{"title":"Modelling of Bitumen-and-Solvent-Mixture Viscosity Data Using Thermodynamic Perturbation Theory","authors":"Mohsen Zirrahi, H. Hassanzadeh, J. Abedi","doi":"10.2118/157930-PA","DOIUrl":"https://doi.org/10.2118/157930-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"53 1","pages":"48-54"},"PeriodicalIF":0.0,"publicationDate":"2014-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/157930-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67738842","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. Nobakht, R. Ambrose, C. Clarkson, J. E. Youngblood, R. Adams
Shale gas reservoirs have become a significant source of gas supply in North America because of the advancement of drilling and stimulation techniques enabling commercial development. The most popular method for exploiting shale gas reservoirs today is the use of long horizontal wells completed with multiple-fracturing stages [multifractured horizontal wells (MFHW)]. The stimulation process may result in biwing fractures or a complex hydraulic-fracture network. However, there is no method to differentiate between these two scenarios with production data analysis alone, making accurate forecasting difficult. For simplicity, hydraulic fractures are often considered biwing when analyzing production data. A conceptual model that is often used for analyzing MFHWs is that of a homogeneous completion in which all fractures have the same length. However, fractures of equal length are rarely if ever observed (Ambrose et al. 2011). In this paper, production data from heterogeneous MFHWs (i.e., where all fracture lengths are not the same) is studied for reservoirs with extremely low permeability. First, the simplified forecasting method of Nobakht et al. (2012), developed for homogeneous completions, is extended to heterogeneous completions. For one specific case, the Arps' decline exponent is correlated to the heterogeneity of the completion. It is found that, as expected, Arps' decline exponent (used after the end of linear flow) increases with the heterogeneity of the completion. Finally, it is shown that ignoring the heterogeneity of the completion can have a material effect on the long-term forecast. We have assumed planar hydraulic-fracture geometries for our modelling in this work and discuss the implications of this when more-complex fracture geometries are created. This seems to be more common in shale gas reservoirs. We provide an example of low-complexity, planar fracture geometries created near an MFHW and observed on an image log at an offset well.
由于钻井和增产技术的进步，页岩气藏已成为北美地区重要的天然气供应来源。目前，开发页岩气藏最流行的方法是使用多级压裂的长水平井(MFHW)。增产过程可能会形成斜缝或复杂的水力裂缝网络。然而，没有办法单独通过生产数据分析来区分这两种情况，这使得准确预测变得困难。为了简单起见，在分析生产数据时，水力裂缝通常被认为是弯曲的。通常用于分析MFHWs的概念模型是均匀完井，其中所有裂缝都具有相同的长度。然而，相等长度的骨折很少被观察到(Ambrose et al. 2011)。本文研究了非均质MFHWs(即所有裂缝长度不相同)的极低渗透率储层的生产数据。首先，将Nobakht等人(2012)为均匀完井开发的简化预测方法推广到非均匀完井。在一个特定的情况下，Arps的下降指数与完井的异质性有关。研究发现，正如预期的那样，Arps的下降指数(线性流动结束后使用的指数)随着完井的非均质性而增加。最后，研究表明，忽略完井的异质性会对长期预测产生重大影响。在这项工作中，我们假设了平面水力裂缝的几何形状，并讨论了在创建更复杂的裂缝几何形状时的意义。这似乎在页岩气藏中更为常见。我们提供了在MFHW附近创建的低复杂性平面裂缝几何形状的示例，并在邻井的图像测井中进行了观察。
{"title":"Effect of Completion Heterogeneity in a Horizontal Well With Multiple Fractures on the Long-Term Forecast in Shale-Gas Reservoirs","authors":"M. Nobakht, R. Ambrose, C. Clarkson, J. E. Youngblood, R. Adams","doi":"10.2118/149400-PA","DOIUrl":"https://doi.org/10.2118/149400-PA","url":null,"abstract":"Shale gas reservoirs have become a significant source of gas supply in North America because of the advancement of drilling and stimulation techniques enabling commercial development. The most popular method for exploiting shale gas reservoirs today is the use of long horizontal wells completed with multiple-fracturing stages [multifractured horizontal wells (MFHW)]. The stimulation process may result in biwing fractures or a complex hydraulic-fracture network. However, there is no method to differentiate between these two scenarios with production data analysis alone, making accurate forecasting difficult. For simplicity, hydraulic fractures are often considered biwing when analyzing production data. A conceptual model that is often used for analyzing MFHWs is that of a homogeneous completion in which all fractures have the same length. However, fractures of equal length are rarely if ever observed (Ambrose et al. 2011). In this paper, production data from heterogeneous MFHWs (i.e., where all fracture lengths are not the same) is studied for reservoirs with extremely low permeability. First, the simplified forecasting method of Nobakht et al. (2012), developed for homogeneous completions, is extended to heterogeneous completions. For one specific case, the Arps' decline exponent is correlated to the heterogeneity of the completion. It is found that, as expected, Arps' decline exponent (used after the end of linear flow) increases with the heterogeneity of the completion. Finally, it is shown that ignoring the heterogeneity of the completion can have a material effect on the long-term forecast. We have assumed planar hydraulic-fracture geometries for our modelling in this work and discuss the implications of this when more-complex fracture geometries are created. This seems to be more common in shale gas reservoirs. We provide an example of low-complexity, planar fracture geometries created near an MFHW and observed on an image log at an offset well.","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"417-425"},"PeriodicalIF":0.0,"publicationDate":"2013-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/149400-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67734916","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}
{"title":"Short-Term Testing Method for Stimulated Wells--Field Examples","authors":"I. Kutasov","doi":"10.2118/168219-PA","DOIUrl":"https://doi.org/10.2118/168219-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"426-432"},"PeriodicalIF":0.0,"publicationDate":"2013-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/168219-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67754013","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}
{"title":"Impact Map for Assessment of New Delineation-Well Locations","authors":"Yevgeniy Zagayevskiy, C. Deutsch","doi":"10.2118/168222-PA","DOIUrl":"https://doi.org/10.2118/168222-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"11 1","pages":"441-462"},"PeriodicalIF":0.0,"publicationDate":"2013-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/168222-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67754065","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}
Incorporating some heat injection along with solvent injection appears to be the most viable option for improving the oil-drainage rate of vapour-assisted petroleum extraction (VAPEX) in extraheavy-oil formations. This study was intended to quantify the maximum possible increase in VAPEX drainage rate that can be obtained by heating the formation to a target temperature. The experimental phase of this study involved conducting VAPEX experiments in a large high-pressure physical model, packed with 250-darcy sand, using propane as the solvent. The physical model was preheated to 40, 50 and 60 C, and propane was injected at the same test temperature but different injection pressures to observe how injection pressure affects oil-drainage rate at elevated temperatures. In the experiments at elevated temperatures, but without increasing the injection pressure, higher rate of oil production was achieved in the early stages of the process. However, a stabilized rate of oil production did not show pronounced improvement caused by a lower solubility of propane in the oil at higher temperatures. Increasing injection pressure along with increasing the test temperatures was successful in accelerating the oil production. The oil used in these experiments was found to become mobile with the increase in temperature even without solvent dissolution. As a result, the total rate of oil production appeared to be controlled by two mechanisms: (1) by solvent dissolution and oil mobilization at the boundaries of the vapour chamber and (2) by pure free-fall gravity drainage beyond the vapour chamber wherever gravity head was sufficient to push the mobile oil toward the production well. The results of this these tests define the upper limit of oil rates achievable with heated solvent injection. They can also be used to assess the applicability of VAPEX to warm reservoirs naturally (e.g., in Venezuela) and reservoirs with mobile oil in place.
{"title":"Effect of Temperature on VAPEX Performance","authors":"P. Haghighat, B. Maini","doi":"10.2118/157799-PA","DOIUrl":"https://doi.org/10.2118/157799-PA","url":null,"abstract":"Incorporating some heat injection along with solvent injection appears to be the most viable option for improving the oil-drainage rate of vapour-assisted petroleum extraction (VAPEX) in extraheavy-oil formations. This study was intended to quantify the maximum possible increase in VAPEX drainage rate that can be obtained by heating the formation to a target temperature. The experimental phase of this study involved conducting VAPEX experiments in a large high-pressure physical model, packed with 250-darcy sand, using propane as the solvent. The physical model was preheated to 40, 50 and 60 C, and propane was injected at the same test temperature but different injection pressures to observe how injection pressure affects oil-drainage rate at elevated temperatures. In the experiments at elevated temperatures, but without increasing the injection pressure, higher rate of oil production was achieved in the early stages of the process. However, a stabilized rate of oil production did not show pronounced improvement caused by a lower solubility of propane in the oil at higher temperatures. Increasing injection pressure along with increasing the test temperatures was successful in accelerating the oil production. The oil used in these experiments was found to become mobile with the increase in temperature even without solvent dissolution. As a result, the total rate of oil production appeared to be controlled by two mechanisms: (1) by solvent dissolution and oil mobilization at the boundaries of the vapour chamber and (2) by pure free-fall gravity drainage beyond the vapour chamber wherever gravity head was sufficient to push the mobile oil toward the production well. The results of this these tests define the upper limit of oil rates achievable with heated solvent injection. They can also be used to assess the applicability of VAPEX to warm reservoirs naturally (e.g., in Venezuela) and reservoirs with mobile oil in place.","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2013-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/157799-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67739203","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}
H. Motahhari, F. Schoeggl, M. Satyro, H. Yarranton
{"title":"Viscosity Prediction for Solvent-Diluted Live Bitumen and Heavy Oil at Temperatures Up to 175-deg-C","authors":"H. Motahhari, F. Schoeggl, M. Satyro, H. Yarranton","doi":"10.2118/149405-PA","DOIUrl":"https://doi.org/10.2118/149405-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"376-390"},"PeriodicalIF":0.0,"publicationDate":"2013-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/149405-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67734968","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}
Thermodynamic steam-trap control, or subcool control, in a typical steam-assisted gravity-drainage (SAGD) production is essential to the stability and longevity of the operation. It is achieved commonly through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing steam from the injector to bypass to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popular in the industry; however it does not prove to hold in many situations. This paper presents a study of the dynamics of SAGD-production control with a resulting algebraic equation that relates subcool, fluid productivity, and wellbore drawdown to the liquid level above a producer. The main conclusions of this study include • There is no minimum subcool value for a pure-gravity-drainage scenario; however, as the wellbore drawdown is considered, there is a minimum subcool value in order to maintain the stability of fluid flow. • For a given productivity, the liquid level increases as subcool increases or as wellbore drawdown decreases. • For each given set of operating parameters, there exists a critical productivity below which SAGD operation would halt. • Before the steam chamber reaches the top of the reservoir, the fluid productivity is limited by the vertical distance between the injector and the producer; the larger the distance, the higher the fluid-production rate can be. A verification of this analysis was conducted by a series of numerical reservoir simulations. Although limited to two dimensions, we expect that this analysis captures the main physics amid the dynamic complexity of SAGD-production control. The resulting algebraic equation can be used for better understanding of the dynamics of subcool control and for determining operation strategies.
{"title":"Subcool, Fluid Productivity, and Liquid Level Above a SAGD Producer","authors":"J. Yuan, Daniel Nugent","doi":"10.2118/157899-PA","DOIUrl":"https://doi.org/10.2118/157899-PA","url":null,"abstract":"Thermodynamic steam-trap control, or subcool control, in a typical steam-assisted gravity-drainage (SAGD) production is essential to the stability and longevity of the operation. It is achieved commonly through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing steam from the injector to bypass to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popular in the industry; however it does not prove to hold in many situations. This paper presents a study of the dynamics of SAGD-production control with a resulting algebraic equation that relates subcool, fluid productivity, and wellbore drawdown to the liquid level above a producer. The main conclusions of this study include • There is no minimum subcool value for a pure-gravity-drainage scenario; however, as the wellbore drawdown is considered, there is a minimum subcool value in order to maintain the stability of fluid flow. • For a given productivity, the liquid level increases as subcool increases or as wellbore drawdown decreases. • For each given set of operating parameters, there exists a critical productivity below which SAGD operation would halt. • Before the steam chamber reaches the top of the reservoir, the fluid productivity is limited by the vertical distance between the injector and the producer; the larger the distance, the higher the fluid-production rate can be. A verification of this analysis was conducted by a series of numerical reservoir simulations. Although limited to two dimensions, we expect that this analysis captures the main physics amid the dynamic complexity of SAGD-production control. The resulting algebraic equation can be used for better understanding of the dynamics of subcool control and for determining operation strategies.","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"360-367"},"PeriodicalIF":0.0,"publicationDate":"2013-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/157899-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67738792","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}
{"title":"Stability of In-Situ-Combustion Process to Stoppage of Air Injection","authors":"A. Turta","doi":"10.2118/158258-PA","DOIUrl":"https://doi.org/10.2118/158258-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"391-398"},"PeriodicalIF":0.0,"publicationDate":"2013-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/158258-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67739867","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}
{"title":"Field Results for Recovering Oil From a Steam-Project Pressure-Isolation Wall","authors":"K. A. Miller, Yi Xiao","doi":"10.2118/158262-PA","DOIUrl":"https://doi.org/10.2118/158262-PA","url":null,"abstract":"","PeriodicalId":15181,"journal":{"name":"Journal of Canadian Petroleum Technology","volume":"52 1","pages":"368-375"},"PeriodicalIF":0.0,"publicationDate":"2013-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/158262-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67739908","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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