples during the preparations.\u0000 Our results cannot dismiss osmosis as an important mechanism for low-salinity EOR. Possible explanations for the correlation between increased oil production and pore volume are hysteresis and simultaneous connate water expansion throughout the core.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86269051","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 Vinci, M. Pirrone, G. Galli, D. Macaluso, François Rocco, Roberto Zarauti
In new wells with hole stability problems, which require to be cased and cemented immediately, and in old wells without a complete or reliable log dataset, a formation evaluation by means of quantitative open-hole (OH) log interpretation is not possible. Cased-hole (CH) logging can represent the only solution, despite being usually considered highly uncertain. This paper discusses the standalone use of CH logs, integrated in a probabilistic framework, for petrophysical characterization and uncertainty propagation purposes. The approach consists of a full statistical workflow aimed at a formation evaluation with only CH logs as input, also including capture cross-sections, carbon/oxygen ratios and inelastic spectra. Several wells with complete OH petrophysical characterization have been used to define the rate of success of this methodology in different scenarios. Furthermore, a Monte Carlo framework is introduced to account for the uncertainty quantification of the CH outputs. The final outcome is the set of probability distribution functions of the petrophysical properties, the most probable scenario and the associated uncertainty. Three real operative applications, in scenarios with no OH logs available, are presented: an old well without a complete/reliable OH log dataset (gas- and oil-bearing sandstone reservoir with variable salinity), and two new wells with hole stability problems (in a sandstone and in a carbonate oil-bearing reservoir at high formation water salinity). In the latter cases, numerical simulations are performed to correctly handle mud-filtrate invasion effects for a robust modeling also in the shallow zone investigated by CH logs. In all these challenging conditions, a complete formation evaluation has been obtained, and successfully used to select proper intervals to perforate. The increased hydrocarbon production driven by the outcomes of the standalone CH characterization further validates the efficiency of this method. Though CH logging is a well-known technology in reservoir monitoring, its successful standalone use for reliable formation evaluation can represent an important step forward in reservoir characterization processes, in all those cases where OH data are not available or too risky to acquire. Finally, the value of uncertainty analysis has a huge relevance for appropriate production optimization and reservoir modeling strategies.
{"title":"Standalone Cased-Hole Formation Evaluation and Uncertainty Propagation to Increase Well Deliverability in Challenging Environments","authors":"Fabio Vinci, M. Pirrone, G. Galli, D. Macaluso, François Rocco, Roberto Zarauti","doi":"10.2118/192887-MS","DOIUrl":"https://doi.org/10.2118/192887-MS","url":null,"abstract":"\u0000 In new wells with hole stability problems, which require to be cased and cemented immediately, and in old wells without a complete or reliable log dataset, a formation evaluation by means of quantitative open-hole (OH) log interpretation is not possible. Cased-hole (CH) logging can represent the only solution, despite being usually considered highly uncertain. This paper discusses the standalone use of CH logs, integrated in a probabilistic framework, for petrophysical characterization and uncertainty propagation purposes.\u0000 The approach consists of a full statistical workflow aimed at a formation evaluation with only CH logs as input, also including capture cross-sections, carbon/oxygen ratios and inelastic spectra. Several wells with complete OH petrophysical characterization have been used to define the rate of success of this methodology in different scenarios. Furthermore, a Monte Carlo framework is introduced to account for the uncertainty quantification of the CH outputs. The final outcome is the set of probability distribution functions of the petrophysical properties, the most probable scenario and the associated uncertainty.\u0000 Three real operative applications, in scenarios with no OH logs available, are presented: an old well without a complete/reliable OH log dataset (gas- and oil-bearing sandstone reservoir with variable salinity), and two new wells with hole stability problems (in a sandstone and in a carbonate oil-bearing reservoir at high formation water salinity). In the latter cases, numerical simulations are performed to correctly handle mud-filtrate invasion effects for a robust modeling also in the shallow zone investigated by CH logs. In all these challenging conditions, a complete formation evaluation has been obtained, and successfully used to select proper intervals to perforate. The increased hydrocarbon production driven by the outcomes of the standalone CH characterization further validates the efficiency of this method.\u0000 Though CH logging is a well-known technology in reservoir monitoring, its successful standalone use for reliable formation evaluation can represent an important step forward in reservoir characterization processes, in all those cases where OH data are not available or too risky to acquire. Finally, the value of uncertainty analysis has a huge relevance for appropriate production optimization and reservoir modeling strategies.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88812476","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. Amo, T. Taniwaki, M. Yamanaka, A. Kato, Emiko Shinbo, S. Shibuya
Crude oils and rock samples from Cenomanian carbonate oil field (Field A) in the offshore Abu Dhabi were investigated in order to define oil families, paleoenvironment, origin of organic materials and thermal maturity because the origin of crude oils and their thermal history in this field has not been understood well. Especially, maturity profile in this area has not been determined yet because the source rocks don't contain enough amount of vitrinite due to the dominance of marine organic matters. Field A has two culminations above OWC: North structure and South structure. Therefore, we investigated oils from both structures to figure out the geochemical features of each culmination. The Cenomanian carbonate rocks of Field A are composed of shallow marine porous limestone (reservoir rocks) and deep marine lime mudstone (seal rocks and source rocks). Saturated biomarkers (n-alkanes, isoprenoids, steranes and triterpanes) of crude oils from shallow marine porous limestone and core samples from deep marine lime mudstone were determined using gas chromatography-mass spectrometry (GC/MS), gas chromatography-mass spectrometry-mass spectrometry (GC/MS/MS) and gas chromatography-combustion-isotope ratio mass spectrometry (GC/C/IRMS). Ternary diagrams of C27-C29 steranes of all oil samples and core samples show significant similarity among crude oils and source rocks in Cenomanian age. High amount of C30 sterane and the ratio of C27-C29 steranes suggest that the crude oils were generated from Cenomanian marine source rocks. Biomarker maturity parameters such as Ts to Tm ratio and diasterane (Dia) to regular sterane ratio (Reg) were slightly different among the crude oils. The crude oils from South structure were slightly more maturated than those from North structure. The stable carbon isotopic values of individual n-alkanes in the crude oil would be classified into two crude oil families: dominance of lighter carbon in North structure and relatively heavier carbon in South structure. These results were consistent with the results of biomarker maturity parameters such as Ts/(Ts + Tm) and Dia/(Dia + Reg). Thus it was confirmed that the crude oils of North structure and South structure were from same Cenomanian source rock, however, thermal maturity of the crude oils were slightly different between North structure and South structure.
{"title":"A Biomarker and Isotopic Study of the Source Rock Organofacies, Oil Families, Source-oil Correlation and Thermal Maturity of Cenomanian Petroleum Systems in the Offshore Abu Dhabi","authors":"M. Amo, T. Taniwaki, M. Yamanaka, A. Kato, Emiko Shinbo, S. Shibuya","doi":"10.2118/192671-MS","DOIUrl":"https://doi.org/10.2118/192671-MS","url":null,"abstract":"\u0000 Crude oils and rock samples from Cenomanian carbonate oil field (Field A) in the offshore Abu Dhabi were investigated in order to define oil families, paleoenvironment, origin of organic materials and thermal maturity because the origin of crude oils and their thermal history in this field has not been understood well. Especially, maturity profile in this area has not been determined yet because the source rocks don't contain enough amount of vitrinite due to the dominance of marine organic matters. Field A has two culminations above OWC: North structure and South structure. Therefore, we investigated oils from both structures to figure out the geochemical features of each culmination. The Cenomanian carbonate rocks of Field A are composed of shallow marine porous limestone (reservoir rocks) and deep marine lime mudstone (seal rocks and source rocks). Saturated biomarkers (n-alkanes, isoprenoids, steranes and triterpanes) of crude oils from shallow marine porous limestone and core samples from deep marine lime mudstone were determined using gas chromatography-mass spectrometry (GC/MS), gas chromatography-mass spectrometry-mass spectrometry (GC/MS/MS) and gas chromatography-combustion-isotope ratio mass spectrometry (GC/C/IRMS). Ternary diagrams of C27-C29 steranes of all oil samples and core samples show significant similarity among crude oils and source rocks in Cenomanian age. High amount of C30 sterane and the ratio of C27-C29 steranes suggest that the crude oils were generated from Cenomanian marine source rocks. Biomarker maturity parameters such as Ts to Tm ratio and diasterane (Dia) to regular sterane ratio (Reg) were slightly different among the crude oils. The crude oils from South structure were slightly more maturated than those from North structure. The stable carbon isotopic values of individual n-alkanes in the crude oil would be classified into two crude oil families: dominance of lighter carbon in North structure and relatively heavier carbon in South structure. These results were consistent with the results of biomarker maturity parameters such as Ts/(Ts + Tm) and Dia/(Dia + Reg). Thus it was confirmed that the crude oils of North structure and South structure were from same Cenomanian source rock, however, thermal maturity of the crude oils were slightly different between North structure and South structure.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88541405","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}
Muhammad Triandi, I. Chigbo, Thanudcha Khunmek, I. M. Ismail
The Jasmine Field sandstone reservoir described in the paper is highly compartmentalized, has a sand thickness of about 30-40ft, reservoir pressure is supported by a strong aquifer, and most wells have high productivity. However, in the particular fault block of interest, a gas cap is present, which is normally not present in other fault blocks. This reduces the oil sand thickness to about 20 ft, with a big gas cap above and water below. To efficiently produce the oil rim in this area, a horizontal well was required, with an electrical submersible pumps (ESP) to aid lift. Since ESPs don't typically handle gas very well, the challenge was to ensure the well is economic by preventing premature gas breakthrough, and hence increase oil recovery. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil.When used in a horizontal well, segmented into multiple compartments, this device prevents excessive production of unwanted fluids after breakthrough occurs in one or more compartments. The JS-06 well was drilled with almost 2000 ft horizontal length within the original thin oil column, with gas on top and water below. AICD flow loop testing, performance modelling, candidate selection, and completion design for this well was focused on gas production control, given that gas production was the main concern. Post implementation and production, gas production has been controlled very well compared to the base case conventional completion. The gas oil ratio (GOR) observed from nearby wells was within the normal production range, which has allowed more oil to be produced from the JS-06 well. The production results observed were consistent with modelling and laboratory flow testing, thereby increasing confidence in the methods employed in designing the AICD completion for the well and in AICD modelling and candidate selection. The successful implementation of AICD in this well has opened up another similar opportunity, which are currently being evaluated for the same application
{"title":"Field Case: Use of Autonomous Inflow Control Devices to Increase Oil Production in a Thin Oil Rim Reservoir in the Gulf of Thailand","authors":"Muhammad Triandi, I. Chigbo, Thanudcha Khunmek, I. M. Ismail","doi":"10.2118/193305-MS","DOIUrl":"https://doi.org/10.2118/193305-MS","url":null,"abstract":"\u0000 The Jasmine Field sandstone reservoir described in the paper is highly compartmentalized, has a sand thickness of about 30-40ft, reservoir pressure is supported by a strong aquifer, and most wells have high productivity. However, in the particular fault block of interest, a gas cap is present, which is normally not present in other fault blocks. This reduces the oil sand thickness to about 20 ft, with a big gas cap above and water below. To efficiently produce the oil rim in this area, a horizontal well was required, with an electrical submersible pumps (ESP) to aid lift. Since ESPs don't typically handle gas very well, the challenge was to ensure the well is economic by preventing premature gas breakthrough, and hence increase oil recovery.\u0000 The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil.When used in a horizontal well, segmented into multiple compartments, this device prevents excessive production of unwanted fluids after breakthrough occurs in one or more compartments. The JS-06 well was drilled with almost 2000 ft horizontal length within the original thin oil column, with gas on top and water below. AICD flow loop testing, performance modelling, candidate selection, and completion design for this well was focused on gas production control, given that gas production was the main concern.\u0000 Post implementation and production, gas production has been controlled very well compared to the base case conventional completion. The gas oil ratio (GOR) observed from nearby wells was within the normal production range, which has allowed more oil to be produced from the JS-06 well. The production results observed were consistent with modelling and laboratory flow testing, thereby increasing confidence in the methods employed in designing the AICD completion for the well and in AICD modelling and candidate selection.\u0000 The successful implementation of AICD in this well has opened up another similar opportunity, which are currently being evaluated for the same application","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 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":"88565676","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}
Abdulaziz Alqasim, Amer Al-Anazi, Abdulrahman Bin Omar, Muataz Ghamdi
In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state. The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles. This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.
{"title":"Asphaltene Precipitation: A Review on Remediation Techniques and Prevention Strategies","authors":"Abdulaziz Alqasim, Amer Al-Anazi, Abdulrahman Bin Omar, Muataz Ghamdi","doi":"10.2118/192784-MS","DOIUrl":"https://doi.org/10.2118/192784-MS","url":null,"abstract":"\u0000 In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state.\u0000 The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles.\u0000 This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88802550","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}
Wellbore quality might not always be the top priority from a drilling perspective due to the misconception that quality comes at the expense of drilling efficiency. This is indeed a misconception since a compromised wellbore quality, which can be defined as non-uniform wellbore shape due to the presence of enlargements and tight spots, is a sign of energy waste. The result of this is actually drilling inefficiency. It is proposed that drilling quality and efficiency come hand in hand provided that they are planned to be connected by two factors: drillstring design and geomechanics modelling. Drillstrings are designed to prevent mechanical failure and produce the highest possible ROP. Another aspect of the design is preventing vibrations and hole patterns. This work employs surface drilling parameters and geomechanics principles to correlate the drilled wellbore quality to the drillstring design. Surface drilling parameters and bit wear grading reports are used as diagnostic tools to check for dissipated energy and string vibrations, where the dissipated energy can be either mechanical, hydraulic, or both. This is then cross-referenced with multi-arm caliper measurements to confirm the influence on wellbore quality. A geomechanics model is incorporated to filter out in-situ stresses induced breakouts from breakouts and hole patterns caused by interactions with the drillstring. The role played by the drillstring design on this whole process is explored. Finally, drillstring modifications are proposed based on geomechanics considerations. The illustrated case shows a strong correlation between the shape of the wellbore, the spacing of the different bottomhole assembly components, and the formation mechanical properties. Another illustrated case, which utilized a modified drillstring design showed significant improvement in the wellbore quality. The results of the different cases confirm that incorporating geomechanical analysis in the process of drillstring design will help reconcile both of drilling quality and of efficiency.
{"title":"Drillstring Vibrations and Wellbore Quality: Where Drillstring Design Meets Geomechanics","authors":"H. Albahrani, A. Al-Yami","doi":"10.2118/193253-MS","DOIUrl":"https://doi.org/10.2118/193253-MS","url":null,"abstract":"\u0000 Wellbore quality might not always be the top priority from a drilling perspective due to the misconception that quality comes at the expense of drilling efficiency. This is indeed a misconception since a compromised wellbore quality, which can be defined as non-uniform wellbore shape due to the presence of enlargements and tight spots, is a sign of energy waste. The result of this is actually drilling inefficiency. It is proposed that drilling quality and efficiency come hand in hand provided that they are planned to be connected by two factors: drillstring design and geomechanics modelling. Drillstrings are designed to prevent mechanical failure and produce the highest possible ROP. Another aspect of the design is preventing vibrations and hole patterns. This work employs surface drilling parameters and geomechanics principles to correlate the drilled wellbore quality to the drillstring design.\u0000 Surface drilling parameters and bit wear grading reports are used as diagnostic tools to check for dissipated energy and string vibrations, where the dissipated energy can be either mechanical, hydraulic, or both. This is then cross-referenced with multi-arm caliper measurements to confirm the influence on wellbore quality. A geomechanics model is incorporated to filter out in-situ stresses induced breakouts from breakouts and hole patterns caused by interactions with the drillstring. The role played by the drillstring design on this whole process is explored. Finally, drillstring modifications are proposed based on geomechanics considerations.\u0000 The illustrated case shows a strong correlation between the shape of the wellbore, the spacing of the different bottomhole assembly components, and the formation mechanical properties. Another illustrated case, which utilized a modified drillstring design showed significant improvement in the wellbore quality. The results of the different cases confirm that incorporating geomechanical analysis in the process of drillstring design will help reconcile both of drilling quality and of efficiency.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89302612","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}
Asset-intensive companies face tighter maintenance budgets, stricter regulations and increased pressure to improve asset performance, whilst confronted with aging assets and workforce. Managing an asset with these challenges requires informed decision-making based on insight, knowledge and forecasting. Data is a powerful tool to achieve this goal. ‘Internet of things’ innovations have led to a rapid increase in the availability of technical and business data. A few years ago, techniques that were complex and expensive are now more affordable, accessible and increasingly important in order to compete in this world of rapid change. Field data is faster and immediately available for processing, while more relevant measurements and observations of similar or better quality are leading to more reliable information for decision-making.
{"title":"Asset Performance Management 4.0 Internet of Things iot Enabled Condition Monitoring, a Story from a Digital Maintenance Service Provider","authors":"Johan Ferket","doi":"10.2118/192636-MS","DOIUrl":"https://doi.org/10.2118/192636-MS","url":null,"abstract":"\u0000 Asset-intensive companies face tighter maintenance budgets, stricter regulations and increased pressure to improve asset performance, whilst confronted with aging assets and workforce. Managing an asset with these challenges requires informed decision-making based on insight, knowledge and forecasting. Data is a powerful tool to achieve this goal.\u0000 ‘Internet of things’ innovations have led to a rapid increase in the availability of technical and business data. A few years ago, techniques that were complex and expensive are now more affordable, accessible and increasingly important in order to compete in this world of rapid change.\u0000 Field data is faster and immediately available for processing, while more relevant measurements and observations of similar or better quality are leading to more reliable information for decision-making.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87408462","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：