Polymer-surfactant mixtures in aqueous solutions present unique rheological and interfacial properties that promote their applications in chemical flooding. The objective of this study is to investigate the interaction between anionic polyacrylamides and cationic surfactants in different temperature and salinity conditions and the potential application of the polymer-surfactant mixtures in carbonate reservoirs. Cationic surfactants were selected owing to low adsorption on carbonate rocks. Compatibility tests of polymer-surfactant mixtures were conducted in brine with different salinities to study the interaction between anionic polymers and cationic surfactants in the presence of salts. The effect of cationic surfactants on polymer viscosity at different temperatures was investigated. The compatibility of the mixtures of the cationic surfactants and the anionic polymers was significantly improved in high salinity injection water (with a total dissolved solid of 57,670 mg/L), compared with the compatibility in deionized water. This is attributed to the shielding of polymer and surfactant charges by the salts, which diminishes the electrostatic interaction between the chemicals. Rheological measurements indicated that the polymer viscosity increased in the presence of the cationic surfactant CAS-S or CAS-B. This effect was decreased at 90˚C. Other cationic surfactant CAS-1 or CAS-3 slightly increased the polymer viscosity at 25˚C and significantly decreased the viscosity at 90˚C. These observations can be explained based on the surfactants self-assembly. At room temperature, CAS-1 and CAS-3 form spherical micelles while CAS-S and CAS-B form wormlike micelles. The entanglement of the polymers with wormlike micelles explains the observed viscosity enhancement. At 90˚C, wormlike micelles became shorter which weakens this viscosity enhancement effect. In conclusion, the charges and self-assembly structures of surfactants play an important role in the performance of polymer-surfactant mixtures that should be taken into account in the design of optimal formulations. This work provides the insight of interaction between anionic polymers and cationic surfactants with different self-assembly structures for the potential application in improving oil production.
{"title":"Study on Oppositely Charged Polymer and Surfactant Mixture for Enhancing Oil Production","authors":"Limin Xu, M. Han, Xuan Zhang, A. Fuseni","doi":"10.2118/198094-ms","DOIUrl":"https://doi.org/10.2118/198094-ms","url":null,"abstract":"\u0000 Polymer-surfactant mixtures in aqueous solutions present unique rheological and interfacial properties that promote their applications in chemical flooding. The objective of this study is to investigate the interaction between anionic polyacrylamides and cationic surfactants in different temperature and salinity conditions and the potential application of the polymer-surfactant mixtures in carbonate reservoirs. Cationic surfactants were selected owing to low adsorption on carbonate rocks. Compatibility tests of polymer-surfactant mixtures were conducted in brine with different salinities to study the interaction between anionic polymers and cationic surfactants in the presence of salts. The effect of cationic surfactants on polymer viscosity at different temperatures was investigated.\u0000 The compatibility of the mixtures of the cationic surfactants and the anionic polymers was significantly improved in high salinity injection water (with a total dissolved solid of 57,670 mg/L), compared with the compatibility in deionized water. This is attributed to the shielding of polymer and surfactant charges by the salts, which diminishes the electrostatic interaction between the chemicals. Rheological measurements indicated that the polymer viscosity increased in the presence of the cationic surfactant CAS-S or CAS-B. This effect was decreased at 90˚C. Other cationic surfactant CAS-1 or CAS-3 slightly increased the polymer viscosity at 25˚C and significantly decreased the viscosity at 90˚C. These observations can be explained based on the surfactants self-assembly. At room temperature, CAS-1 and CAS-3 form spherical micelles while CAS-S and CAS-B form wormlike micelles. The entanglement of the polymers with wormlike micelles explains the observed viscosity enhancement. At 90˚C, wormlike micelles became shorter which weakens this viscosity enhancement effect. In conclusion, the charges and self-assembly structures of surfactants play an important role in the performance of polymer-surfactant mixtures that should be taken into account in the design of optimal formulations. This work provides the insight of interaction between anionic polymers and cationic surfactants with different self-assembly structures for the potential application in improving oil production.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116627075","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}
Formation damage resulting from organic and inorganic depositions, such as calcium carbonate, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production completions, such as from electric submersible pumps (ESPs), and less footage coverage while running with production and flow profile logging tools. The major concern highlighted is the increased probability of having more organic deposits in the wellbore as a result of the increased scale of the inorganic deposits. A thick, heterogeneous sludge mix of hydrocarbons and solid materials is a critical subject for characterization and solubility measurements. Analyzed deposit samples were collected either while running with production logging tools, when pulling out a failed ESP, or when lowering the completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. The solid phase analyses included X-ray diffraction (XRD) analysis and scanning/transmission electron microscopy (SEM and TEM). The composition of organic deposit samples was investigated using saturates, aromatics, resins, and asphaltenes (SARA) characterization, Fourier transform infrared analysis (FTIR) and Fourier transform ion cyclotron resonance mass spectrometry (FTMS). The sludge sample solubility tests were conducted over a variety of organic solvents at different temperatures, up to 300°F with a solid mass/liquid volume ratio of 1:10. The paper presents a typical analysis procedure of organic deposits collected from downhole equipment. The XRD analysis of solid debris materials (inorganic) present in collected sticky materials samples showed that the materials contained mainly carbonate compounds; for instance, calcite-CaCO3, dolomite-CaMg(CO3)2, and Halite-NaCl. These materials were completely soluble in acids like 15 wt% of HCl at reservoir conditions. Calcite scale would have been a problem in cases where the calcium content exceeded 12,000 mg/L. Low solubility results were obtained with static reaction of organic solvents recipes with the sticky materials around 17 to 50 wt%. This, in turn, increased solubility up to 98% as observed from the reaction in dynamic conditions.
{"title":"Heavy Organic Deposit Formation Damage Control, Analysis and Remediation Techniques","authors":"Abdulaziz Alqasim, Mutaz Alsubhi, Amer Al-Anazi","doi":"10.2118/198170-ms","DOIUrl":"https://doi.org/10.2118/198170-ms","url":null,"abstract":"\u0000 Formation damage resulting from organic and inorganic depositions, such as calcium carbonate, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production completions, such as from electric submersible pumps (ESPs), and less footage coverage while running with production and flow profile logging tools. The major concern highlighted is the increased probability of having more organic deposits in the wellbore as a result of the increased scale of the inorganic deposits.\u0000 A thick, heterogeneous sludge mix of hydrocarbons and solid materials is a critical subject for characterization and solubility measurements. Analyzed deposit samples were collected either while running with production logging tools, when pulling out a failed ESP, or when lowering the completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. The solid phase analyses included X-ray diffraction (XRD) analysis and scanning/transmission electron microscopy (SEM and TEM). The composition of organic deposit samples was investigated using saturates, aromatics, resins, and asphaltenes (SARA) characterization, Fourier transform infrared analysis (FTIR) and Fourier transform ion cyclotron resonance mass spectrometry (FTMS). The sludge sample solubility tests were conducted over a variety of organic solvents at different temperatures, up to 300°F with a solid mass/liquid volume ratio of 1:10.\u0000 The paper presents a typical analysis procedure of organic deposits collected from downhole equipment. The XRD analysis of solid debris materials (inorganic) present in collected sticky materials samples showed that the materials contained mainly carbonate compounds; for instance, calcite-CaCO3, dolomite-CaMg(CO3)2, and Halite-NaCl. These materials were completely soluble in acids like 15 wt% of HCl at reservoir conditions. Calcite scale would have been a problem in cases where the calcium content exceeded 12,000 mg/L. Low solubility results were obtained with static reaction of organic solvents recipes with the sticky materials around 17 to 50 wt%. This, in turn, increased solubility up to 98% as observed from the reaction in dynamic conditions.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132762813","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}
Reduction of LNG prices has thrown up a very serious challenge for the Refining Industry as it is rapidly replacing the demand of the Fuel Oil. Refiners need to find a way for a suitable upgrade of the Residual Fuel Oil from the Crude Distillation Units (CDU). One of the most economical and attractive ways to do this is to process the surplus Fuel Oil in the Resid Fluidized Catalytic Cracking (RFCC). These days, higher amount of surplus Fuel Oil is resulting in Higher capacity RFCCs. However, does it come without any challenges? Certainly No. As we all know that the current market scenarios discourage production of Gasoline while emphasizing on maximizing Poly Propylene and Para Xylene. However conventional RFCCs are considered for producing Gasoline. So, we are left with a challenging question. How to minimize Gasoline from RFCC while increasing its capacity? It is rarely possible to reduce Gasoline production while increasing RFCC capacity. Sounds Impossible but this is made possible by an innovative Process Unit Reconfiguration in KIPIC. This article will highlight the various challenges associated with the increased RFCC capacity. This will discuss in detail how the optimum configuration is achieved for minimizing the Gasoline production and maximizing the feed stocks to downstream Poly Propylene and Aromatics complex to produce the valuable Polypropylene and Para Xylene. The paper will conclude that by an innovative Process Unit Configuration, the overall Gasoline quantity can be reduced by 15% even by almost doubling the RFCC capacity. It will also elaborate how the optimum configuration helps in reducing the overall CAPEX / OPEX of the units, increases the overall reliability, eliminates the dependence on the imported feed stocks and helps in value maximization of the intermediate streams. The paper will be of interest to anyone who is involved in carrying out the Configuration study for the secondary processing units of the Refinery and looking for optimum solution to the surplus Fuel Oil. It will provide an insight to the latest options available for upgrading the fuel oil to various products meeting the current market demands with minimum CAPEX and OPEX. The paper also focusses on how RFCC overall Reliability is increased and how yields of high value products is maximized from the unit.
{"title":"Overcoming Challenges Resulting from Surplus Fuel Oil","authors":"Mohammad Falah Al-Azmi, Gunjan Ojha","doi":"10.2118/198064-ms","DOIUrl":"https://doi.org/10.2118/198064-ms","url":null,"abstract":"\u0000 Reduction of LNG prices has thrown up a very serious challenge for the Refining Industry as it is rapidly replacing the demand of the Fuel Oil. Refiners need to find a way for a suitable upgrade of the Residual Fuel Oil from the Crude Distillation Units (CDU). One of the most economical and attractive ways to do this is to process the surplus Fuel Oil in the Resid Fluidized Catalytic Cracking (RFCC). These days, higher amount of surplus Fuel Oil is resulting in Higher capacity RFCCs. However, does it come without any challenges? Certainly No. As we all know that the current market scenarios discourage production of Gasoline while emphasizing on maximizing Poly Propylene and Para Xylene. However conventional RFCCs are considered for producing Gasoline. So, we are left with a challenging question. How to minimize Gasoline from RFCC while increasing its capacity? It is rarely possible to reduce Gasoline production while increasing RFCC capacity. Sounds Impossible but this is made possible by an innovative Process Unit Reconfiguration in KIPIC. This article will highlight the various challenges associated with the increased RFCC capacity. This will discuss in detail how the optimum configuration is achieved for minimizing the Gasoline production and maximizing the feed stocks to downstream Poly Propylene and Aromatics complex to produce the valuable Polypropylene and Para Xylene. The paper will conclude that by an innovative Process Unit Configuration, the overall Gasoline quantity can be reduced by 15% even by almost doubling the RFCC capacity. It will also elaborate how the optimum configuration helps in reducing the overall CAPEX / OPEX of the units, increases the overall reliability, eliminates the dependence on the imported feed stocks and helps in value maximization of the intermediate streams. The paper will be of interest to anyone who is involved in carrying out the Configuration study for the secondary processing units of the Refinery and looking for optimum solution to the surplus Fuel Oil. It will provide an insight to the latest options available for upgrading the fuel oil to various products meeting the current market demands with minimum CAPEX and OPEX. The paper also focusses on how RFCC overall Reliability is increased and how yields of high value products is maximized from the unit.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132088780","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}
Jiabo Liang, Li‐Qin Jin, Wenyong Li, Qiang Li, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, H. Saadawi, C. Harper, Jon Tuck, Yongjun Fang
CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields’ water injection system.
{"title":"Material Selection for Water Injection System for a Giant Oil Field, Iraq","authors":"Jiabo Liang, Li‐Qin Jin, Wenyong Li, Qiang Li, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, H. Saadawi, C. Harper, Jon Tuck, Yongjun Fang","doi":"10.2118/197983-ms","DOIUrl":"https://doi.org/10.2118/197983-ms","url":null,"abstract":"\u0000 CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad.\u0000 In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells.\u0000 This paper describes the approach adopted in selecting the materials for Missan fields’ water injection system.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116738713","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. Freeman, Pabitra Saikia, Philip O. Benham, M. Cheers, Zhiyi Ian Zhang, P. Choudhary, Khalid Ahmad, Ren Zu Biao, Khalid Al-Dohaiem, Hamad Al-Haqqan, Saad Al-Rashdan, G. Warrlich, A. Al-Rabah
This paper presents a method for facies classification derived from cross plots of basic gamma ray and bulk density wireline log data. It has been specifically developed in-house for two North Kuwait heavy-oil fields, and has been calibrated against both field analogues and core sample measurements. This new facies classification scheme has proven to be quick and cost effective, with multiple practical applications for future field development and operation optimization. For two heavy oil fields in North Kuwait basic Gamma Ray and Bulk Density (GR-DENS) curve data from over 1300 wells were cross-plotted. The resulting relationship characteristics were used to delineate eight separate facies, which plot along a continuum from clean porous sands with little cement and clay, to less porous sands with increasing clay and cementation content, to carbonate and shale. The properties for these facies were calibrated against data from core analyses and with outcrop analogues in North Kuwait. These facies were populated into static reservoir models using the Sequential Indicator Simulation (SIS) method, and petrophysical modeling was then conditioned to these facies. These resulting modeled facies, with their associated petrophysical properties, have been used in a wide variety of subsequent analytical studies. The eight facies which have been newly delineated by the GR-DENS classification scheme capture the transitional nature of petrophysical properties for oil saturation, porosity and permeability. This has enabled several improvements for heavy-oil field development including: 1) better delineation of reservoir and baffle zones; 2) better calibration of oil saturation with core data; 3) calibration of facies with 3D seismic amplitude response; 4) better understanding of reservoir geomechanics and seal integrity assessment; 5) greater confidence in the results of static and dynamic reservoir modeling; 6) more effective decision making in the WRFM process; and 7) alignment of the petrophysical and facies characterization approach between two separate heavy oil asset teams, which allows for direct comparisons between their data sets. Although more complex software exists for specialized facies classification, the GR-DENS workflow newly developed for North Kuwait heavy oil has proven to be simple, rapid, accurate and cost effective. In summary a robust facies classification scheme was developed in-house which is appropriately customized for two North Kuwait heavy oil fields. This methodology has enabled the creation of more representative reservoir models, with resulting improvements in understanding for multiple aspects of both fields. These improvements in turn will lead to better production forecasting and optimization as well as enhance future life of field planning.
{"title":"A New Facies Classification Scheme Using Gamma Ray and Bulk Density Logs, With Multiple Practical Applications in North Kuwait Heavy Oil Fields","authors":"M. Freeman, Pabitra Saikia, Philip O. Benham, M. Cheers, Zhiyi Ian Zhang, P. Choudhary, Khalid Ahmad, Ren Zu Biao, Khalid Al-Dohaiem, Hamad Al-Haqqan, Saad Al-Rashdan, G. Warrlich, A. Al-Rabah","doi":"10.2118/198084-ms","DOIUrl":"https://doi.org/10.2118/198084-ms","url":null,"abstract":"\u0000 This paper presents a method for facies classification derived from cross plots of basic gamma ray and bulk density wireline log data. It has been specifically developed in-house for two North Kuwait heavy-oil fields, and has been calibrated against both field analogues and core sample measurements. This new facies classification scheme has proven to be quick and cost effective, with multiple practical applications for future field development and operation optimization.\u0000 For two heavy oil fields in North Kuwait basic Gamma Ray and Bulk Density (GR-DENS) curve data from over 1300 wells were cross-plotted. The resulting relationship characteristics were used to delineate eight separate facies, which plot along a continuum from clean porous sands with little cement and clay, to less porous sands with increasing clay and cementation content, to carbonate and shale. The properties for these facies were calibrated against data from core analyses and with outcrop analogues in North Kuwait. These facies were populated into static reservoir models using the Sequential Indicator Simulation (SIS) method, and petrophysical modeling was then conditioned to these facies. These resulting modeled facies, with their associated petrophysical properties, have been used in a wide variety of subsequent analytical studies.\u0000 The eight facies which have been newly delineated by the GR-DENS classification scheme capture the transitional nature of petrophysical properties for oil saturation, porosity and permeability. This has enabled several improvements for heavy-oil field development including: 1) better delineation of reservoir and baffle zones; 2) better calibration of oil saturation with core data; 3) calibration of facies with 3D seismic amplitude response; 4) better understanding of reservoir geomechanics and seal integrity assessment; 5) greater confidence in the results of static and dynamic reservoir modeling; 6) more effective decision making in the WRFM process; and 7) alignment of the petrophysical and facies characterization approach between two separate heavy oil asset teams, which allows for direct comparisons between their data sets. Although more complex software exists for specialized facies classification, the GR-DENS workflow newly developed for North Kuwait heavy oil has proven to be simple, rapid, accurate and cost effective.\u0000 In summary a robust facies classification scheme was developed in-house which is appropriately customized for two North Kuwait heavy oil fields. This methodology has enabled the creation of more representative reservoir models, with resulting improvements in understanding for multiple aspects of both fields. These improvements in turn will lead to better production forecasting and optimization as well as enhance future life of field planning.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127454000","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}
Mohammed T. Al Murayri, A. Hassan, A. Rahim, B. Decroux, A. Negre, M. Salaun
This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait. A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results. The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding.Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer).Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding. Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.
本文讨论了科威特北部Raudhatain Lower Burgan (RALB)油藏单井化学示踪剂测试(SWCTT)的设计和实施，以评估实验室优化的表面活性剂-聚合物配方的效果。SWCTT是在完成先前出版物(al - murayri et al. 2017和al - murayri et al. 2018)中讨论的广泛的实验室和模拟工作后设计的。SWCTT的设计工作旨在确定在岩心洪水规模下，根据最小体积、速率和持续时间确定的最佳注入/生产顺序。主要的不确定性是用许多敏感性情景来评估的。随后，SWCTT在现场实施，并对结果进行了仔细分析，并与之前获得的实验室和模拟结果进行了比较。SWCTT的主要目的是验证聚合物和表面活性剂溶液在降低残余油饱和度和注入能力方面的有效性。这包括比较化学驱前后的残余油饱和度估算值，同时监测注入速率和相应的井口压力。SWCTT注入顺序包括以下步骤:初始水驱，然后注入示踪剂，浸泡和生产，以测量水驱后的含油饱和度。预冲之后是主段塞(加入5000 ppm的表面活性剂和500 ppm的聚合物)和后冲(只加入聚合物)。化学驱后进行海水推注、示踪剂注入、浸泡和生产，测量含油饱和度。在SWCTT测试之前的模拟工作显示，在距井10英尺的范围内，化学驱后的原油去饱和效果令人鼓舞。然而，在分析试点结果后，人们意识到实际SWCTT结果与先前获得的实验室和模拟结果之间存在差距。本文阐述了上述swctt的设计和实现，重点讨论了实际现场数据与实验室/模拟结果之间存在差距的潜在原因。该研究的见解有望帮助进一步优化表面活性剂-聚合物驱，以经济地提高相对成熟油藏的采收率。
{"title":"Surfactant-Polymer Flooding: Single Well Chemical Tracer Test Design and Implementation in a Major Sandstone Kuwaiti Reservoir","authors":"Mohammed T. Al Murayri, A. Hassan, A. Rahim, B. Decroux, A. Negre, M. Salaun","doi":"10.2118/197995-ms","DOIUrl":"https://doi.org/10.2118/197995-ms","url":null,"abstract":"\u0000 This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait.\u0000 A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results.\u0000 The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding.Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer).Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding.\u0000 Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"39 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120905976","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}
Induced hydraulic fractures in the field interact heavily with pre-existing natural fractures in the rock that are abundant in many formations. Most laboratory fracturing investigations in the literature consider pre-existing fractures as frictional interfaces with zero thickness. However, natural fractures in subsurface formations are often sealed with mineral cementing material of finite thickness. In this study, we present a novel experimental demonstration of the behavior of an induced hydraulic fracture as it approaches a cemented natural fracture utilizing a two-dimensional (2-D) hydraulic fracturing cell. Sheet-like test specimens are cast with natural fractures of varied mechanical properties, thickness, and relative position to a fluid injection port. Plaster is used as the specimen matrix. The filling material for hard natural fractures are cast using hydrostone while soft natural fractures are cast using a mixture of plaster and talc. Several tests are performed to characterize the mechanical and flow properties of these materials. A novel method for casting the specimen matrix and filling material of the natural fracture is described and used to enable strong bonding between the natural fracture and specimen matrix. The test specimen is placed between two thick, transparent plates and constant, anisotropic far-field stresses are applied to the specimen. Fracturing fluid is injected in the center of the specimen and the induced fracture trajectories in several experiments are captured with high-resolution digital images. We show a clear tendency for the induced hydraulic fracture to cross thick natural fractures filled with materials softer than the host rock and to be diverted by thick natural fractures with harder filling materials. The induced hydraulic fracture also tends to cross hard natural fractures when the natural fractures are relatively thin. In addition, the induced hydraulic fracture from the injection port is shown to be diverted by a thin, hard natural fracture that is placed relatively close to the injection port but crosses the same natural fracture when placed farther away from the injection port. Using our in-house numerical simulator that is based on the phase field approach, we model these laboratory experiments to gain insights into the observed fracture behaviors. Our results provide clear evidence of the impact of natural fracture filling material, natural fracture width, and the induced hydraulic fracture length on the outcome of hydraulic fracture interaction with natural fractures. The small-scale, 2-D nature, and well-characterized properties of our laboratory specimens are also valuable for validating numerical hydraulic fracturing simulators that are capable of modeling the effect of pre-existing natural fractures on hydraulic fracture propagation.
{"title":"Laboratory Imaging and Phase Field Modeling of the Interaction of Hydraulic Fractures with Well Cemented Natural Fractures","authors":"M. AlTammar, T. E. Alotaibi, M. Sharma, C. Landis","doi":"10.2118/198086-ms","DOIUrl":"https://doi.org/10.2118/198086-ms","url":null,"abstract":"\u0000 Induced hydraulic fractures in the field interact heavily with pre-existing natural fractures in the rock that are abundant in many formations. Most laboratory fracturing investigations in the literature consider pre-existing fractures as frictional interfaces with zero thickness. However, natural fractures in subsurface formations are often sealed with mineral cementing material of finite thickness. In this study, we present a novel experimental demonstration of the behavior of an induced hydraulic fracture as it approaches a cemented natural fracture utilizing a two-dimensional (2-D) hydraulic fracturing cell.\u0000 Sheet-like test specimens are cast with natural fractures of varied mechanical properties, thickness, and relative position to a fluid injection port. Plaster is used as the specimen matrix. The filling material for hard natural fractures are cast using hydrostone while soft natural fractures are cast using a mixture of plaster and talc. Several tests are performed to characterize the mechanical and flow properties of these materials. A novel method for casting the specimen matrix and filling material of the natural fracture is described and used to enable strong bonding between the natural fracture and specimen matrix. The test specimen is placed between two thick, transparent plates and constant, anisotropic far-field stresses are applied to the specimen. Fracturing fluid is injected in the center of the specimen and the induced fracture trajectories in several experiments are captured with high-resolution digital images.\u0000 We show a clear tendency for the induced hydraulic fracture to cross thick natural fractures filled with materials softer than the host rock and to be diverted by thick natural fractures with harder filling materials. The induced hydraulic fracture also tends to cross hard natural fractures when the natural fractures are relatively thin. In addition, the induced hydraulic fracture from the injection port is shown to be diverted by a thin, hard natural fracture that is placed relatively close to the injection port but crosses the same natural fracture when placed farther away from the injection port. Using our in-house numerical simulator that is based on the phase field approach, we model these laboratory experiments to gain insights into the observed fracture behaviors.\u0000 Our results provide clear evidence of the impact of natural fracture filling material, natural fracture width, and the induced hydraulic fracture length on the outcome of hydraulic fracture interaction with natural fractures. The small-scale, 2-D nature, and well-characterized properties of our laboratory specimens are also valuable for validating numerical hydraulic fracturing simulators that are capable of modeling the effect of pre-existing natural fractures on hydraulic fracture propagation.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128376238","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}
R. Alamer, Abdullah Al Ajmi, M. Qahtani, R. Gharbi
This paper investigates the applicability of Low Salinity (LoSal) EOR for a Kuwaiti reservoir. Many reservoirs in the Middle East are not producing satisfied results after depletion methods for a long time of production. Therefore, new management and production strategies must be determined in order to meet the global market demand for oil, which can be done using Enhanced Oil Recovery (EOR) techniques. In Kuwait, one of the EOR methods that could be applied is the use of Low-Salinity (LoSal) Water Flood. Results from previous research have clearly shown that LoSal water injection has a significant impact on oil recovery. Although there are many LoSal experimental results reported in the literature, the process mechanisms and the prediction modeling are yet to be fully investigated and understood. As a result, further experimental work is needed in order to be able to develop reliable prediction tools. The research in this paper is an integrated study combining laboratory work to assess the performance of LoSal water flood using live crude, reservoir brine and native core with wettability conditions restored. The core flooding phase will conduct series of low salinity water flood experiments, design of Salt type and concentration. The performance of LoSal will be compared to different salinities water flood based on reservoir water salinity.
{"title":"Investigation of Low Salinity EOR: Application for Kuwaiti Reservoir","authors":"R. Alamer, Abdullah Al Ajmi, M. Qahtani, R. Gharbi","doi":"10.2118/198113-ms","DOIUrl":"https://doi.org/10.2118/198113-ms","url":null,"abstract":"\u0000 This paper investigates the applicability of Low Salinity (LoSal) EOR for a Kuwaiti reservoir. Many reservoirs in the Middle East are not producing satisfied results after depletion methods for a long time of production. Therefore, new management and production strategies must be determined in order to meet the global market demand for oil, which can be done using Enhanced Oil Recovery (EOR) techniques. In Kuwait, one of the EOR methods that could be applied is the use of Low-Salinity (LoSal) Water Flood.\u0000 Results from previous research have clearly shown that LoSal water injection has a significant impact on oil recovery. Although there are many LoSal experimental results reported in the literature, the process mechanisms and the prediction modeling are yet to be fully investigated and understood. As a result, further experimental work is needed in order to be able to develop reliable prediction tools.\u0000 The research in this paper is an integrated study combining laboratory work to assess the performance of LoSal water flood using live crude, reservoir brine and native core with wettability conditions restored. The core flooding phase will conduct series of low salinity water flood experiments, design of Salt type and concentration. The performance of LoSal will be compared to different salinities water flood based on reservoir water salinity.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"112 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126707324","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}
Maximizing production and sustaining the barrels produced is the aspiration to all oil and gas key players. Current producing reservoirs may not giving good yield till the end of expected production life due to depletion, high water cut and also due to well integrity issues. Finding prolific reservoirs with thick pay zones and excellent rock quality are also becoming scarcer as more complex reservoir characterization comes into play. The challenges are further compounded by high uncertainty in distinguishing hydrocarbon fluid type. Hence, a systematic effort need to be garnered to sustain the production pipeline. This paper will present several case studies and petrophysical solutions in monetizing the untapped low resistivity low contrast reservoirs in a highly complex stratigraphic trap geological setting to squeeze more barrels into production as well as adding value to the reserves portfolio. Identifying the low resistivity and low contrast (LRLC) reservoirs starts with delineating the log responses complemented by other subsurface data such as mud log, cores, fluid samples and advanced acoustic logging to determine lateral sand continuity. Often, well test and production data is used as the benchmark to identify hydrocarbon fluid type in the contradicting evidences. Comparison of nearby wells performance and evaluating fluid contact movement will be also part of the assessment stage. Application of in-house reservoir enhancement modeling (REM) will be the highlight of this paper to reveal those new promising reserves which are masked by thin laminated sand, low salinity, presence of light oil with similar log responses as gas and high silt content. Few examples relating the well production performance with log characteristics will be also discussed in this paper. Results proved that production gain has soared up to 4800 bopd in total to make an astounding impact to the overall field production scenario. In few cases, significant new reserves addition is recorded which further open-up new upside opportunities for work-over, more aggressive production enhancement, appraisal and development drilling campaign. A systematic formation evaluation and petrophysical workflow has also been established to mature and realize the gain which sets a replication standard to the entire region. As more data comes in from the actual jobs done, a database relating the log responses with production capacity and catalogue of past job lessons learned have been initiated for future reference and demonstrating concrete evidences in realizing LRLC potential. In a nutshell, exploiting LRLC potential in complex stratigraphic play requires an intensive subsurface evaluation and offers a promising opportunity in expanding the resource base and generating the cash. The efforts must continue with more success being replicated and bringing in more technology to minimize LRLC uncertainty and create a chain impact to production growth.
{"title":"The Anatomy of Bypassed Low Resistivity Low Contrast Hydrocarbon Reservoirs: The Arts of Finding Additional Barrels in a Highly Complex Stratigraphic Geological Setting","authors":"S. Zulkipli, Norhana Harun","doi":"10.2118/198126-ms","DOIUrl":"https://doi.org/10.2118/198126-ms","url":null,"abstract":"\u0000 Maximizing production and sustaining the barrels produced is the aspiration to all oil and gas key players. Current producing reservoirs may not giving good yield till the end of expected production life due to depletion, high water cut and also due to well integrity issues. Finding prolific reservoirs with thick pay zones and excellent rock quality are also becoming scarcer as more complex reservoir characterization comes into play. The challenges are further compounded by high uncertainty in distinguishing hydrocarbon fluid type. Hence, a systematic effort need to be garnered to sustain the production pipeline. This paper will present several case studies and petrophysical solutions in monetizing the untapped low resistivity low contrast reservoirs in a highly complex stratigraphic trap geological setting to squeeze more barrels into production as well as adding value to the reserves portfolio.\u0000 Identifying the low resistivity and low contrast (LRLC) reservoirs starts with delineating the log responses complemented by other subsurface data such as mud log, cores, fluid samples and advanced acoustic logging to determine lateral sand continuity. Often, well test and production data is used as the benchmark to identify hydrocarbon fluid type in the contradicting evidences. Comparison of nearby wells performance and evaluating fluid contact movement will be also part of the assessment stage. Application of in-house reservoir enhancement modeling (REM) will be the highlight of this paper to reveal those new promising reserves which are masked by thin laminated sand, low salinity, presence of light oil with similar log responses as gas and high silt content. Few examples relating the well production performance with log characteristics will be also discussed in this paper.\u0000 Results proved that production gain has soared up to 4800 bopd in total to make an astounding impact to the overall field production scenario. In few cases, significant new reserves addition is recorded which further open-up new upside opportunities for work-over, more aggressive production enhancement, appraisal and development drilling campaign. A systematic formation evaluation and petrophysical workflow has also been established to mature and realize the gain which sets a replication standard to the entire region. As more data comes in from the actual jobs done, a database relating the log responses with production capacity and catalogue of past job lessons learned have been initiated for future reference and demonstrating concrete evidences in realizing LRLC potential.\u0000 In a nutshell, exploiting LRLC potential in complex stratigraphic play requires an intensive subsurface evaluation and offers a promising opportunity in expanding the resource base and generating the cash. The efforts must continue with more success being replicated and bringing in more technology to minimize LRLC uncertainty and create a chain impact to production growth.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"62 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114488924","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. Cheers, Phillip Benham, G. Warrlich, M. Freeman, P. Choudhary, Prabitra Saika, A. Tyagi, Ian Zhang, K. Ahmed, A. Al-Rabah
North Kuwait heavy oil development continues to benefit from detailed study of outcrops at the Jal Az-Zor escarpment that are stratigraphic equivalents to some of their reservoirs. During the 2018-19 field season, focus was placed on recording the internal architectures of specific stratigraphic layers, developing a deeper understanding of the diagenetic processes in the basin and relating these observations to the North Kuwait reservoirs. These are all key controls on reservoir quality and connectivity. Inter-well scale heterogeneities were identified for inclusion into subsurface models to predict steam/polymer conformance and oil production better. Building on work of the 2017-18 field season when the Jal Az-Zor sequence was logged, measured, described and interpreted; units were tracked and correlated laterally for around 3km. Internal architectures of prominent layers were mapped through conventional and drone mounted photographic surveys, and satellite images. X-Ray Diffraction and thin section studies of hand samples were analyzed, to understand mineralogical controls on porosity & permeability. Integrated field trips were conducted with members from subsurface, reservoir and well-engineering disciplines, to engender common perspectives on subsurface uncertainties and development risks. They also served to close the communications gap between disciplines. Interpreted high-resolution photographic data, sediment flow direction measurements and other observations gave clues to environments of deposition and their implications for lateral connectivity for each layer. Observations on vertical connectivity between and within layers were recorded. Geological heterogeneities were considered in the context of the typical inter-well separation spacing for their implications on injected steam or polymer conformance, & water-cut. Depositional models were compiled and interpreted with regard to their implications for reservoir plumbing, H2S risk, top-seal integrity, sand production etc. Additionally, increased awareness of the stratigraphic relationships between zones was utilized to resolve correlation ambiguities for closed spaced wells in a water injection pilot and led to the development of a screening tool to predict water-coning risk in wells and informed a similar study for injected steam-conformance risk mapping. Field analogues at Jal Az-Zor are key to defining and characterizing the key genetic flow units of the heavy-oil reservoirs in North Kuwait and it is rare to have closely linked field-outcrop analogues so readily accessible. They represent an important cost-effective resource for field development and operations as they bridge the scale gap between well-derived and seismic data as they provide insight to the nature of flow unit connectivity (i.e. the reservoir plumbing – heterogeneities that matter-for-flow) in way that other data types do not. Field analogue observations therefore directly inform the grid scale permeability est
{"title":"Field Outcrop Analogue Studies - A Vital Resource for Heavy Oil Reservoir Development in North Kuwait","authors":"M. Cheers, Phillip Benham, G. Warrlich, M. Freeman, P. Choudhary, Prabitra Saika, A. Tyagi, Ian Zhang, K. Ahmed, A. Al-Rabah","doi":"10.2118/197993-ms","DOIUrl":"https://doi.org/10.2118/197993-ms","url":null,"abstract":"\u0000 North Kuwait heavy oil development continues to benefit from detailed study of outcrops at the Jal Az-Zor escarpment that are stratigraphic equivalents to some of their reservoirs. During the 2018-19 field season, focus was placed on recording the internal architectures of specific stratigraphic layers, developing a deeper understanding of the diagenetic processes in the basin and relating these observations to the North Kuwait reservoirs. These are all key controls on reservoir quality and connectivity. Inter-well scale heterogeneities were identified for inclusion into subsurface models to predict steam/polymer conformance and oil production better.\u0000 Building on work of the 2017-18 field season when the Jal Az-Zor sequence was logged, measured, described and interpreted; units were tracked and correlated laterally for around 3km. Internal architectures of prominent layers were mapped through conventional and drone mounted photographic surveys, and satellite images. X-Ray Diffraction and thin section studies of hand samples were analyzed, to understand mineralogical controls on porosity & permeability.\u0000 Integrated field trips were conducted with members from subsurface, reservoir and well-engineering disciplines, to engender common perspectives on subsurface uncertainties and development risks. They also served to close the communications gap between disciplines.\u0000 Interpreted high-resolution photographic data, sediment flow direction measurements and other observations gave clues to environments of deposition and their implications for lateral connectivity for each layer. Observations on vertical connectivity between and within layers were recorded. Geological heterogeneities were considered in the context of the typical inter-well separation spacing for their implications on injected steam or polymer conformance, & water-cut.\u0000 Depositional models were compiled and interpreted with regard to their implications for reservoir plumbing, H2S risk, top-seal integrity, sand production etc. Additionally, increased awareness of the stratigraphic relationships between zones was utilized to resolve correlation ambiguities for closed spaced wells in a water injection pilot and led to the development of a screening tool to predict water-coning risk in wells and informed a similar study for injected steam-conformance risk mapping.\u0000 Field analogues at Jal Az-Zor are key to defining and characterizing the key genetic flow units of the heavy-oil reservoirs in North Kuwait and it is rare to have closely linked field-outcrop analogues so readily accessible. They represent an important cost-effective resource for field development and operations as they bridge the scale gap between well-derived and seismic data as they provide insight to the nature of flow unit connectivity (i.e. the reservoir plumbing – heterogeneities that matter-for-flow) in way that other data types do not. Field analogue observations therefore directly inform the grid scale permeability est","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121486163","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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