It's difficult to fully discover all the geological reserves during exploration stage, because the fracture system of complex fault block oilfield is very complicated. As the reserve scale in single block is limited, the decline rate of the oilfield is usually very fast. As a result, finding new replacement reserves inside the oilfield is an important method to ensure stable production of complex fault block oilfields. Base on the improvement of the Vogel method and material balance method to calculate the reservoir dynamic reserves under the degassing conditions of A14 well area. Using Allan profiling to construct lithologic docking relationship between A14 well area and adjacent fault block. Calculate SGR(Shale Gouge Ratio) for different docking areas. According to the statistics of shale content and porosity in the oilfield area, core experiment results with porosity and displacement pressure, the displacement pressure on both sides of the fault docking area can be used to predict the oil column height of adjacent block. To ensure the initially high-speed production of A14 well area, it's necessary to reduce the times of shut-in static pressure measurement. The continuous reservoir pressure under the degassing conditions is calculated by the improvement of the Vogel method. Avoid the error of dynamic geological reserve calculation caused by too little reservoir pressure data. Result shows that the geological reserves of A14 well area is much smaller than its dynamic reserves. Study on the sealing property of faults around the A14 well area shows that the fault on the east side of the A14 well area is a non-closed fault, and the adjacent fault block is an oil-bearing fault block. Well A20 confirmed the oil-bearing properties for the fault block on the east side of the A14 well area. The result of pressure testing while drilling also shows that pressure drop in the east block of the A14 well area. All of that verify the reliability of previous research. Aiming at the development of complex fault block oilfield, a method based on dynamic reserves research result to study the sealing property of peripheral faults to predict the height of oil columns in adjacent blocks is proposed. Achieved the purpose of finding new replacement reserves inside the oilfield. The reliability of the research is verified by the pressure testing while drilling. It provides a valuable experience for the development in similar oilfield.
{"title":"A New Discovery in Complex Fault Block Oilfield Based on Dynamic Reserves Study and Fault Sealing Study: A Case Study of Bz29-4 Oilfield in Southern Bohai Bay","authors":"Pengyu Gao, L. Cao, Cong Jiang, Runsen Qin, Longtao Cui, Zhonghua Meng","doi":"10.2118/194804-MS","DOIUrl":"https://doi.org/10.2118/194804-MS","url":null,"abstract":"\u0000 It's difficult to fully discover all the geological reserves during exploration stage, because the fracture system of complex fault block oilfield is very complicated. As the reserve scale in single block is limited, the decline rate of the oilfield is usually very fast. As a result, finding new replacement reserves inside the oilfield is an important method to ensure stable production of complex fault block oilfields.\u0000 Base on the improvement of the Vogel method and material balance method to calculate the reservoir dynamic reserves under the degassing conditions of A14 well area. Using Allan profiling to construct lithologic docking relationship between A14 well area and adjacent fault block. Calculate SGR(Shale Gouge Ratio) for different docking areas. According to the statistics of shale content and porosity in the oilfield area, core experiment results with porosity and displacement pressure, the displacement pressure on both sides of the fault docking area can be used to predict the oil column height of adjacent block.\u0000 To ensure the initially high-speed production of A14 well area, it's necessary to reduce the times of shut-in static pressure measurement. The continuous reservoir pressure under the degassing conditions is calculated by the improvement of the Vogel method. Avoid the error of dynamic geological reserve calculation caused by too little reservoir pressure data. Result shows that the geological reserves of A14 well area is much smaller than its dynamic reserves. Study on the sealing property of faults around the A14 well area shows that the fault on the east side of the A14 well area is a non-closed fault, and the adjacent fault block is an oil-bearing fault block. Well A20 confirmed the oil-bearing properties for the fault block on the east side of the A14 well area. The result of pressure testing while drilling also shows that pressure drop in the east block of the A14 well area. All of that verify the reliability of previous research.\u0000 Aiming at the development of complex fault block oilfield, a method based on dynamic reserves research result to study the sealing property of peripheral faults to predict the height of oil columns in adjacent blocks is proposed. Achieved the purpose of finding new replacement reserves inside the oilfield. The reliability of the research is verified by the pressure testing while drilling. It provides a valuable experience for the development in similar oilfield.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90288689","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A.M.Q.M. Al-Ajmi, Abdulaziz Al-Rushoud, Ashis Gohain, F. Khatib, Hussain Al-Haj, Faisal Al-naqa, F. Al-Mutawa, Majed Al-Gharib, Hrishikesh Shinde, Saurabh Arora, Bader Arrar, Manar Bumaryoum, A. Al-Mousa, Rustem Sagirov, Tamer Reda, R. Hamed
To optimize production from a key reservoir, obtaining a core sample with minimum fluid invasion and damage was necessary. In addition, operational nonproductive time (NPT) related to drilling challenges, such as interbedded formations of varying formation pressures, wellbore instability in the reactive, stressed shale sections, and hole cleaning concerns, needed to be mitigated. This paper describes the design of the drilling fluid and its performance in the field. After completion of the first dump flood water injection well drilled using an 80/20 conventional nonaqueous fluid (NAF) weighted with barite, low injectivity was observed, which led to acquiring cores to analyze permeability and porosity along with the change in mineralogy resulting from long exposure of the reservoir in the water zone. A 70/30 organophilic clay-free (OCF) NAF was selected to mitigate equivalent circulating density (ECD) risks and minimize damage. Proprietary software was used to customize the bridging design, which was verified during laboratory testing, and to help ensure adequate hole cleaning with the customized low-ECD fluid. The engineered OCF NAF contained no damaging materials, such as barite, asphaltic material, or organophilic clay. OCF NAFs are well suited to low-ECD drilling operations because they are more resistant to weighting material sag than conventional NAF systems of similar rheology. This is a product of the high gel strengths developed, even in low-rheology (low-ECD) fluids. Downhole pressure fluctuations are low because these gels are fragile and break easily. For the well in which this OCF NAF was used, drilling, coring, and logging operations were successfully completed without incident. Four cores were acquired with minimal damage compared to the previous wells resulting from the engineered design of the bridging material and fluid-loss control polymers. In addition, there was minimal erosion to these four cores, which was a result of the low-ECD fragile gel fluid used. The fluid-loss control properties of the fluid were also effective in strengthening the wellbore and eliminating differential stuck pipe tendencies that had been observed in previous wells. The fluid properties resulted in minimal ECD, and the OCF NAF displayed excellent suspension along with improved pressure management; no pressure spikes occurred while breaking circulation. There was no NPT related to wellbore instability or any of the drilling challenges previously identified. This unique organophilic clay-free and organolignite-free drilling and coring fluid relies on a specialized technology involving an interaction between the emulsifier package and the polymer additives in the fluid. This provides the behaviors needed for reliable weight material suspension and suitable hole cleaning properties in a low-ECD drilling fluid. Together with the appropriately designed bridging package, the OCF NAF provided a better understanding of the reservoir characteristics by del
{"title":"Successful Field Application of Organophilic Clay-Free Invert Emulsion Fluid to Protect the Reservoir Core from Drilling Fluid Damage: Case Study from a Kuwait Field","authors":"A.M.Q.M. Al-Ajmi, Abdulaziz Al-Rushoud, Ashis Gohain, F. Khatib, Hussain Al-Haj, Faisal Al-naqa, F. Al-Mutawa, Majed Al-Gharib, Hrishikesh Shinde, Saurabh Arora, Bader Arrar, Manar Bumaryoum, A. Al-Mousa, Rustem Sagirov, Tamer Reda, R. Hamed","doi":"10.2118/194707-MS","DOIUrl":"https://doi.org/10.2118/194707-MS","url":null,"abstract":"\u0000 To optimize production from a key reservoir, obtaining a core sample with minimum fluid invasion and damage was necessary. In addition, operational nonproductive time (NPT) related to drilling challenges, such as interbedded formations of varying formation pressures, wellbore instability in the reactive, stressed shale sections, and hole cleaning concerns, needed to be mitigated. This paper describes the design of the drilling fluid and its performance in the field.\u0000 After completion of the first dump flood water injection well drilled using an 80/20 conventional nonaqueous fluid (NAF) weighted with barite, low injectivity was observed, which led to acquiring cores to analyze permeability and porosity along with the change in mineralogy resulting from long exposure of the reservoir in the water zone. A 70/30 organophilic clay-free (OCF) NAF was selected to mitigate equivalent circulating density (ECD) risks and minimize damage. Proprietary software was used to customize the bridging design, which was verified during laboratory testing, and to help ensure adequate hole cleaning with the customized low-ECD fluid.\u0000 The engineered OCF NAF contained no damaging materials, such as barite, asphaltic material, or organophilic clay. OCF NAFs are well suited to low-ECD drilling operations because they are more resistant to weighting material sag than conventional NAF systems of similar rheology. This is a product of the high gel strengths developed, even in low-rheology (low-ECD) fluids. Downhole pressure fluctuations are low because these gels are fragile and break easily. For the well in which this OCF NAF was used, drilling, coring, and logging operations were successfully completed without incident. Four cores were acquired with minimal damage compared to the previous wells resulting from the engineered design of the bridging material and fluid-loss control polymers. In addition, there was minimal erosion to these four cores, which was a result of the low-ECD fragile gel fluid used. The fluid-loss control properties of the fluid were also effective in strengthening the wellbore and eliminating differential stuck pipe tendencies that had been observed in previous wells. The fluid properties resulted in minimal ECD, and the OCF NAF displayed excellent suspension along with improved pressure management; no pressure spikes occurred while breaking circulation. There was no NPT related to wellbore instability or any of the drilling challenges previously identified.\u0000 This unique organophilic clay-free and organolignite-free drilling and coring fluid relies on a specialized technology involving an interaction between the emulsifier package and the polymer additives in the fluid. This provides the behaviors needed for reliable weight material suspension and suitable hole cleaning properties in a low-ECD drilling fluid. Together with the appropriately designed bridging package, the OCF NAF provided a better understanding of the reservoir characteristics by del","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78266563","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A solid understanding of challenging reservoir complexities such as, naturally fractured "super-k" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems. In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.
{"title":"An Integrated Approach to Deal with Challenges of Interpreting Pressure-Transient Data in Complex-Reservoir Systems","authors":"R. Guerrero, O. H. Al-Obathani","doi":"10.2118/195075-MS","DOIUrl":"https://doi.org/10.2118/195075-MS","url":null,"abstract":"\u0000 A solid understanding of challenging reservoir complexities such as, naturally fractured \"super-k\" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems.\u0000 In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76594827","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}
B. Hornby, Ruijia Wang, M. Collins, Joonshik Kim, R. Confer
This paper presents a case study in which new methods that use full-waveform sonic data are applied in an unconventional well setting to determine depth-dependent elastic anisotropy of formations penetrated by the well and estimate parameters of interest. The study objectives include the following: Estimate Thomsen's shear anisotropy parameter γ in an unconventional well that penetrates fast formationsUse rock physics and other approximations to further estimate a complete vertical transverse isotropic (VTI) elastic tensor at each depthCompare results with ground truth in terms of dynamic and static core measurementsUse these results to derive anisotropic geomechanical parameters for well completion and fracture treatment design and to compute upscaled seismic-equivalent elastic anisotropy for the calibration of anisotropic seismic velocity models Formation speeds in this well were extremely fast, typical for unconventional shale reservoirs, which created a challenging environment for estimating VTI Thomsen's parameter γ because of the extreme sensitivity of the inversion to the accuracy of the borehole fluid slowness estimate. The key to the study's success was development and application of methods to invert for a depth-dependent mud slowness curve. This allowed for much more accurate inversion of the VTI parameter γ than the conventional method that uses a constant mud slowness value. In addition to enabling a more accurate inversion, it is observed that the mud slowness curve not only varied with depth [likely because of pressure/temperature (P/T) changes and possible settling] but also reflected quite different properties across a drilling fluid pill that was placed around the reservoir formations. This analysis provides an additional benefit for drilling engineers because the mud slowness curve tracks mud property changes in the well and can determine the actual location of the drilling fluid pill after placement and stabilization. Additional work estimated the depth-continuous elastic tensor and geomechanics (anisotropic Poisson's ratios and Young's moduli necessary for computing horizontal stresses) for well completion and fracture treatment design. Seismic-scale properties were estimated using anisotropic Backus averaging for the calibration of the anisotropic seismic velocity model for prestack depth migration.
{"title":"Case Study Demonstrating the Estimation of Depth-Continuous Formation Anisotropy with Application to Geomechanics and Seismic Velocity Model Calibration","authors":"B. Hornby, Ruijia Wang, M. Collins, Joonshik Kim, R. Confer","doi":"10.2118/194867-MS","DOIUrl":"https://doi.org/10.2118/194867-MS","url":null,"abstract":"\u0000 This paper presents a case study in which new methods that use full-waveform sonic data are applied in an unconventional well setting to determine depth-dependent elastic anisotropy of formations penetrated by the well and estimate parameters of interest. The study objectives include the following: Estimate Thomsen's shear anisotropy parameter γ in an unconventional well that penetrates fast formationsUse rock physics and other approximations to further estimate a complete vertical transverse isotropic (VTI) elastic tensor at each depthCompare results with ground truth in terms of dynamic and static core measurementsUse these results to derive anisotropic geomechanical parameters for well completion and fracture treatment design and to compute upscaled seismic-equivalent elastic anisotropy for the calibration of anisotropic seismic velocity models\u0000 Formation speeds in this well were extremely fast, typical for unconventional shale reservoirs, which created a challenging environment for estimating VTI Thomsen's parameter γ because of the extreme sensitivity of the inversion to the accuracy of the borehole fluid slowness estimate. The key to the study's success was development and application of methods to invert for a depth-dependent mud slowness curve. This allowed for much more accurate inversion of the VTI parameter γ than the conventional method that uses a constant mud slowness value. In addition to enabling a more accurate inversion, it is observed that the mud slowness curve not only varied with depth [likely because of pressure/temperature (P/T) changes and possible settling] but also reflected quite different properties across a drilling fluid pill that was placed around the reservoir formations. This analysis provides an additional benefit for drilling engineers because the mud slowness curve tracks mud property changes in the well and can determine the actual location of the drilling fluid pill after placement and stabilization.\u0000 Additional work estimated the depth-continuous elastic tensor and geomechanics (anisotropic Poisson's ratios and Young's moduli necessary for computing horizontal stresses) for well completion and fracture treatment design. Seismic-scale properties were estimated using anisotropic Backus averaging for the calibration of the anisotropic seismic velocity model for prestack depth migration.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74752777","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}
Approximately 20% of all oilwells in the world use a beam pump to raise crude oil to the surface. The proper maintenance of these pumps is thus an important issue in oilfield operations. We wish to know, preferably before the failure, what is wrong with the pump. Maintenance issues on the downhole part of a beam pump can be reliably diagnosed from a plot of the displacement and load on the traveling valve; a diagram known as a dynamometer card. We demonstrate in this paper that this analysis can be fully automated using machine learning techniques that teach themselves to recognize various classes of damage in advance of the failure. We use a dataset of of 35292 sample cards drawn from 299 beam pumps in the Bahrain oilfield. We can detect 11 different damage classes from each other and from the normal class with an accuracy of 99.9%. This high accuracy makes it possible to automatically diagnose beam pumps in real-time and for the maintenance crew to focus on fixing pumps instead of monitoring them, which increases overall oil yield and decreases environmental impact.
{"title":"Diagnosing and Predicting Problems with Rod Pumps using Machine Learning","authors":"P. Bangert","doi":"10.2118/194993-MS","DOIUrl":"https://doi.org/10.2118/194993-MS","url":null,"abstract":"\u0000 Approximately 20% of all oilwells in the world use a beam pump to raise crude oil to the surface. The proper maintenance of these pumps is thus an important issue in oilfield operations. We wish to know, preferably before the failure, what is wrong with the pump. Maintenance issues on the downhole part of a beam pump can be reliably diagnosed from a plot of the displacement and load on the traveling valve; a diagram known as a dynamometer card. We demonstrate in this paper that this analysis can be fully automated using machine learning techniques that teach themselves to recognize various classes of damage in advance of the failure. We use a dataset of of 35292 sample cards drawn from 299 beam pumps in the Bahrain oilfield. We can detect 11 different damage classes from each other and from the normal class with an accuracy of 99.9%. This high accuracy makes it possible to automatically diagnose beam pumps in real-time and for the maintenance crew to focus on fixing pumps instead of monitoring them, which increases overall oil yield and decreases environmental impact.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75311434","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}
Aliya Azlan, W.M.S. B Wan Muda, A. Mubaraki, Khairul Ezee Azreen M. Khir, Norhayati M Sahid, Amran B M Zakei
This paper presents the result of synergizing advanced well test deconvolution, rate transient analysis and detailed reservoir modeling to answer the compartmentalization uncertainty demonstrated by downhole pressure data in K field located offshore Sarawak, Malaysia. The gas reservoir is well distributed within approximately 10 × 20 km area and divided into two fault blocks, east and west. The development only focused at eastern area. Based on earlier assessment during Field Development Plan (FDP) stage, no fault has been seen from seismic data interpretation within east area. However, the six years actual performance of the field address different understanding which suggesting possible compartmentalization. Several assumptions were made to reconcile the connected hydrocarbon initially in–place estimated from conventional material balance and static volumetric calculation, however it has led to inconclusive results. The paper draws on the strength of an integrated reservoir engineering studies that include analytical and numerical analysis. The general framework covers advanced well test deconvolution analysis which multiple Pressure Build Ups (PBUs) and flowing duration were interpreted. This helps in guiding reservoir characterization understanding further from the well and type of fault setting within the reservoir. In addition, Rate Transient Analysis (RTA) has been conducted to estimate the connected volume. Several interesting findings will be shared in this paper as well. The combination of these deconvolution and RTA works enhanced the understanding of reservoir compartmentalization which guided the history matching process done through dynamic model. The newly established workflow has reduced the efforts required in history matching process and gave clearer picture of the uncertainty of reservoir compartmentalization.
{"title":"New Approach of Synergizing Advanced Well Test Deconvolution, Rate Transient Analysis and Dynamic Modeling in Evaluating Reservoir Compartmentalization Uncertainty at K Field in Sarawak Basin; A Case Study","authors":"Aliya Azlan, W.M.S. B Wan Muda, A. Mubaraki, Khairul Ezee Azreen M. Khir, Norhayati M Sahid, Amran B M Zakei","doi":"10.2118/195038-MS","DOIUrl":"https://doi.org/10.2118/195038-MS","url":null,"abstract":"\u0000 This paper presents the result of synergizing advanced well test deconvolution, rate transient analysis and detailed reservoir modeling to answer the compartmentalization uncertainty demonstrated by downhole pressure data in K field located offshore Sarawak, Malaysia. The gas reservoir is well distributed within approximately 10 × 20 km area and divided into two fault blocks, east and west. The development only focused at eastern area. Based on earlier assessment during Field Development Plan (FDP) stage, no fault has been seen from seismic data interpretation within east area. However, the six years actual performance of the field address different understanding which suggesting possible compartmentalization. Several assumptions were made to reconcile the connected hydrocarbon initially in–place estimated from conventional material balance and static volumetric calculation, however it has led to inconclusive results. The paper draws on the strength of an integrated reservoir engineering studies that include analytical and numerical analysis. The general framework covers advanced well test deconvolution analysis which multiple Pressure Build Ups (PBUs) and flowing duration were interpreted. This helps in guiding reservoir characterization understanding further from the well and type of fault setting within the reservoir. In addition, Rate Transient Analysis (RTA) has been conducted to estimate the connected volume. Several interesting findings will be shared in this paper as well.\u0000 The combination of these deconvolution and RTA works enhanced the understanding of reservoir compartmentalization which guided the history matching process done through dynamic model. The newly established workflow has reduced the efforts required in history matching process and gave clearer picture of the uncertainty of reservoir compartmentalization.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74010896","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. F. Zaidin, B. Kantaatmadja, A. Chapoy, P. Ahmadi, R. Burgass
The X field is one of PETRONAS's Research & Development (R&D) initiative plans involving separation of high CO2-Hydrocarbon gas and CO2 storage in offshore Malaysia. The X field is a high pressure high temperature (HPHT) carbonate reservoir with a temperature of 423 K and pressure of 36.0 MPa with about 500 m of gas column. It was chosen as a candidate due to its well and reservoir data completeness. The plan is technically challenging as it involves re-injecting produced supercritical CO2 back into an aquifer reservoir for permanent storage. Recently acquired X field DST data indicates the presence of CO2 in the aquifer, up to a level nearing saturation. Information of the initial CO2 concentration level in the aquifer reservoir is critical to ensure the success of the CO2 injection. Predictions on this initial CO2 solubility have been made using available well data, however the reliability of the results has to be validated by an experimental study. Therefore, an extensive experimental approach to measure initial CO2 solubility in the X field aquifer reservoir has been conducted. As pressure, temperature and salinity are the important key parameters that influence CO2 solubility, detailed information about X field gas and aquifer brine compositions are well determined prior to the solubility measurement. Utilizing lab facilities at Heriot-Watt University (HWU), measurements were conducted at T=423.15 K and pressure at 36.0 MPa to mimic the X field aquifer conditions. The experimental results obtained are compared against available literature data, Duan Model and sCPA-EoS model and reasonable agreements were observed. Experimental results indicated that the X field aquifer is not fully saturated with CO2 and it could accommodate an additional 6 mol% of CO2 dissolved in the brine. In addition, approximately 6 mol% of hydrocarbon will be recovered from the same aquifer system as a result of CO2 injection due to the CO2-Hydrocarbon displacement. This paper details lab measurements of initial CO2 solubility in the X field aquifer, including preparation, experimental procedure, results and discussion as well as suggested future works. Reservoir simulation incorporating the experimental data obtained from this study is necessary and recommended, for getting a full picture of the CO2 injection program for the current Carbon Capture Utilization & Storage (CCUS) project.
{"title":"Experimental Study to Estimate CO2 Solubility in a High Pressure High Temperature HPHT Reservoir Carbonate Aquifer","authors":"M. F. Zaidin, B. Kantaatmadja, A. Chapoy, P. Ahmadi, R. Burgass","doi":"10.2118/195003-MS","DOIUrl":"https://doi.org/10.2118/195003-MS","url":null,"abstract":"\u0000 The X field is one of PETRONAS's Research & Development (R&D) initiative plans involving separation of high CO2-Hydrocarbon gas and CO2 storage in offshore Malaysia. The X field is a high pressure high temperature (HPHT) carbonate reservoir with a temperature of 423 K and pressure of 36.0 MPa with about 500 m of gas column. It was chosen as a candidate due to its well and reservoir data completeness. The plan is technically challenging as it involves re-injecting produced supercritical CO2 back into an aquifer reservoir for permanent storage. Recently acquired X field DST data indicates the presence of CO2 in the aquifer, up to a level nearing saturation. Information of the initial CO2 concentration level in the aquifer reservoir is critical to ensure the success of the CO2 injection. Predictions on this initial CO2 solubility have been made using available well data, however the reliability of the results has to be validated by an experimental study. Therefore, an extensive experimental approach to measure initial CO2 solubility in the X field aquifer reservoir has been conducted. As pressure, temperature and salinity are the important key parameters that influence CO2 solubility, detailed information about X field gas and aquifer brine compositions are well determined prior to the solubility measurement. Utilizing lab facilities at Heriot-Watt University (HWU), measurements were conducted at T=423.15 K and pressure at 36.0 MPa to mimic the X field aquifer conditions. The experimental results obtained are compared against available literature data, Duan Model and sCPA-EoS model and reasonable agreements were observed. Experimental results indicated that the X field aquifer is not fully saturated with CO2 and it could accommodate an additional 6 mol% of CO2 dissolved in the brine. In addition, approximately 6 mol% of hydrocarbon will be recovered from the same aquifer system as a result of CO2 injection due to the CO2-Hydrocarbon displacement. This paper details lab measurements of initial CO2 solubility in the X field aquifer, including preparation, experimental procedure, results and discussion as well as suggested future works. Reservoir simulation incorporating the experimental data obtained from this study is necessary and recommended, for getting a full picture of the CO2 injection program for the current Carbon Capture Utilization & Storage (CCUS) project.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73218522","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}
Zhilin Cheng, Z. Ning, Qing Wang, Mingqi Li, W. Sui
As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.
{"title":"Experimental Investigation of Boundary Conditions Effects on Spontaneous Imbibition in Oil-Water and Gas-Water Systems for Tight Sandstones","authors":"Zhilin Cheng, Z. Ning, Qing Wang, Mingqi Li, W. Sui","doi":"10.2118/194858-MS","DOIUrl":"https://doi.org/10.2118/194858-MS","url":null,"abstract":"\u0000 As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83745592","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 work is to present the development of a numerical model for wave propagation in materials with time-varying, heterogeneous, and non-linear properties. Materials change with time as the result of complex linear and non-linear processes, which can occur due to natural causes or induced. Wave phenomena in this context brings about an interesting and complex problem, which involves the solution to coupled equations which describe interlinked multiphysics phenomena. Thus, understanding the dynamics of this interaction is beneficial to numerous applications across different industries and applied research; e.g. acoustic characterization of moving fluids, laser-fluid interaction, distributed optical fiber sensing, photonic integrated systems, among others. Numerical models, therefore, are indispensable to gain a deeper insight about the physical dynamics of the process and, ultimately, purvey a platform to design and test new applications and technologies. Over time some numerical models have been proposed to simulate wave phenomena in these situations. The method and solution reviewed in this work provides a unique solution to develop and optimize multiple applications. For example, it can be used to model the interaction of electromagnetic waves with travelling Bragg mirrors produced by temperature or pressure changes in optical fibers, which is the basis of fiber-based distributed fiber sensing; the scattering of acoustic waves by transient disturbances in fluid flow that may arise from gas bubbles or variations in the density of fluids; and the propagation of an electromagnetic pulse in a rapidly moving and varying fluid. The mathematical description of the process was derived originally for electromagnetics; yet, the numerical solver and mathematical treatment is generic and can be applied to other wave phenomena. The derivation departs from physical principles to write a generalized set of equations that describe wave propagation in time-varying, heterogeneous, and non-linear materials. The resulting set of hyperbolic partial differential equations (PDE) includes diffusive and convective terms that fully describe the wave interaction and process. Linear and nonlinear spatial and time heterogeneities in the material are assimilated into the convective terms of the hyperbolic wave equation. The solver was implemented using a semi-discrete and multidimensional scheme based in the finite-volume method which is highly scalable. Extension to other wave phenomena is discussed by analyzing the parameter correspondence for the acoustic and electromagnetic case.
{"title":"The Role of Transient Perturbations and Heterogeneities in Subsurface Wave Propagation - A Scalable Numerical Solution","authors":"D. San-Roman-Alerigi","doi":"10.2118/194888-MS","DOIUrl":"https://doi.org/10.2118/194888-MS","url":null,"abstract":"\u0000 The objective of this work is to present the development of a numerical model for wave propagation in materials with time-varying, heterogeneous, and non-linear properties. Materials change with time as the result of complex linear and non-linear processes, which can occur due to natural causes or induced. Wave phenomena in this context brings about an interesting and complex problem, which involves the solution to coupled equations which describe interlinked multiphysics phenomena. Thus, understanding the dynamics of this interaction is beneficial to numerous applications across different industries and applied research; e.g. acoustic characterization of moving fluids, laser-fluid interaction, distributed optical fiber sensing, photonic integrated systems, among others. Numerical models, therefore, are indispensable to gain a deeper insight about the physical dynamics of the process and, ultimately, purvey a platform to design and test new applications and technologies.\u0000 Over time some numerical models have been proposed to simulate wave phenomena in these situations. The method and solution reviewed in this work provides a unique solution to develop and optimize multiple applications. For example, it can be used to model the interaction of electromagnetic waves with travelling Bragg mirrors produced by temperature or pressure changes in optical fibers, which is the basis of fiber-based distributed fiber sensing; the scattering of acoustic waves by transient disturbances in fluid flow that may arise from gas bubbles or variations in the density of fluids; and the propagation of an electromagnetic pulse in a rapidly moving and varying fluid.\u0000 The mathematical description of the process was derived originally for electromagnetics; yet, the numerical solver and mathematical treatment is generic and can be applied to other wave phenomena. The derivation departs from physical principles to write a generalized set of equations that describe wave propagation in time-varying, heterogeneous, and non-linear materials. The resulting set of hyperbolic partial differential equations (PDE) includes diffusive and convective terms that fully describe the wave interaction and process. Linear and nonlinear spatial and time heterogeneities in the material are assimilated into the convective terms of the hyperbolic wave equation. The solver was implemented using a semi-discrete and multidimensional scheme based in the finite-volume method which is highly scalable. Extension to other wave phenomena is discussed by analyzing the parameter correspondence for the acoustic and electromagnetic case.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"509 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85245655","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}
One of the primary functions of Saudi Aramco Gas-Oil Separation Plants (also known as GOSPs) is to separate emulsified water from the crude. The water is typically highly concentrated with salt, so crude desalting is required to meet the standard quality specifications. GOSPs are typically designed with standard Proportional-Integral-Derivative (PID) controllers to control demulsifier and wash water flow for injection into wet crude. Demulsifier and wash water injection rates are normally left to operator judgement. The challenge with manual adjustment of flowrate is the high risk of overdosing or underdosing as there are several variables that impact the required demulsifier and wash water rates. Overdosing will result in wastage of demulsifier and wash water and higher operating expenditures. Underdosing may lead to operational upsets and potentially off-spec crude production. To overcome this challenge, innovative schemes (Smart Demulsifier Control & Wash Water Ratio Control) have been developed in-house. Smart Demulsifier Control optimizes the separation efficiency (or percentage of total produced water separated) of an upstream High Pressure Production Trap (HPPT or 3-Phase Separator) based on a dynamic target by adjusting the demulsifier injection rate and concentration in the wet crude. Simultaneously, wash water ratio control ensures that an adequate wash water rate is injected to satisfy salt-in-crude specifications. These control schemes eliminate the need for operators to determine the required dosage rate, thereby avoiding both overdosing and underdosing of demulsifier and wash water. The Smart Demulsifier Control (SDC) scheme controls demulsifier injection using two control layers. The first layer controls the Concentration of the Demulsifier in the Wet Crude so that demulsifier flow is automatically adjusted based on the Production Rate to achieve the set point concentration determined by the second layer of control. The second layer adjusts the demulsifier concentration to control the Separation Efficiency of the HPPT, or the amount of water separated in the HPPT vs. the Dehydrator, to achieve the Target Separation Efficiency Set Point determined by a site specific process model. In case of a dehydrator upset, another PID controller with more aggressive tuning will override the HPPT Separation PID Controller to set the required demulsifier concentration to mitigate the upset. Wash water ratio control scheme controls the flow of wash water to ensure that the salt-in-crude specification is met. A site specific target ratio is determined through a salt mass balance. These innovative controls have reduced desalting train upsets by 78% as the process related upsets are practically eliminated. This is achieved while optimizing the demulsifier dosage where 20-40% of demulsifier dosage reduction was realized, especially during the winter season. Moreover, savings of 20% wash water have been achieved throughout the utilization of thes
{"title":"Crude Oil Process Enhancement and Water Conservation Through Industrial Revolution Initiatives","authors":"Nasser A. Alhajri, R. White, M. A. Andreu","doi":"10.2118/195044-MS","DOIUrl":"https://doi.org/10.2118/195044-MS","url":null,"abstract":"\u0000 One of the primary functions of Saudi Aramco Gas-Oil Separation Plants (also known as GOSPs) is to separate emulsified water from the crude. The water is typically highly concentrated with salt, so crude desalting is required to meet the standard quality specifications. GOSPs are typically designed with standard Proportional-Integral-Derivative (PID) controllers to control demulsifier and wash water flow for injection into wet crude. Demulsifier and wash water injection rates are normally left to operator judgement. The challenge with manual adjustment of flowrate is the high risk of overdosing or underdosing as there are several variables that impact the required demulsifier and wash water rates. Overdosing will result in wastage of demulsifier and wash water and higher operating expenditures. Underdosing may lead to operational upsets and potentially off-spec crude production.\u0000 To overcome this challenge, innovative schemes (Smart Demulsifier Control & Wash Water Ratio Control) have been developed in-house. Smart Demulsifier Control optimizes the separation efficiency (or percentage of total produced water separated) of an upstream High Pressure Production Trap (HPPT or 3-Phase Separator) based on a dynamic target by adjusting the demulsifier injection rate and concentration in the wet crude. Simultaneously, wash water ratio control ensures that an adequate wash water rate is injected to satisfy salt-in-crude specifications. These control schemes eliminate the need for operators to determine the required dosage rate, thereby avoiding both overdosing and underdosing of demulsifier and wash water.\u0000 The Smart Demulsifier Control (SDC) scheme controls demulsifier injection using two control layers. The first layer controls the Concentration of the Demulsifier in the Wet Crude so that demulsifier flow is automatically adjusted based on the Production Rate to achieve the set point concentration determined by the second layer of control. The second layer adjusts the demulsifier concentration to control the Separation Efficiency of the HPPT, or the amount of water separated in the HPPT vs. the Dehydrator, to achieve the Target Separation Efficiency Set Point determined by a site specific process model. In case of a dehydrator upset, another PID controller with more aggressive tuning will override the HPPT Separation PID Controller to set the required demulsifier concentration to mitigate the upset.\u0000 Wash water ratio control scheme controls the flow of wash water to ensure that the salt-in-crude specification is met. A site specific target ratio is determined through a salt mass balance.\u0000 These innovative controls have reduced desalting train upsets by 78% as the process related upsets are practically eliminated. This is achieved while optimizing the demulsifier dosage where 20-40% of demulsifier dosage reduction was realized, especially during the winter season. Moreover, savings of 20% wash water have been achieved throughout the utilization of thes","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"496 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77053581","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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