Xiaohu Dong, Huiqing Liu, N. Lu, Keliu Wu, Kun Wang, Zhangxin Chen
Dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can effectively delay the occurrence of steam fingering and homogenize the steam injection profile along the horizontal wellbore. In this paper, first, we built a cylindrical wellbore physical model to experimentally study the steam injection profiles of a single-pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along the horizontal wellbore with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semianalytical model for the gas/liquid two-phase flow in the horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated. Experimental results indicated that under the same steam injection condition, an application of dual-pipe well configuration can significantly enhance the oil drainage volume by approximately 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable mass flowing behavior and pressure drops, the wellbore segment close to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along the wellbore. Compared with a pure steam injection process, the coinjection of steam and noncondensable gas (NCG) can improve the effective heating wellbore length by more than 25%. This model is also applied to predict the steam conformance of an actual horizontal well in Liaohe Oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation.
{"title":"Steam Conformance along Horizontal Well with Different Well Configurations of Single Tubing: An Experimental and Numerical Investigation","authors":"Xiaohu Dong, Huiqing Liu, N. Lu, Keliu Wu, Kun Wang, Zhangxin Chen","doi":"10.2118/195799-pa","DOIUrl":"https://doi.org/10.2118/195799-pa","url":null,"abstract":"\u0000 Dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can effectively delay the occurrence of steam fingering and homogenize the steam injection profile along the horizontal wellbore. In this paper, first, we built a cylindrical wellbore physical model to experimentally study the steam injection profiles of a single-pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along the horizontal wellbore with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semianalytical model for the gas/liquid two-phase flow in the horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated. Experimental results indicated that under the same steam injection condition, an application of dual-pipe well configuration can significantly enhance the oil drainage volume by approximately 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable mass flowing behavior and pressure drops, the wellbore segment close to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along the wellbore. Compared with a pure steam injection process, the coinjection of steam and noncondensable gas (NCG) can improve the effective heating wellbore length by more than 25%. This model is also applied to predict the steam conformance of an actual horizontal well in Liaohe Oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/195799-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47205629","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The main objective of this paper is to develop a new approach for constructing the inflow-performance relationships (IPRs) of unconventional reservoirs. The proposed approach focuses on using transient- and pseudosteady-state-flow regimes in developing integrated analytical models for wellhead deliverability and wellbore-pressure decline considering the two wellbore conditions, constant-sandface-flow rate and constant wellbore pressure. The motivation is to reduce the uncertainties in predicting current and future performance of unconventional reservoirs. Three tasks are conducted in this study for achieving the objective of this paper. The first task includes generating the pressure behavior of the reservoirs of interest using a trilinear-flow model. The pressure behavior helps in characterizing the flow regimes that could be developed during the entire life of production and estimating the time interval elapsed by each flow regime. The second task concentrates on developing integrated analytical models for these flow regimes and using these models for predicting the IPR at the end of the time interval of each flow regime. The third task deals with constructing the IPRs at any time and any flow regime, considering different reservoir conditions. For constructing the IPR during bilinear- and linear-flow regimes wherein most of the production is dominated by these two flow regimes, two new functions are developed. The first is the pressure function (P), which represents the change in pressure with time for constant production rate, whereas the second represents the change in flow rate with time for constant wellbore pressure, and is called the flow-rate function (q). The effects of hydraulic-fracture characteristics, reservoir configurations, and the dominant flow pattern—whether it is Darcy or non-Darcy flow—are considered in constructing these IPRs. The observations of this study can be summarized as the following: The IPRs for all transient-flow regimes exhibit linear behavior at a specific production time, even in the cases where non-Darcy flow is the dominant flow pattern and the reservoirs are characterized by high skin factor. However, considering the change in the reservoir and reservoir-fluid properties with time and pressure might cause some deviation from this linear behavior. The IPRs obtained by applying a constant-sandface-flow rate are slightly better than the IPRs obtained by applying constant wellbore pressure. The IPRs of bilinear- and linear-flow regimes are more applicable for unconventional reservoirs than the IPRs of the hydraulic-fracture linear-flow regime and pseudosteady-state-flow regime because the former might not be developed for a long production time and the latter might not be reached. The novel points presented by this study are the following: Introducing an approach for constructing the IPRs during transient-state flow when the wellbore conditions deteriorate continuously Introducing two new functions for
{"title":"Flow-Regime-Based Inflow-Performance Relationships of Unconventional Fractured Reservoirs","authors":"S. Al-Rbeawi","doi":"10.2118/198910-pa","DOIUrl":"https://doi.org/10.2118/198910-pa","url":null,"abstract":"\u0000 The main objective of this paper is to develop a new approach for constructing the inflow-performance relationships (IPRs) of unconventional reservoirs. The proposed approach focuses on using transient- and pseudosteady-state-flow regimes in developing integrated analytical models for wellhead deliverability and wellbore-pressure decline considering the two wellbore conditions, constant-sandface-flow rate and constant wellbore pressure. The motivation is to reduce the uncertainties in predicting current and future performance of unconventional reservoirs.\u0000 Three tasks are conducted in this study for achieving the objective of this paper. The first task includes generating the pressure behavior of the reservoirs of interest using a trilinear-flow model. The pressure behavior helps in characterizing the flow regimes that could be developed during the entire life of production and estimating the time interval elapsed by each flow regime. The second task concentrates on developing integrated analytical models for these flow regimes and using these models for predicting the IPR at the end of the time interval of each flow regime. The third task deals with constructing the IPRs at any time and any flow regime, considering different reservoir conditions. For constructing the IPR during bilinear- and linear-flow regimes wherein most of the production is dominated by these two flow regimes, two new functions are developed. The first is the pressure function (P), which represents the change in pressure with time for constant production rate, whereas the second represents the change in flow rate with time for constant wellbore pressure, and is called the flow-rate function (q). The effects of hydraulic-fracture characteristics, reservoir configurations, and the dominant flow pattern—whether it is Darcy or non-Darcy flow—are considered in constructing these IPRs.\u0000 The observations of this study can be summarized as the following:\u0000 The IPRs for all transient-flow regimes exhibit linear behavior at a specific production time, even in the cases where non-Darcy flow is the dominant flow pattern and the reservoirs are characterized by high skin factor. However, considering the change in the reservoir and reservoir-fluid properties with time and pressure might cause some deviation from this linear behavior. The IPRs obtained by applying a constant-sandface-flow rate are slightly better than the IPRs obtained by applying constant wellbore pressure. The IPRs of bilinear- and linear-flow regimes are more applicable for unconventional reservoirs than the IPRs of the hydraulic-fracture linear-flow regime and pseudosteady-state-flow regime because the former might not be developed for a long production time and the latter might not be reached.\u0000 The novel points presented by this study are the following:\u0000 Introducing an approach for constructing the IPRs during transient-state flow when the wellbore conditions deteriorate continuously Introducing two new functions for ","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/198910-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43843207","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Modeling of multiphase flow represents the cornerstone of oil/gas-production systems. Accurate pressure-drop estimation is crucial in the design and operations of subsea architectures. However, the complexity of the underlying physics governing the transport of mass, momentum, and energy considerably limits the accuracy of the current state-of-the-art models. In this paper, we resort to artificial intelligence to develop a unifying artificial-neural-network (ANN) model encompassing all flow conditions. A genetic algorithm (GA) is used to find the optimal input combination from a broad pool of candidates leading to the best prediction accuracy. To train and validate the model, we used the Stanford multiphase-flow database (SMFD). Comprising 5,659 measurements (1,800 of which are actual field data), the SMFD is the largest of its kind encompassing several published data sets. Eighty percent of the data were used to train the model (4,527 measurements) and the remaining 20% (1,132 measurements) were used for validation. The proposed model was compared with two published models, the Beggs and Brill (1973) model, which is widely used in the oil and gas industry, and the Petalas and Aziz (2000) model (a preeminent mechanistic model). The proposed model was proved to significantly increase the prediction accuracy across all pipe-inclination ranges (up to 88%) and also all observed flow patterns (up to 71%). This is a major contribution with potential benefits to the oil and gas industry, where, because of the limited accuracy of the current models, much conservatism is used in the design of subsea architectures, leading to shortfalls of millions in profits.
{"title":"An Integrated Genetic-Algorithm/Artificial-Neural-Network Approach for Steady-State Modeling of Two-Phase Pressure Drop in Pipes","authors":"Majdi Chaari, Jalel Ben Hmida, A. Seibi, A. Fekih","doi":"10.2118/201191-pa","DOIUrl":"https://doi.org/10.2118/201191-pa","url":null,"abstract":"\u0000 Modeling of multiphase flow represents the cornerstone of oil/gas-production systems. Accurate pressure-drop estimation is crucial in the design and operations of subsea architectures. However, the complexity of the underlying physics governing the transport of mass, momentum, and energy considerably limits the accuracy of the current state-of-the-art models. In this paper, we resort to artificial intelligence to develop a unifying artificial-neural-network (ANN) model encompassing all flow conditions. A genetic algorithm (GA) is used to find the optimal input combination from a broad pool of candidates leading to the best prediction accuracy. To train and validate the model, we used the Stanford multiphase-flow database (SMFD). Comprising 5,659 measurements (1,800 of which are actual field data), the SMFD is the largest of its kind encompassing several published data sets. Eighty percent of the data were used to train the model (4,527 measurements) and the remaining 20% (1,132 measurements) were used for validation. The proposed model was compared with two published models, the Beggs and Brill (1973) model, which is widely used in the oil and gas industry, and the Petalas and Aziz (2000) model (a preeminent mechanistic model). The proposed model was proved to significantly increase the prediction accuracy across all pipe-inclination ranges (up to 88%) and also all observed flow patterns (up to 71%). This is a major contribution with potential benefits to the oil and gas industry, where, because of the limited accuracy of the current models, much conservatism is used in the design of subsea architectures, leading to shortfalls of millions in profits.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201191-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48315000","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. O'Reilly, M. Haghighi, M. Flett, M. Sayyafzadeh
Presented here is an analytical framework to assess the impact of transient-temperature changes in the wellbore on the pressure-transient response of cold-water injection wells. We focus attention on both drawdown and falloff periods in a well after injection. Historically, these pressure data have been used to calculate reservoir properties concerning flood-efficiency and completion properties (formation permeability/thickness, mechanical skin, and fluid-bank mobilities). One key question addressed in this paper is whether the effects of thermal heating of wellbore fluids during a falloff survey can mask the pressure signature of a two-region composite reservoir. The pressure deflections required to detect mobility changes can be relatively small compared with pressure changes induced by temperature effects in the well. The framework proposed in this paper allows for the numerical evaluation of the contribution of each. Previously, researchers have studied multiple bank-transient-injection problems extensively for the case of reservoir flow and pressure drop, even for nonisothermal problems. The effect of temperature changes in the wellbore and overburden are seldom discussed, however. It is demonstrated in this paper that these effects can, in some cases, be substantial, and it is worthwhile to incorporate them into an interpretation model. The results of this paper are useful for planning and designing a pressure-falloff survey to minimize the adverse effect that heating of wellbore fluid by overburden rock can have on the pressure-transient signature. The theory can also be used to analyze existing data affected by the phenomenon. A real-field case study is shown for a cold-water injector where pressure-falloff data have been affected by temperature changes. The analytical model fits the field data closely when parameters are adjusted within reservoir-property-uncertainty ranges.
{"title":"Pressure-Transient Analysis for Cold-Water Injection into a Reservoir Coupled with Wellbore-Transient-Temperature Effects","authors":"D. O'Reilly, M. Haghighi, M. Flett, M. Sayyafzadeh","doi":"10.2118/186306-pa","DOIUrl":"https://doi.org/10.2118/186306-pa","url":null,"abstract":"\u0000 Presented here is an analytical framework to assess the impact of transient-temperature changes in the wellbore on the pressure-transient response of cold-water injection wells. We focus attention on both drawdown and falloff periods in a well after injection. Historically, these pressure data have been used to calculate reservoir properties concerning flood-efficiency and completion properties (formation permeability/thickness, mechanical skin, and fluid-bank mobilities). One key question addressed in this paper is whether the effects of thermal heating of wellbore fluids during a falloff survey can mask the pressure signature of a two-region composite reservoir. The pressure deflections required to detect mobility changes can be relatively small compared with pressure changes induced by temperature effects in the well. The framework proposed in this paper allows for the numerical evaluation of the contribution of each.\u0000 Previously, researchers have studied multiple bank-transient-injection problems extensively for the case of reservoir flow and pressure drop, even for nonisothermal problems. The effect of temperature changes in the wellbore and overburden are seldom discussed, however. It is demonstrated in this paper that these effects can, in some cases, be substantial, and it is worthwhile to incorporate them into an interpretation model.\u0000 The results of this paper are useful for planning and designing a pressure-falloff survey to minimize the adverse effect that heating of wellbore fluid by overburden rock can have on the pressure-transient signature. The theory can also be used to analyze existing data affected by the phenomenon. A real-field case study is shown for a cold-water injector where pressure-falloff data have been affected by temperature changes. The analytical model fits the field data closely when parameters are adjusted within reservoir-property-uncertainty ranges.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/186306-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49461992","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Stavland, Siv Marie Åsen, A. Mebratu, F. Gathier
Polymer flooding is a well-known method for enhanced oil recovery (EOR). Synthetic EOR polymers are susceptible to mechanical degradation. Understanding and mitigating mechanical degradation is a key issue for successful polymer flooding. The main concern of this work is mechanical degradation during choking. Offshore, it is necessary to have control over the injection pressure to each well. During traditional waterflooding, this is achieved by choking the fluid stream by choke valves. In choke valves, there will be sudden change in the flow field, strongly indicating that choke valves will cause mechanical degradation of polymers and thereby reduce the EOR potential of the polymer flood. In this study we investigate mechanical degradation of conventional synthetic EOR polymers. The experiments were performed in commercial chokes and pipes with internal diameters (IDs) from 0.127 to 35 mm, lengths from 13.5 mm to 400 m, and flow rates from 0.3×10−3 to 600 dm3/min, covering several magnitudes of Reynolds number, linear velocities, shear rates, and pressure drop. Using friction factors, f, and Reynolds number, Re, we derived a simple and practical expression for a scaling parameter, τw/η, for degradation of shear thinning polymers in circular tubes at turbulent and laminar flow, where τw=f8ρ⟨v⟩2. At laminar flow, the friction factor is ∝1Re, resulting in a scaling parameter proportional to the velocity-to-radius ratio, ∝⟨v⟩R, equal to the shear rate at the wall and practically independent of viscosity. At turbulent flow, the friction factor is ∝1Reβ, resulting in a scaling parameter at turbulent flow, which is a function of density and viscosity and valid only for high shear rates where the viscosity of shear thinning polymers approaches a fixed value. During the large-scale test, several methods for mitigating or decreasing degradation as a function of pressure drop were identified: decreasing the pressure with several chokes in series, each below a critical pressure drop; decreasing the pressure over a long distance in a linear pressure reducer (LPR); or by choking concentrated polymer solution.
{"title":"Scaling of Mechanical Degradation of EOR Polymers: From Field-Scale Chokes to Capillary Tubes","authors":"A. Stavland, Siv Marie Åsen, A. Mebratu, F. Gathier","doi":"10.2118/202478-pa","DOIUrl":"https://doi.org/10.2118/202478-pa","url":null,"abstract":"\u0000 Polymer flooding is a well-known method for enhanced oil recovery (EOR). Synthetic EOR polymers are susceptible to mechanical degradation. Understanding and mitigating mechanical degradation is a key issue for successful polymer flooding.\u0000 The main concern of this work is mechanical degradation during choking. Offshore, it is necessary to have control over the injection pressure to each well. During traditional waterflooding, this is achieved by choking the fluid stream by choke valves. In choke valves, there will be sudden change in the flow field, strongly indicating that choke valves will cause mechanical degradation of polymers and thereby reduce the EOR potential of the polymer flood.\u0000 In this study we investigate mechanical degradation of conventional synthetic EOR polymers. The experiments were performed in commercial chokes and pipes with internal diameters (IDs) from 0.127 to 35 mm, lengths from 13.5 mm to 400 m, and flow rates from 0.3×10−3 to 600 dm3/min, covering several magnitudes of Reynolds number, linear velocities, shear rates, and pressure drop.\u0000 Using friction factors, f, and Reynolds number, Re, we derived a simple and practical expression for a scaling parameter, τw/η, for degradation of shear thinning polymers in circular tubes at turbulent and laminar flow, where τw=f8ρ⟨v⟩2. At laminar flow, the friction factor is ∝1Re, resulting in a scaling parameter proportional to the velocity-to-radius ratio, ∝⟨v⟩R, equal to the shear rate at the wall and practically independent of viscosity. At turbulent flow, the friction factor is ∝1Reβ, resulting in a scaling parameter at turbulent flow, which is a function of density and viscosity and valid only for high shear rates where the viscosity of shear thinning polymers approaches a fixed value.\u0000 During the large-scale test, several methods for mitigating or decreasing degradation as a function of pressure drop were identified: decreasing the pressure with several chokes in series, each below a critical pressure drop; decreasing the pressure over a long distance in a linear pressure reducer (LPR); or by choking concentrated polymer solution.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/202478-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46222208","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
N. Fleming, Erlend Moldrheim, Espen Teigland, A. Mathisen
As part of an Equinor technical efficiency program that was initiated in 2015 to deliver savings and improvements, bridging particles were removed from the drilling fluids of 15 wells in Oseberg Main and instead loss control material (LCM) was used, as required, in some but not all the wells. These long, horizontal wells were a combination of open hole (OH) and sand screens with and without inflow control together with cased and perforated (C&P) completions, producing from typical Brent Group sandstone formations with permeabilities varying from approximately 10 md to darcy sandstones, and which were depleted by as much as approximately 280 bars. In 2018, an extensive study was performed on these wells to determine the impact on inflow performance of drilling without bridging particles. It was realized that the 15 wells offered a worst-case scenario to study in the field rather than laboratory the significance of formation damage on well productivity. The data set generated offered a unique opportunity to challenge conventional formation damage assertions, especially for long, horizontal wells. The influence of different parameters, including LCMs, lower completion design, loss type, mud penetration depth, dynamic overbalance while drilling, length of production interval, net to gross (NTG) and kh were considered for those wells drilled without bridging particles. One of the surprising findings was that there was no clear evidence that losses were detrimental to the productivity of these long horizontal wells; i.e., it would appear that the Brent reservoir sections, despite being depleted, were more resistant to the influence of formation damage on inflow performance than first thought. Furthermore, for this example bridging particles appear to be of less importance in the avoidance of formation damage but are important in preventing excessive increases in fluid costs due to losses. After a thorough review of all the data obtained from this study, together with the conclusions drawn, it was realized that these had direct implications for Equinor's approach to fluid qualification, and especially coreflooding. The most important conclusion that influenced this change in approach was that the long reservoir sections (approximately 1 km or more) within typical Brent heterogeneous formations appear to tolerate more formation damage without impairing the productivity index (PI). A direct consequence of this was the conclusion that more emphasis should be placed on fluid compatibility, mobility, screen plugging and stability along with particle-size distribution (PSD) design, while the importance of coreflooding to fluid qualification was downgraded for Brent and reservoirs of similar characteristics. This is not to say that coreflooding will not be performed, but rather it will be targeted toward situations where the influence of formation damage on well productivity is more significant; e.g., high-pressure and high-temperature fields where special
{"title":"Systematic Approach to Well Productivity Evaluation To Determine the Significance of Formation Damage for Wells Drilled in a Depleted Reservoir without Bridging Particles: Oseberg Main Case History","authors":"N. Fleming, Erlend Moldrheim, Espen Teigland, A. Mathisen","doi":"10.2118/199266-pa","DOIUrl":"https://doi.org/10.2118/199266-pa","url":null,"abstract":"\u0000 As part of an Equinor technical efficiency program that was initiated in 2015 to deliver savings and improvements, bridging particles were removed from the drilling fluids of 15 wells in Oseberg Main and instead loss control material (LCM) was used, as required, in some but not all the wells. These long, horizontal wells were a combination of open hole (OH) and sand screens with and without inflow control together with cased and perforated (C&P) completions, producing from typical Brent Group sandstone formations with permeabilities varying from approximately 10 md to darcy sandstones, and which were depleted by as much as approximately 280 bars. In 2018, an extensive study was performed on these wells to determine the impact on inflow performance of drilling without bridging particles. It was realized that the 15 wells offered a worst-case scenario to study in the field rather than laboratory the significance of formation damage on well productivity. The data set generated offered a unique opportunity to challenge conventional formation damage assertions, especially for long, horizontal wells.\u0000 The influence of different parameters, including LCMs, lower completion design, loss type, mud penetration depth, dynamic overbalance while drilling, length of production interval, net to gross (NTG) and kh were considered for those wells drilled without bridging particles. One of the surprising findings was that there was no clear evidence that losses were detrimental to the productivity of these long horizontal wells; i.e., it would appear that the Brent reservoir sections, despite being depleted, were more resistant to the influence of formation damage on inflow performance than first thought. Furthermore, for this example bridging particles appear to be of less importance in the avoidance of formation damage but are important in preventing excessive increases in fluid costs due to losses.\u0000 After a thorough review of all the data obtained from this study, together with the conclusions drawn, it was realized that these had direct implications for Equinor's approach to fluid qualification, and especially coreflooding. The most important conclusion that influenced this change in approach was that the long reservoir sections (approximately 1 km or more) within typical Brent heterogeneous formations appear to tolerate more formation damage without impairing the productivity index (PI). A direct consequence of this was the conclusion that more emphasis should be placed on fluid compatibility, mobility, screen plugging and stability along with particle-size distribution (PSD) design, while the importance of coreflooding to fluid qualification was downgraded for Brent and reservoirs of similar characteristics. This is not to say that coreflooding will not be performed, but rather it will be targeted toward situations where the influence of formation damage on well productivity is more significant; e.g., high-pressure and high-temperature fields where special","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199266-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46125318","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. Thiberville, Yanfang Wang, P. Waltrich, W. Williams, S. Kam
Although leak incidents continue, a pipeline remains the most reliable mode of transportation within the oil and gas industry. It becomes even more important today because the projection for new pipelines is expected to increase by 1 billion barrels of oil equivalent (BOE) through 2035. In addition, increasing the number and length of subsea tiebacks faces new challenges in terms of data acquisition, monitoring, analysis, and remedial actions. Passive leak-detection methods commonly used in the industry have been successful with some limitations, in that they often cannot detect small leaks and seeps. In addition to a thorough review of related topics, this study investigates how to create a framework for a smart pigging technique for pipeline leak detection as an active leak-detection method. Numerical modeling of smart pigging for leak detection requires two crucial components: detailed mathematical descriptions for fluid-solid and solid-solid interactions around pig and network modeling for the calculation of pressure and rate along the pipeline using iterative algorithms. The first step of this study is to build a numerical model that shows the motion of a pig along the pipeline with no leak (i.e., at a given injection rate, a pig first accelerates until it reaches its terminal velocity, beyond which the pig moves at a constant velocity). The second step is to construct a network model that consists of two pipeline segments (one upstream and the other downstream of the leak location) through which the pig travels and at the junction of which fluid leak occurs. By putting these multiple mechanisms together and using resulting pressure signatures, this study presents a new method to predict the location and size of a leak in the pipeline.
{"title":"Modeling of Smart Pigging for Pipeline Leak Detection","authors":"C. Thiberville, Yanfang Wang, P. Waltrich, W. Williams, S. Kam","doi":"10.2118/198648-pa","DOIUrl":"https://doi.org/10.2118/198648-pa","url":null,"abstract":"\u0000 Although leak incidents continue, a pipeline remains the most reliable mode of transportation within the oil and gas industry. It becomes even more important today because the projection for new pipelines is expected to increase by 1 billion barrels of oil equivalent (BOE) through 2035. In addition, increasing the number and length of subsea tiebacks faces new challenges in terms of data acquisition, monitoring, analysis, and remedial actions. Passive leak-detection methods commonly used in the industry have been successful with some limitations, in that they often cannot detect small leaks and seeps. In addition to a thorough review of related topics, this study investigates how to create a framework for a smart pigging technique for pipeline leak detection as an active leak-detection method.\u0000 Numerical modeling of smart pigging for leak detection requires two crucial components: detailed mathematical descriptions for fluid-solid and solid-solid interactions around pig and network modeling for the calculation of pressure and rate along the pipeline using iterative algorithms. The first step of this study is to build a numerical model that shows the motion of a pig along the pipeline with no leak (i.e., at a given injection rate, a pig first accelerates until it reaches its terminal velocity, beyond which the pig moves at a constant velocity). The second step is to construct a network model that consists of two pipeline segments (one upstream and the other downstream of the leak location) through which the pig travels and at the junction of which fluid leak occurs. By putting these multiple mechanisms together and using resulting pressure signatures, this study presents a new method to predict the location and size of a leak in the pipeline.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/198648-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44313315","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Xiaodong Han, L. Zhong, Yigang Liu, Jian Zou, Qiuxia Wang
{"title":"Study and Pilot Test of Multiple Thermal-Fluid Stimulation in Offshore Nanpu Oilfield","authors":"Xiaodong Han, L. Zhong, Yigang Liu, Jian Zou, Qiuxia Wang","doi":"10.2118/201241-pa","DOIUrl":"https://doi.org/10.2118/201241-pa","url":null,"abstract":"","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201241-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42515952","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. D. M. Pallares, Chenxi Wang, M. Haftani, A. Nouri
Wire-wrapped screens (WWSs) are one of the most-commonly used devices by steam-assisted gravity drainage (SAGD) operators because of the capacity to control plugging and improve flow performance. WWSs offer high open-to-flow area (OFA) (6 to 18%) that allow a high release of fines, hence, less pore plugging and accumulation at the near-screen zone. Over the years, several criteria have been proposed for the selection of aperture sizes on the basis of different industrial contexts and laboratory experiments. Generally, existing aperture-sizing recommendations include only a single point of the particle-size distribution (PSD). Operators and academics rely on sand-control testing to evaluate the performance of sand-control devices (SCDs). Scaled laboratory testing provides a straightforward tool to understand the role of flow rate, flowing phases, fluid properties, stresses, and screen specifications on sand retention and flow impairment. This study employs large-scale prepacked sand-retention tests (SRTs) to experimentally assess the performance of WWSs under variable single-phase and multiphase conditions. The experimental results and parametric trends are used to formulate a set of empirical equations that describe the response of the WWS. Several PSD classes with various fines content and particle size are tested to evaluate a broad range of PSDs. Operational procedures include the coinjection of gas, brine, and oil to emulate aggressive conditions during steam-breakthrough events. The experimental investigation leads to the formulation of predictive correlations. Additional PSDs were prepared to verify the adequacy of the proposed equations. The results show that sanding modes are both flow-rate and flowing-phase dependent. Moreover, the severity or intensity of producing sand is greatly influenced by the ratio of grain size to aperture size and the ability to form stable bridges. During gas and multiphase flow, a dramatic amount of sanding was observed for wider apertures caused by high multiphase flow velocities. However, liquid stages displayed less-intense transient behaviors. Remarkably, WWSs rendered an excellent flow performance even for low-quality sands and narrow apertures. Although further and more complete testing is required, empirical correlations showed good agreement with experimental results.
{"title":"Experimental Correlations for the Performance and Aperture Selection of Wire-Wrapped Screens in Steam-Assisted Gravity Drainage Production Wells","authors":"J. D. M. Pallares, Chenxi Wang, M. Haftani, A. Nouri","doi":"10.2118/200473-pa","DOIUrl":"https://doi.org/10.2118/200473-pa","url":null,"abstract":"\u0000 Wire-wrapped screens (WWSs) are one of the most-commonly used devices by steam-assisted gravity drainage (SAGD) operators because of the capacity to control plugging and improve flow performance. WWSs offer high open-to-flow area (OFA) (6 to 18%) that allow a high release of fines, hence, less pore plugging and accumulation at the near-screen zone. Over the years, several criteria have been proposed for the selection of aperture sizes on the basis of different industrial contexts and laboratory experiments. Generally, existing aperture-sizing recommendations include only a single point of the particle-size distribution (PSD). Operators and academics rely on sand-control testing to evaluate the performance of sand-control devices (SCDs). Scaled laboratory testing provides a straightforward tool to understand the role of flow rate, flowing phases, fluid properties, stresses, and screen specifications on sand retention and flow impairment.\u0000 This study employs large-scale prepacked sand-retention tests (SRTs) to experimentally assess the performance of WWSs under variable single-phase and multiphase conditions. The experimental results and parametric trends are used to formulate a set of empirical equations that describe the response of the WWS. Several PSD classes with various fines content and particle size are tested to evaluate a broad range of PSDs. Operational procedures include the coinjection of gas, brine, and oil to emulate aggressive conditions during steam-breakthrough events.\u0000 The experimental investigation leads to the formulation of predictive correlations. Additional PSDs were prepared to verify the adequacy of the proposed equations. The results show that sanding modes are both flow-rate and flowing-phase dependent. Moreover, the severity or intensity of producing sand is greatly influenced by the ratio of grain size to aperture size and the ability to form stable bridges. During gas and multiphase flow, a dramatic amount of sanding was observed for wider apertures caused by high multiphase flow velocities. However, liquid stages displayed less-intense transient behaviors. Remarkably, WWSs rendered an excellent flow performance even for low-quality sands and narrow apertures. Although further and more complete testing is required, empirical correlations showed good agreement with experimental results.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200473-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42729152","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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