Hydraulic fracturing is the main stimulation method used to economically produce from shale formations. The method requires the injection of a fracturing fluid at a pressure which is high enough to fracture the formation, and as a result, improves the well productivity. A proppant is pumped with the fracturing fluid to prevent the closure of the induced fractures after the treatment. The proppant inside the fracture is subjected to a high earth closure stress, which causes proppant crushing, embedment, and compaction mechanisms. The subsequent reduction of the fracture width and proppant porosity reduces the fracture conductivity and could be crucial to the success of the fracturing treatments. The objective of this study is to experimentally evaluate the reduction of the propped fracture width and proppant porosity between two Eagle Ford shale samples under stress conditions. An experimental model of propped fracture in Eagle Ford shale was prepared using outcrop samples. Sand proppant of the size 20/40, 40/70, and 100-mesh were tested at the concentrations of 0.2, 0.4, and 0.6 lb/ft2. A high-pressure core holder with modified fittings was used to subject the fracture model to different closure stress values up to 8,000 psia. A new method was used to evaluate the change in the propped fracture width and proppant porosity as a function of closure stress. The fracture width was measured by the consecutive imaging of the fracture under stress using a digital borescope and an image analysis software. The change in the proppant porosity was calculated at each stress and post-experiment sieve analysis was done to quantify the crushed proppant due to the applied stress. The fracture width and the equivalent proppant porosity under stress were found to be a function of the proppant size and concentration. The proppant porosity under stress was found to be directly proportional to the proppant concentration and inversely proportional to the proppant size. The reduction in fracture width and proppant porosity due to stress ranged from 3.66 to 22.03% and from 5.29 to 39.85% respectively. The crushing of sand proppant was found to be as high as 28.03% at 8,000 psia and 0.2 lb/ft2 proppant concentration, and reduced by increasing its concentration or decreasing its size. The propped fracture width and proppant porosity under stress can be used as inputs to well production models, reservoir simulation models, and fracture design calculations. The results can also be used in the proppant selection process to improve the fracture conductivity and maximize the well productivity of Eagle Ford shale formations.
{"title":"Experimental Evaluation of Sand Porosity in Eagle Ford Shale Fractures","authors":"A. Elsarawy, H. Nasr-El-Din","doi":"10.2118/191240-MS","DOIUrl":"https://doi.org/10.2118/191240-MS","url":null,"abstract":"\u0000 Hydraulic fracturing is the main stimulation method used to economically produce from shale formations. The method requires the injection of a fracturing fluid at a pressure which is high enough to fracture the formation, and as a result, improves the well productivity. A proppant is pumped with the fracturing fluid to prevent the closure of the induced fractures after the treatment. The proppant inside the fracture is subjected to a high earth closure stress, which causes proppant crushing, embedment, and compaction mechanisms. The subsequent reduction of the fracture width and proppant porosity reduces the fracture conductivity and could be crucial to the success of the fracturing treatments. The objective of this study is to experimentally evaluate the reduction of the propped fracture width and proppant porosity between two Eagle Ford shale samples under stress conditions.\u0000 An experimental model of propped fracture in Eagle Ford shale was prepared using outcrop samples. Sand proppant of the size 20/40, 40/70, and 100-mesh were tested at the concentrations of 0.2, 0.4, and 0.6 lb/ft2. A high-pressure core holder with modified fittings was used to subject the fracture model to different closure stress values up to 8,000 psia. A new method was used to evaluate the change in the propped fracture width and proppant porosity as a function of closure stress. The fracture width was measured by the consecutive imaging of the fracture under stress using a digital borescope and an image analysis software. The change in the proppant porosity was calculated at each stress and post-experiment sieve analysis was done to quantify the crushed proppant due to the applied stress.\u0000 The fracture width and the equivalent proppant porosity under stress were found to be a function of the proppant size and concentration. The proppant porosity under stress was found to be directly proportional to the proppant concentration and inversely proportional to the proppant size. The reduction in fracture width and proppant porosity due to stress ranged from 3.66 to 22.03% and from 5.29 to 39.85% respectively. The crushing of sand proppant was found to be as high as 28.03% at 8,000 psia and 0.2 lb/ft2 proppant concentration, and reduced by increasing its concentration or decreasing its size.\u0000 The propped fracture width and proppant porosity under stress can be used as inputs to well production models, reservoir simulation models, and fracture design calculations. The results can also be used in the proppant selection process to improve the fracture conductivity and maximize the well productivity of Eagle Ford shale formations.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75504669","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}
Sherif Fakher, H. Abdelaal, Y. Elgahawy, Ahmed El Tonbary, Abdulmohsin Imqam
When producing from gas hydrate reservoirs using steam flooding, since hydrate dissociation is an endothermic reaction, the heat is used up. This results in a decrease in reservoir temperature which causes the hydrate equilibrium conditions to be established again, thus causing hydrate reformation. This research studies the effect of injecting thermodynamic inhibitors during steam injection on overcoming the problem of hydrate reformation which in turn will increase hydrocarbon recovery significantly from hydrate reservoirs. The reservoir model was built based on data collected from previous models found in the literature. After specifying all parameters for the reservoir, and the hydrate layer, a systematic study was performed in order to assess the use of inhibitors with steam flooding. The production methods studied include depressurization, steam flooding, inhibitor injection including both brine and glycol, and finally the combined steam flooding inhibitor injection method. The conditions for the steam flooding were kept the same during all runs in order to be able to compare them. Results indicated that the use of the thermal stimulation alone without inhibitor managed to increase recovery, however, the problem of hydrate reformation occurred which caused a cessation of production. Using inhibitors alone managed to increase recovery as well, however the recovery increase was much less compared to thermal stimulation. The type of inhibitor also played a role in recovery with the glycol producing the most, followed by the brine. By combining both steam flooding and inhibitor injection, the recovery increased significantly more than what was observed when using each of the methods on its own. To the authors' knowledge, no extensive study has been performed by combining both steam flooding and inhibitor to increase hydrocarbon recovery from hydrate reservoirs. This research can help in improving real field gas hydrate projects by making the overall project much more economic by increasing hydrocarbon recovery.
{"title":"Increasing Production Flow Rate and Overall Recovery from Gas Hydrate Reservoirs Using a Combined Steam Flooding-Thermodynamic Inhibitor Technique","authors":"Sherif Fakher, H. Abdelaal, Y. Elgahawy, Ahmed El Tonbary, Abdulmohsin Imqam","doi":"10.2118/191179-MS","DOIUrl":"https://doi.org/10.2118/191179-MS","url":null,"abstract":"\u0000 When producing from gas hydrate reservoirs using steam flooding, since hydrate dissociation is an endothermic reaction, the heat is used up. This results in a decrease in reservoir temperature which causes the hydrate equilibrium conditions to be established again, thus causing hydrate reformation. This research studies the effect of injecting thermodynamic inhibitors during steam injection on overcoming the problem of hydrate reformation which in turn will increase hydrocarbon recovery significantly from hydrate reservoirs. The reservoir model was built based on data collected from previous models found in the literature. After specifying all parameters for the reservoir, and the hydrate layer, a systematic study was performed in order to assess the use of inhibitors with steam flooding. The production methods studied include depressurization, steam flooding, inhibitor injection including both brine and glycol, and finally the combined steam flooding inhibitor injection method. The conditions for the steam flooding were kept the same during all runs in order to be able to compare them. Results indicated that the use of the thermal stimulation alone without inhibitor managed to increase recovery, however, the problem of hydrate reformation occurred which caused a cessation of production. Using inhibitors alone managed to increase recovery as well, however the recovery increase was much less compared to thermal stimulation. The type of inhibitor also played a role in recovery with the glycol producing the most, followed by the brine. By combining both steam flooding and inhibitor injection, the recovery increased significantly more than what was observed when using each of the methods on its own. To the authors' knowledge, no extensive study has been performed by combining both steam flooding and inhibitor to increase hydrocarbon recovery from hydrate reservoirs. This research can help in improving real field gas hydrate projects by making the overall project much more economic by increasing hydrocarbon recovery.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"19 12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82635606","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}
Zhang-cong Liu, Chang-chun Chen, Xue Lv, Zhao-peng Yang, Y. Shen, Yanyan Luo, Xingmin Li
Primary production using horizontal wells has been successfully applied in extra-heavy oil reservoirs, heavy oil belt, Orinoco, Venezuela. During drilling period, formation damage due to drilling fluid invasion lowers the effective permeability around the well, leads to higher pressure drop and has detrimental impact on well productivity in such pressure depleted reservoirs. In this study, laboratory experiments of drilling fluid invasion are conducted to identify damage mechanism. The oil sample used in the test is taken from Block J, Orinoco Belt and the formation temperature is restored in the lab to mimic the process of drilling fluid mixing with crude oil in horizontal drilling. The stable emulsion is formed by mixing the crude oil with drilling fluid in different proportions. Furthermore, damage level is quantified by well test interpretation. Skin factor, wellbore storage and other formation parameters are estimated by deconvolution method based on three build-ups. Finally, acid washing and well bottomhole electric heating, two methods of remedy are applied in oilfield. Experiment results show that low productivity of the horizontal wells is due to the presence of highly viscous emulsion system stabilized by large amount of calcium carbonate in drilling fluid. The emulsion system restricts reservoir fluid flowing from the formation to the slotted liner. In Block J, constrained by the operational problems, the effective shut-in time is commonly short. Conventional well test method can hardly give the reliable results. Compared with the conventional method, deconvolution method can solve the data limitation, minimize the initial distortion caused by wellbore storage and get more reliable results. The production can be improved temporarily after the acid washing while declines rapidly. Electric heating can obviously improve the oil mobility near wellbore and maintain stable production. This paper combines both lab studies and well test interpretation to characterize the formation damage, provides guidance for the remedial operations to improve well productivity.
{"title":"Formation Damage Characterization of Horizontal Well in Extra-Heavy Oil Reservoir and Methods of Remedy","authors":"Zhang-cong Liu, Chang-chun Chen, Xue Lv, Zhao-peng Yang, Y. Shen, Yanyan Luo, Xingmin Li","doi":"10.2118/191158-MS","DOIUrl":"https://doi.org/10.2118/191158-MS","url":null,"abstract":"\u0000 Primary production using horizontal wells has been successfully applied in extra-heavy oil reservoirs, heavy oil belt, Orinoco, Venezuela. During drilling period, formation damage due to drilling fluid invasion lowers the effective permeability around the well, leads to higher pressure drop and has detrimental impact on well productivity in such pressure depleted reservoirs.\u0000 In this study, laboratory experiments of drilling fluid invasion are conducted to identify damage mechanism. The oil sample used in the test is taken from Block J, Orinoco Belt and the formation temperature is restored in the lab to mimic the process of drilling fluid mixing with crude oil in horizontal drilling. The stable emulsion is formed by mixing the crude oil with drilling fluid in different proportions. Furthermore, damage level is quantified by well test interpretation. Skin factor, wellbore storage and other formation parameters are estimated by deconvolution method based on three build-ups. Finally, acid washing and well bottomhole electric heating, two methods of remedy are applied in oilfield.\u0000 Experiment results show that low productivity of the horizontal wells is due to the presence of highly viscous emulsion system stabilized by large amount of calcium carbonate in drilling fluid. The emulsion system restricts reservoir fluid flowing from the formation to the slotted liner. In Block J, constrained by the operational problems, the effective shut-in time is commonly short. Conventional well test method can hardly give the reliable results. Compared with the conventional method, deconvolution method can solve the data limitation, minimize the initial distortion caused by wellbore storage and get more reliable results. The production can be improved temporarily after the acid washing while declines rapidly. Electric heating can obviously improve the oil mobility near wellbore and maintain stable production.\u0000 This paper combines both lab studies and well test interpretation to characterize the formation damage, provides guidance for the remedial operations to improve well productivity.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79885755","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}
C. Guerrero-Martin, E. Montes-Páez, M. Oliveira, J. Campos, E. Lucas
Asphaltenes precipitation is considered a formation damage problem, which can reduce the oil recovery factor. It fouls piping and surface installations, as well as cause serious flow assurance complications and decline oil well production. Therefore, researchers have shown an interest in chemical treatments to control this phenomenon. The aim of this paper is to assess the asphaltenes precipitation onset of crude oils in the presence of cardanol, by titrating the crude with n-heptane. Moreover, based on this results obtained at atmosphere pressure, the asphaltenes precipitation onset pressure were calculated to predict asphaltenes precipitation in the reservoir, by using differential liberation and refractive index data of the oils. The influence of cardanol concentration on the asphaltenes stabilization of three Brazilian crude oils samples (with similar API densities) was studied. Therefore, three formulations of cardanol were prepared: The formulations were added to the crude at 5:98, 1.5:98.5, 2:98 and 4:96 ratios. The petroleum samples were characterized by API density, elemental analysis and differential liberation test. The asphaltenes precipitation onset was determined by titrating with n-heptane and monitoring with near-infrared (NIR). The asphaltenes precipitation onset pressures were estimated. The envelope phase of the crude oils were also determined by numerical simulation (pipesim). In addition, supported in the downhole well profile and a screening methodology, the adequate artificial lift systems (ALS) for the oils were selected. Finally, the oil flow rates were modelling by NODAL analysis production system in the SNAP software. The results of this study show the refractive index for each sample, and the predictive pressure to asphaltene instability. The asphaltenes precipitation onset of the crude oils were 2.06, 2.30 and 6.02 mL of n-heptane/g of oil. The cardanol was an effective inhibitor of asphaltenes precipitation, since it displaces the precipitation pressure of the oil to lower values. This indicates that cardanol can increase the oil wells productivity.
沥青质沉淀被认为是一个地层损害问题，它会降低采收率。它会污染管道和地面设施，造成严重的流动保障问题，并导致油井产量下降。因此，研究人员对化学治疗来控制这种现象表现出了兴趣。本文的目的是通过用正庚烷滴定原油来评估腰果酚存在下原油沥青质沉淀的开始。在此基础上，利用原油的微分解离和折射率数据，计算了沥青质析出开始压力，预测了储层中沥青质的析出。研究了腰果酚浓度对3种API浓度相近的巴西原油沥青质稳定性的影响。为此，制备了三种腰果酚配方:分别以5:98、1.5:98.5、2:98和4:96的比例加入粗料。采用API密度、元素分析和差解试验对石油样品进行了表征。采用正庚烷滴定法和近红外(NIR)监测法测定沥青质析出的起始时间。估算了沥青质沉淀开始压力。通过数值模拟(管道模拟)确定了原油的包络相。此外，在井下井廓和筛选方法的支持下，选择了适当的人工举升系统(ALS)。最后，利用SNAP软件中的NODAL分析生产系统对油流进行建模。本研究的结果显示了每个样品的折射率，以及沥青质不稳定性的预测压力。原油沥青质析出量分别为2.06、2.30和6.02 mL /g原油。腰果酚是一种有效的沥青质沉淀抑制剂，因为它取代了石油的沉淀压力到较低的值。说明腰果酚能提高油井产能。
{"title":"Calculating Asphaltenes Precipitation Onset Pressure by Using Cardanol as Precipitation Inhibitor: A Strategy to Increment the Oil Well Production","authors":"C. Guerrero-Martin, E. Montes-Páez, M. Oliveira, J. Campos, E. Lucas","doi":"10.2118/191275-MS","DOIUrl":"https://doi.org/10.2118/191275-MS","url":null,"abstract":"\u0000 Asphaltenes precipitation is considered a formation damage problem, which can reduce the oil recovery factor. It fouls piping and surface installations, as well as cause serious flow assurance complications and decline oil well production. Therefore, researchers have shown an interest in chemical treatments to control this phenomenon. The aim of this paper is to assess the asphaltenes precipitation onset of crude oils in the presence of cardanol, by titrating the crude with n-heptane. Moreover, based on this results obtained at atmosphere pressure, the asphaltenes precipitation onset pressure were calculated to predict asphaltenes precipitation in the reservoir, by using differential liberation and refractive index data of the oils.\u0000 The influence of cardanol concentration on the asphaltenes stabilization of three Brazilian crude oils samples (with similar API densities) was studied. Therefore, three formulations of cardanol were prepared: The formulations were added to the crude at 5:98, 1.5:98.5, 2:98 and 4:96 ratios.\u0000 The petroleum samples were characterized by API density, elemental analysis and differential liberation test. The asphaltenes precipitation onset was determined by titrating with n-heptane and monitoring with near-infrared (NIR). The asphaltenes precipitation onset pressures were estimated. The envelope phase of the crude oils were also determined by numerical simulation (pipesim). In addition, supported in the downhole well profile and a screening methodology, the adequate artificial lift systems (ALS) for the oils were selected. Finally, the oil flow rates were modelling by NODAL analysis production system in the SNAP software.\u0000 The results of this study show the refractive index for each sample, and the predictive pressure to asphaltene instability. The asphaltenes precipitation onset of the crude oils were 2.06, 2.30 and 6.02 mL of n-heptane/g of oil. The cardanol was an effective inhibitor of asphaltenes precipitation, since it displaces the precipitation pressure of the oil to lower values. This indicates that cardanol can increase the oil wells productivity.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79897317","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}
Proppant diagenesis has been introduced recently as a damaging mechanism to the fracture conductivity in shale formations. The mechanism was used to explain the low values of the field-measured fracture conductivity as well as the long-term decline of the lab-measured API conductivity data. Previous studies revealed the presence of a diagenetic overgrowth on the proppant surface and around the embedment crater after being exposed to high-temperature and/or high-stress conditions. The objective of this paper is to experimentally investigate the diagenesis of bauxite proppant in calcite rich Eagle Ford shale fractures. The interaction between the proppant and the formation was studied by aging its mixture in a deionized water for prolonged period of time at elevated temperature of 325°F to accelerate the involved reactions. Aluminum-based bauxite proppant of 20/40 mesh-size was mixed with a crushed Eagle Ford shale sample of 50/100 mesh-size. The mixture was aged at 325°F and 300 psia for three weeks. The surfaces of the proppant and the formation were examined for mineral overgrowth and dissolution using scanning electron microscope (SEM) with energy dispersive X-ray spectroscopy (EDS). The supernatant fluid was analyzed for cations’ concentrations using inductively coupled plasma (ICP) and the sulfate ion concentration was measured using a spectrophotometer. The proppant and Eagle Ford formation were then aged separately at the same conditions to explain the sources of the leached ions and the observed overgrowth materials. The results show the diagenetic activity that could result from the use of bauxite proppant in Eagle Ford shale fracturing. The ICP results indicated the potential dissolution of the proppant at high temperature. The observed overgrowth materials were identified as calcium sulfate, calcium zeolite, and iron-calcium zeolite. The calcium sulfate was found to be explicitly sourced from the Eagle Ford dissolution-precipitation mechanism. The SEM/EDS results indicated the presence of calcium zeolite after aging both cells: the proppant/formation mixture and the formation alone. The iron-calcium zeolite was found on the proppant surface as a result of the fluid/proppant/shale interactions. The study contributes to the understanding of the damaging mechanisms to the fracture conductivity in the Eagle Ford shale formation. Results impact the choice of proppant and fluid for fracturing optimization and long-term production sustainability in the Eagle Ford shale reservoirs.
{"title":"An Experimental Investigation of Proppant Diagenesis and Proppant-Formation-Fluid Interactions in Hydraulic Fracturing of Eagle Ford Shale","authors":"A. Elsarawy, H. Nasr-El-Din","doi":"10.2118/191225-MS","DOIUrl":"https://doi.org/10.2118/191225-MS","url":null,"abstract":"\u0000 Proppant diagenesis has been introduced recently as a damaging mechanism to the fracture conductivity in shale formations. The mechanism was used to explain the low values of the field-measured fracture conductivity as well as the long-term decline of the lab-measured API conductivity data. Previous studies revealed the presence of a diagenetic overgrowth on the proppant surface and around the embedment crater after being exposed to high-temperature and/or high-stress conditions. The objective of this paper is to experimentally investigate the diagenesis of bauxite proppant in calcite rich Eagle Ford shale fractures.\u0000 The interaction between the proppant and the formation was studied by aging its mixture in a deionized water for prolonged period of time at elevated temperature of 325°F to accelerate the involved reactions. Aluminum-based bauxite proppant of 20/40 mesh-size was mixed with a crushed Eagle Ford shale sample of 50/100 mesh-size. The mixture was aged at 325°F and 300 psia for three weeks. The surfaces of the proppant and the formation were examined for mineral overgrowth and dissolution using scanning electron microscope (SEM) with energy dispersive X-ray spectroscopy (EDS). The supernatant fluid was analyzed for cations’ concentrations using inductively coupled plasma (ICP) and the sulfate ion concentration was measured using a spectrophotometer. The proppant and Eagle Ford formation were then aged separately at the same conditions to explain the sources of the leached ions and the observed overgrowth materials.\u0000 The results show the diagenetic activity that could result from the use of bauxite proppant in Eagle Ford shale fracturing. The ICP results indicated the potential dissolution of the proppant at high temperature. The observed overgrowth materials were identified as calcium sulfate, calcium zeolite, and iron-calcium zeolite. The calcium sulfate was found to be explicitly sourced from the Eagle Ford dissolution-precipitation mechanism. The SEM/EDS results indicated the presence of calcium zeolite after aging both cells: the proppant/formation mixture and the formation alone. The iron-calcium zeolite was found on the proppant surface as a result of the fluid/proppant/shale interactions.\u0000 The study contributes to the understanding of the damaging mechanisms to the fracture conductivity in the Eagle Ford shale formation. Results impact the choice of proppant and fluid for fracturing optimization and long-term production sustainability in the Eagle Ford shale reservoirs.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75613427","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 difficulty of determining effective water saturations in shaly-sand oil reservoirs is an old industry problem. Zones with high water saturation may not be developed even though the resistivity logs show that hydrocarbon exist and production data indicate low water cuts. Reservoirs offshore Southwest Trinidad are examples that show a high degree of mismatch between conventional log analysis and test/production results. These shaly-sandstone reservoirs have water saturations of 50-60% and produce water-free oil or have small water cut values (<5%) based on production reports. The benefits of Nuclear Magnetic Resonance (NMR) logging data to improve shaly-sand analysis and the ability to separately predict mobile water and bound water have been demonstrated by many practitioners. However, the methods of integrating NMR data can be standalone, deterministic or statistical and the type of petrophysical outputs can vary widely. This study assesses the impact of integration methods of NMR/Open-hole data on petrophysical outputs by carrying out an extensive study on log data from five (5) wells offshore Southwest Trinidad. Methodologies for quality control of NMR data and deterministic and statistical workflows for integrating NMR and Conventional Logging data were demonstrated. An effective baseline for comparison was established by using the same environmentally corrected log data, shale/ clay parameters, water resistivity (Rw) and saturation exponents for all techniques. A Dual Water (DWM) and Wet Shale Model (WSM) workflows were developed and three sets of analyses were conducted. In the first analysis Conventional Logging data only were applied in a typical deterministic approach. In the second analysis NMR data and Conventional data were applied using a modified deterministic approach. In the third analysis NMR and Conventional log data were applied in a statistical approach via a system of simultaneous equations. All of the corresponding petrophysical outputs from these three methods of analyses were then compared with core and production data. NMR-derived total porosities were found to match core porosities regardless of shale/clay content, whereas density log porosities match only in clean reservoir sections. In shaly intervals, the Neutron-Density porosities were 5-7% higher and Density porosities were 3-5% lower than core porosities. The results from this study also show that total water saturations (Swt DWM) using NMR- derived porosities (total and bound) were similar to core data. In shaly reservoir sections, Swt-DWM and Swt-WSM using conventional logging data were 10-15% and 15-20% higher than core water saturations respectively. The integration of NMR data using a statistical approach gives the most reliable results for computing irreducible water saturations for shaly sand reservoirs with high water sturations and low water-cut. This case study illustrates how to undertake shaly-sand analysis using NMR data, including the quality
{"title":"NMR Application in the Development of High Water Saturation Shaly Sand Oil Reservoirs: A Case Study Offshore Southwest Trinidad","authors":"Kala Singh-Samlal, R. Hosein","doi":"10.2118/191164-MS","DOIUrl":"https://doi.org/10.2118/191164-MS","url":null,"abstract":"\u0000 The difficulty of determining effective water saturations in shaly-sand oil reservoirs is an old industry problem. Zones with high water saturation may not be developed even though the resistivity logs show that hydrocarbon exist and production data indicate low water cuts. Reservoirs offshore Southwest Trinidad are examples that show a high degree of mismatch between conventional log analysis and test/production results. These shaly-sandstone reservoirs have water saturations of 50-60% and produce water-free oil or have small water cut values (<5%) based on production reports. The benefits of Nuclear Magnetic Resonance (NMR) logging data to improve shaly-sand analysis and the ability to separately predict mobile water and bound water have been demonstrated by many practitioners. However, the methods of integrating NMR data can be standalone, deterministic or statistical and the type of petrophysical outputs can vary widely.\u0000 This study assesses the impact of integration methods of NMR/Open-hole data on petrophysical outputs by carrying out an extensive study on log data from five (5) wells offshore Southwest Trinidad. Methodologies for quality control of NMR data and deterministic and statistical workflows for integrating NMR and Conventional Logging data were demonstrated. An effective baseline for comparison was established by using the same environmentally corrected log data, shale/ clay parameters, water resistivity (Rw) and saturation exponents for all techniques. A Dual Water (DWM) and Wet Shale Model (WSM) workflows were developed and three sets of analyses were conducted. In the first analysis Conventional Logging data only were applied in a typical deterministic approach. In the second analysis NMR data and Conventional data were applied using a modified deterministic approach. In the third analysis NMR and Conventional log data were applied in a statistical approach via a system of simultaneous equations. All of the corresponding petrophysical outputs from these three methods of analyses were then compared with core and production data.\u0000 NMR-derived total porosities were found to match core porosities regardless of shale/clay content, whereas density log porosities match only in clean reservoir sections. In shaly intervals, the Neutron-Density porosities were 5-7% higher and Density porosities were 3-5% lower than core porosities. The results from this study also show that total water saturations (Swt DWM) using NMR- derived porosities (total and bound) were similar to core data. In shaly reservoir sections, Swt-DWM and Swt-WSM using conventional logging data were 10-15% and 15-20% higher than core water saturations respectively. The integration of NMR data using a statistical approach gives the most reliable results for computing irreducible water saturations for shaly sand reservoirs with high water sturations and low water-cut.\u0000 This case study illustrates how to undertake shaly-sand analysis using NMR data, including the quality ","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83381643","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}
Yu Bao, Liang He, Xue Lv, Y. Shen, Xingmin Li, Zhang-cong Liu, Zhao-peng Yang
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters. The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.
{"title":"An Evaluation of Enhanced Oil Recovery Strategies for Extra Heavy Oil Reservoir after Cold Production without Sand in Orinoco, Venezuela","authors":"Yu Bao, Liang He, Xue Lv, Y. Shen, Xingmin Li, Zhang-cong Liu, Zhao-peng Yang","doi":"10.2118/191177-MS","DOIUrl":"https://doi.org/10.2118/191177-MS","url":null,"abstract":"\u0000 The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.\u0000 The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78825179","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}
Conventionally, a calibrated 1D geomechanical model is used to define the mud weight window required for the successful drilling and completion of a well. Utilizing depth stretch functionality, estimated rock properties and subsurface stresses, are ‘stretched’ from the corresponding offset well to the proposed well to be drilled. This approach will only suffice if the geological structure and wellbore trajectory are relatively simple. Even so, optimizing wellbore placement becomes an arduous exercise when using 1D geomechanical models because the workflow must be repeated for each new iteration of the proposed wellbore trajectory. Furthermore, as the geological structure and wellbore trajectory increases in complexity, severe distortion in topological properties, such as overburden stress and pore pressure, can render the one-dimensional solution inapplicable. In such circumstances, a calibrated 3D geomechanical model can be used. This paper introduces a generic workflow for developing a calibrated 3D geomechanical model that can be used for wellbore stability analysis. The workflow incorporates calibrated 1D geomechanical models and existing static geological modeling outputs, such as structural surfaces and facies model, to constrain the distribution of topological and primary properties within a 3D structural framework. The applicability of the workflow will be demonstrated by presenting the results of a case study from the Starfish field, ECMA, offshore Trinidad. It is intended for this paper to serve as a reference to geoscientists and engineers involved in brownfield and greenfield development planning. By extension, subsurface professionals who are involved in integrated reservoir modeling may also benefit from the work presented since geomechanics is often omitted from the modelling workflow.
{"title":"3D Geomechanical Modeling for Wellbore Stability Analysis: Starfish, ECMA, Trinidad and Tobago","authors":"Rashad Ramjohn, T. Gan, M. Sarfare","doi":"10.2118/191242-MS","DOIUrl":"https://doi.org/10.2118/191242-MS","url":null,"abstract":"\u0000 Conventionally, a calibrated 1D geomechanical model is used to define the mud weight window required for the successful drilling and completion of a well. Utilizing depth stretch functionality, estimated rock properties and subsurface stresses, are ‘stretched’ from the corresponding offset well to the proposed well to be drilled. This approach will only suffice if the geological structure and wellbore trajectory are relatively simple. Even so, optimizing wellbore placement becomes an arduous exercise when using 1D geomechanical models because the workflow must be repeated for each new iteration of the proposed wellbore trajectory. Furthermore, as the geological structure and wellbore trajectory increases in complexity, severe distortion in topological properties, such as overburden stress and pore pressure, can render the one-dimensional solution inapplicable.\u0000 In such circumstances, a calibrated 3D geomechanical model can be used. This paper introduces a generic workflow for developing a calibrated 3D geomechanical model that can be used for wellbore stability analysis. The workflow incorporates calibrated 1D geomechanical models and existing static geological modeling outputs, such as structural surfaces and facies model, to constrain the distribution of topological and primary properties within a 3D structural framework. The applicability of the workflow will be demonstrated by presenting the results of a case study from the Starfish field, ECMA, offshore Trinidad. It is intended for this paper to serve as a reference to geoscientists and engineers involved in brownfield and greenfield development planning. By extension, subsurface professionals who are involved in integrated reservoir modeling may also benefit from the work presented since geomechanics is often omitted from the modelling workflow.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79492224","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}
Kunkun Fan, Ren-yuan Sun, D. Elsworth, M. Dong, Yajun Li, C. Yin, Yanchao Li
Shale gas is becoming an important addition to worldwide energy supply with permeability a critical controlling factor for gas production. Helium permeability determined using small pressure gradient (SPG)methods may lead to erroneous results when applied to actual field production with variable pressure gradients (VPG). In this paper, a VPG method using real gas (rather than He) is established to render permeability measurements more representative of reservoir conditions and hence response. Dynamic methane production experiments are performed to measure permeability using the annular space in shale cores. Boundary pressure is maintained constant within each production stage with a designated pressure gradient and the gas production with time is measured. A mathematical model explicitly accommodating gas desorption uses pseudo-pressure and normalized time to accommodate the effects of variations in pressure-dependent viscosity and compressibility. General and approximate solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the approximate solution with the recorded gas production data. Results indicate that the radial permeability of the shale determined with methane is of the order of of 10-6∼10-5md and decreases with an increase in average pore pressure. This is contrary to the observed change in permeability estimated with helium. Permeability errors obtained from the SPG method using helium are several times greater than those obtained from the VPG method using methane. Bedding geometry has a significant influence on shale permeability. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods. The VPG method has two advantages: The first is that reservoir gas can be used in the VPG method instead of helium, better incorporating potential desorption impacts in permeability evltuion. The second is that realistic pressure dependent impacts can be accurately accommodated, making this method more applicable to gas production conditions in the reservoir. Although several assumptions are used, the results obtained from the VPG method are much closer to reality and may be directly used for actual gas production evaluation and prediction.
{"title":"Radial Permeability Measurement for Shale Using Variable Pressure Gradients","authors":"Kunkun Fan, Ren-yuan Sun, D. Elsworth, M. Dong, Yajun Li, C. Yin, Yanchao Li","doi":"10.2118/191198-MS","DOIUrl":"https://doi.org/10.2118/191198-MS","url":null,"abstract":"\u0000 Shale gas is becoming an important addition to worldwide energy supply with permeability a critical controlling factor for gas production. Helium permeability determined using small pressure gradient (SPG)methods may lead to erroneous results when applied to actual field production with variable pressure gradients (VPG). In this paper, a VPG method using real gas (rather than He) is established to render permeability measurements more representative of reservoir conditions and hence response.\u0000 Dynamic methane production experiments are performed to measure permeability using the annular space in shale cores. Boundary pressure is maintained constant within each production stage with a designated pressure gradient and the gas production with time is measured. A mathematical model explicitly accommodating gas desorption uses pseudo-pressure and normalized time to accommodate the effects of variations in pressure-dependent viscosity and compressibility. General and approximate solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the approximate solution with the recorded gas production data.\u0000 Results indicate that the radial permeability of the shale determined with methane is of the order of of 10-6∼10-5md and decreases with an increase in average pore pressure. This is contrary to the observed change in permeability estimated with helium. Permeability errors obtained from the SPG method using helium are several times greater than those obtained from the VPG method using methane. Bedding geometry has a significant influence on shale permeability. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods.\u0000 The VPG method has two advantages: The first is that reservoir gas can be used in the VPG method instead of helium, better incorporating potential desorption impacts in permeability evltuion. The second is that realistic pressure dependent impacts can be accurately accommodated, making this method more applicable to gas production conditions in the reservoir. Although several assumptions are used, the results obtained from the VPG method are much closer to reality and may be directly used for actual gas production evaluation and prediction.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77970578","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 Technical Paper is to show the experiences and challenges in the design and execution of an extended reach well in unconsolidated sands carried out by Pluspetrol Bolivia Corporation in the Tacobo-Curiche Area. Due to surface obstacles (bed of the Rio Grande river) was proposed the drilling of a directional well which trajectory had to pass through two objectives: 1570 m Horizontal Displacement (HD) at 770 mTVD and 2345 mHD at 1171 mTVD, with the following conditions: 1st.- unconsolidated sands, 2nd.- channel of the river and 3rd.- superficiality of the objectives. The main objectives set for this project were: Reach the targets in the required position.Provide well quality to obtain reservoir data.Provide a well capable of being tested and produced in multiple thin layers of reservoir. These objectives raised technical challenges in different areas of well construction, i) curve construction in the first section with significant Dog Leg Severity (DLS) in well of 17½" and in unconsolidated sands, ii) complex trajectory type "S" with HD/TVD ratio> 2; iii) collision with existing well; iv) well stability and v) cementing job for high angle well, with long areas of interest and interspersed water levels. To face these challenges, it was necessary to achieve a balance between hole cleaning, bit hydraulics, Rate of Penetration (ROP) and BHA directional response, being of vital importance for this, thixotropic mud, its density and the management of drilling parameters. The challenges and the way to face them will be developed in this Technical Paper together with the results obtained.
{"title":"Extended Reach Wells in Unconsolidated Sands in Bolivia","authors":"G. Dordoni","doi":"10.2118/191271-MS","DOIUrl":"https://doi.org/10.2118/191271-MS","url":null,"abstract":"\u0000 The objective of this Technical Paper is to show the experiences and challenges in the design and execution of an extended reach well in unconsolidated sands carried out by Pluspetrol Bolivia Corporation in the Tacobo-Curiche Area. Due to surface obstacles (bed of the Rio Grande river) was proposed the drilling of a directional well which trajectory had to pass through two objectives: 1570 m Horizontal Displacement (HD) at 770 mTVD and 2345 mHD at 1171 mTVD, with the following conditions: 1st.- unconsolidated sands, 2nd.- channel of the river and 3rd.- superficiality of the objectives.\u0000 The main objectives set for this project were: Reach the targets in the required position.Provide well quality to obtain reservoir data.Provide a well capable of being tested and produced in multiple thin layers of reservoir.\u0000 These objectives raised technical challenges in different areas of well construction, i) curve construction in the first section with significant Dog Leg Severity (DLS) in well of 17½\" and in unconsolidated sands, ii) complex trajectory type \"S\" with HD/TVD ratio> 2; iii) collision with existing well; iv) well stability and v) cementing job for high angle well, with long areas of interest and interspersed water levels.\u0000 To face these challenges, it was necessary to achieve a balance between hole cleaning, bit hydraulics, Rate of Penetration (ROP) and BHA directional response, being of vital importance for this, thixotropic mud, its density and the management of drilling parameters.\u0000 The challenges and the way to face them will be developed in this Technical Paper together with the results obtained.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83185275","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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