Fractured reservoirs, including unconventional fields, are important in global energy supply, particularly for carbonate source rocks. Fractures can influence subsurface fluid flow and the stress state of a reservoir. The knowledge about the existence of fractures, their spatial distributions, and orientations can help us optimize well productivity and reservoir performance. Seismic detection of subsurface fractures provides important measurements to remotely image field-scale fractures. In developing such technology, forward modeling of the seismic response from fractures in the reservoir provides an important alternate tool for imaging subsurface fractures. In this paper, we implement a seismic modeling algorithm which can simulate 3D wave propagation in an arbitrary background media with imbedded fractures. During modeling, the fractures are added to the background medium by linear slip theory. Examples demonstrated the impacts of fractures on the wave propagation patterns for both PP and PS waves. We also investigate the amplitude versus offset (AVO) effects caused by fractures in a layer media and lay out potential applications of forward modeling in the inversion of fracture parameters and the estimation of fluid contents.
{"title":"Seismic Wave Simulation in Fractured Media","authors":"H. Zhang, Jiaxuan Li, A. Ali","doi":"10.2118/204845-ms","DOIUrl":"https://doi.org/10.2118/204845-ms","url":null,"abstract":"\u0000 Fractured reservoirs, including unconventional fields, are important in global energy supply, particularly for carbonate source rocks. Fractures can influence subsurface fluid flow and the stress state of a reservoir. The knowledge about the existence of fractures, their spatial distributions, and orientations can help us optimize well productivity and reservoir performance. Seismic detection of subsurface fractures provides important measurements to remotely image field-scale fractures. In developing such technology, forward modeling of the seismic response from fractures in the reservoir provides an important alternate tool for imaging subsurface fractures. In this paper, we implement a seismic modeling algorithm which can simulate 3D wave propagation in an arbitrary background media with imbedded fractures. During modeling, the fractures are added to the background medium by linear slip theory. Examples demonstrated the impacts of fractures on the wave propagation patterns for both PP and PS waves. We also investigate the amplitude versus offset (AVO) effects caused by fractures in a layer media and lay out potential applications of forward modeling in the inversion of fracture parameters and the estimation of fluid contents.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74366923","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}
It is still a challenge to build a numerical static reservoir model, based on limited data, to characterize reservoir architecture that corresponds to the geological concept models. The numerical static reef reservoir model has been evolving from the oversimplified tank-like models, simple multi-layer models to the complex multi-layer models that are more realistic representations of complex reservoirs. A simple multi-layer model for the reef reservoir with proportional layering scheme was applied in the CO2 Storage Development Plan (SDP) study, as the most-likely scenario to match the geological complexity. Model refinement can be conducted during CO2 injection phase with Measurement, Monitoring and Verification (MMV) technologies for CO2 plume distribution tracking. The selected reservoir is a Middle to Late Miocene carbonate reef complex, with three phases of reef growth: 1) basal transgressive phase, 2) lower buildup phase, and 3) upper buildup phase. Three chronostratigraphic surfaces were identified on 3D seismic reflection data as the zone boundaries, which were then divided into sub-zones and layers. Four layering methods were compared, which are ‘proportional’, ’follow top’, ‘follow base’ and ‘follow top with reference surface’. The proportional layering method was selected for the base case of the 3D static reservoir model and the others were used in the uncertainty analysis. Based on the results of uncertainty and risk assessment, a risk mitigation for CO2 injection operation were modeled and three CO2 injection well locations were optimized. The reservoir architecture model would be updated and refined by the difference between the modeled CO2 plume patterns and The MMV results in the future.
{"title":"Reservoir Architecture Modeling at Sub-Seismic Scale for a Depleted Carbonate Reef Reservoir for CO2 Storage in Sarawak Basin, Offshore Malaysia","authors":"Z. Cai, A. Widyanita, P. Chidambaram, E. A. Jones","doi":"10.2118/204689-ms","DOIUrl":"https://doi.org/10.2118/204689-ms","url":null,"abstract":"\u0000 It is still a challenge to build a numerical static reservoir model, based on limited data, to characterize reservoir architecture that corresponds to the geological concept models. The numerical static reef reservoir model has been evolving from the oversimplified tank-like models, simple multi-layer models to the complex multi-layer models that are more realistic representations of complex reservoirs. A simple multi-layer model for the reef reservoir with proportional layering scheme was applied in the CO2 Storage Development Plan (SDP) study, as the most-likely scenario to match the geological complexity. Model refinement can be conducted during CO2 injection phase with Measurement, Monitoring and Verification (MMV) technologies for CO2 plume distribution tracking.\u0000 The selected reservoir is a Middle to Late Miocene carbonate reef complex, with three phases of reef growth: 1) basal transgressive phase, 2) lower buildup phase, and 3) upper buildup phase. Three chronostratigraphic surfaces were identified on 3D seismic reflection data as the zone boundaries, which were then divided into sub-zones and layers. Four layering methods were compared, which are ‘proportional’, ’follow top’, ‘follow base’ and ‘follow top with reference surface’. The proportional layering method was selected for the base case of the 3D static reservoir model and the others were used in the uncertainty analysis. Based on the results of uncertainty and risk assessment, a risk mitigation for CO2 injection operation were modeled and three CO2 injection well locations were optimized. The reservoir architecture model would be updated and refined by the difference between the modeled CO2 plume patterns and The MMV results in the future.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77732459","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}
Reservoir fluid properties at bubble points play a vital role in reservoir and production engineering computations. Ideally, the bubble point physical properties of crude oils are obtained experimentally. On some occasions, these properties are neither available nor reliable; then, empirically derived correlations or artificial neural network models are used to predict the properties. This study presents a new single multi-input multi-output artificial neural network model for predicting the six bubble point physical properties of crude oils, namely, oil pressure, oil formation volume factor, isobaric thermal expansion of oil, isothermal compressibility of oil, oil density, and oil viscosity. A large database comprising conventional PVT laboratory reports was collected from major producing reservoirs in the Middle East. The model input is constrained mathematically to be consistent with the limiting values of the physical properties. The new model is represented in mathematical format to be easily used as empirical correlations. The new neural network model is compared with popular fluid property correlations. The results show that the developed model outperforms the fluid property correlations in terms of the average absolute percent relative error.
{"title":"A Single Artificial Neural Network Model Predicts Bubble Point Physical Properties of Crude Oils","authors":"M. Al-Marhoun","doi":"10.2118/204648-ms","DOIUrl":"https://doi.org/10.2118/204648-ms","url":null,"abstract":"\u0000 Reservoir fluid properties at bubble points play a vital role in reservoir and production engineering computations. Ideally, the bubble point physical properties of crude oils are obtained experimentally. On some occasions, these properties are neither available nor reliable; then, empirically derived correlations or artificial neural network models are used to predict the properties.\u0000 This study presents a new single multi-input multi-output artificial neural network model for predicting the six bubble point physical properties of crude oils, namely, oil pressure, oil formation volume factor, isobaric thermal expansion of oil, isothermal compressibility of oil, oil density, and oil viscosity. A large database comprising conventional PVT laboratory reports was collected from major producing reservoirs in the Middle East. The model input is constrained mathematically to be consistent with the limiting values of the physical properties. The new model is represented in mathematical format to be easily used as empirical correlations.\u0000 The new neural network model is compared with popular fluid property correlations. The results show that the developed model outperforms the fluid property correlations in terms of the average absolute percent relative error.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77903434","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Othman, M. Aljawad, M. Kamal, M. Mahmoud, S. Patil
Due to the scarcity and high cost of freshwater, especially in the Gulf region, utilization of seawater as a fracturing fluid gained noticeable interest. However, seawater contains high total dissolved solids (TDS) that may damage the formation and degrade the performance of the fracturing fluids. Numerous additives are required to reduce the damaging effect and improve the viscosity resulting in an expensive and non-eco-friendly fracturing fluid system. Chelating agents, which are environmentally benign, are proposed in this study as the replacement of many additives for seawater fracturing fluids. This study focuses on optimizing chelating agents to achieve high viscosity employing the standard industry rheometers. Carboxymethyl Hydroxypropyl Guar Gum (CMHPG) polymer, which is effective in hydraulic fracturing, was used in this research with 0.5 and 1.0 wt% in deionized water (DW) as well as seawater (SW). It was first tested as a standalone additive at different conditions to provide a benchmark then combined with different concentrations, and pH level chelating agents. In this study the hydration test was conducted through different conditions. It was observed that CMHPG, when tested as a standalone additive, provided slightly higher viscosity in SW compared to DW. Also, increasing polymer concentration from 0.5 to 1.0 wt% provided three folds of viscosity. The viscosity did not show time dependence behavior at room temperature for the aforementioned experiments where all hydration tests were run at 511 1/s shear rate. Temperature, however, had a significant impact on both viscosity magnitude and behavior. At 70 °C, the fluid viscosity increased with time where low viscosity was achieved early on but kept increasing with shearing time. Similarly, high pH chelating agents provided time dependant viscosity behavior when mixed with CMHPG. This behavior is important as low viscosity is favorable during pumping but high viscosity when the fluids hit the formation. The study investigates the possibility of utilizing chelating agents with seawater to replace numerous additives. It acts as a crosslinker at early shearing times, where a gradual increase in viscosity was observed and a breaker in the reservoir harsh conditions. It also captures the divalent ions that are common in seawater, which replaces the need for scale inhibitors. The viscosity increase behavior can be controlled by adjusting the pH level, which could be desirable during operations.
{"title":"Optimizing Seawater Based Fracture Fluids Rheology Utilizing Chelating Agents","authors":"A. Othman, M. Aljawad, M. Kamal, M. Mahmoud, S. Patil","doi":"10.2118/204684-ms","DOIUrl":"https://doi.org/10.2118/204684-ms","url":null,"abstract":"\u0000 Due to the scarcity and high cost of freshwater, especially in the Gulf region, utilization of seawater as a fracturing fluid gained noticeable interest. However, seawater contains high total dissolved solids (TDS) that may damage the formation and degrade the performance of the fracturing fluids. Numerous additives are required to reduce the damaging effect and improve the viscosity resulting in an expensive and non-eco-friendly fracturing fluid system. Chelating agents, which are environmentally benign, are proposed in this study as the replacement of many additives for seawater fracturing fluids.\u0000 This study focuses on optimizing chelating agents to achieve high viscosity employing the standard industry rheometers. Carboxymethyl Hydroxypropyl Guar Gum (CMHPG) polymer, which is effective in hydraulic fracturing, was used in this research with 0.5 and 1.0 wt% in deionized water (DW) as well as seawater (SW). It was first tested as a standalone additive at different conditions to provide a benchmark then combined with different concentrations, and pH level chelating agents. In this study the hydration test was conducted through different conditions.\u0000 It was observed that CMHPG, when tested as a standalone additive, provided slightly higher viscosity in SW compared to DW. Also, increasing polymer concentration from 0.5 to 1.0 wt% provided three folds of viscosity. The viscosity did not show time dependence behavior at room temperature for the aforementioned experiments where all hydration tests were run at 511 1/s shear rate. Temperature, however, had a significant impact on both viscosity magnitude and behavior. At 70 °C, the fluid viscosity increased with time where low viscosity was achieved early on but kept increasing with shearing time. Similarly, high pH chelating agents provided time dependant viscosity behavior when mixed with CMHPG. This behavior is important as low viscosity is favorable during pumping but high viscosity when the fluids hit the formation.\u0000 The study investigates the possibility of utilizing chelating agents with seawater to replace numerous additives. It acts as a crosslinker at early shearing times, where a gradual increase in viscosity was observed and a breaker in the reservoir harsh conditions. It also captures the divalent ions that are common in seawater, which replaces the need for scale inhibitors. The viscosity increase behavior can be controlled by adjusting the pH level, which could be desirable during operations.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80975673","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}
Klemens Katterbauer, Abdallah Al Shehri, A. Marsala
Waterfront movement in fractured carbonate reservoirs occurs in micro-fractures, corridors and interconnected fracture channels (above 5 mm in size) that penetrate the carbonate reservoir structure. Determining the fracture channels and the waterfront movements within the flow corridors is critical to optimize sweep efficiency and increase hydrocarbon recovery. In this work, we present a new deep reinforcement learning algorithm for the optimization of sensor placement for waterfront movement detection in carbonate fracture channels. The framework deploys deep reinforcement learning approach for optimizing the location of sensors within the fracture channels to enhance waterfront tracking. The approach first deploys the deep learning algorithm for determining the water saturation levels within the fractures based on the sensor data.. Then, it updates the sensor locations in order to optimize the reservoir coverage. We test the deep reinforcement learning framework on a synthetic fracture carbonate reservoir box model exhibiting a complex fracture system. Fracture Robots (FracBots, around 5 mm in size) technology will be used to sense key reservoir parameters (e.g., temperature, pressure, pH and other chemical parameters). The technology is comprised of a wireless micro-sensor network for mapping and monitoring fractures in conventional and unconventional reservoirs [1]. It establish a wireless network connectivity via magnetic induction (MI)-based communication since it exhibits highly reliable and constant channel conditions with sufficient communication range in the oil reservoir environment. The system architecture of the FracBots network has two layers: FracBot nodes layer and a base station layer. A number of subsurface FracBot sensors are injected in the formation fractures that record data affected by changes in water saturation. The sensor placement can be adapted in the reservoir formation to improve sensor data quality, as well as better track the penetrating waterfronts. They will move with the injected fluids and distribute themselves in the fractures where they start sensing the surrounding environment's conditions and communicate data, including their location coordinates, among each other to finally send the information in multi-hop fashion to the base station installed inside the wellbore. The base station layer consists of a large antenna connected to an aboveground gateway. The data collected from the FracBots network will be transmitted to the control room via aboveground gateway for further processing. The results exhibited resilient performance in updating the sensor placement to capture the penetrating waterfronts in the formation. The framework performs well particularly when the distance between the sensors is sufficient to avoid measurement interference. The framework demonstrates the criticality of adequate sensor placement in the reservoir formation for accurate waterfront tracking. Also, it shows that itis a viabl
{"title":"A Novel Deep Reinforcement Sensor Placement Method for Waterfront Tracking","authors":"Klemens Katterbauer, Abdallah Al Shehri, A. Marsala","doi":"10.2118/204851-ms","DOIUrl":"https://doi.org/10.2118/204851-ms","url":null,"abstract":"\u0000 Waterfront movement in fractured carbonate reservoirs occurs in micro-fractures, corridors and interconnected fracture channels (above 5 mm in size) that penetrate the carbonate reservoir structure. Determining the fracture channels and the waterfront movements within the flow corridors is critical to optimize sweep efficiency and increase hydrocarbon recovery.\u0000 In this work, we present a new deep reinforcement learning algorithm for the optimization of sensor placement for waterfront movement detection in carbonate fracture channels. The framework deploys deep reinforcement learning approach for optimizing the location of sensors within the fracture channels to enhance waterfront tracking. The approach first deploys the deep learning algorithm for determining the water saturation levels within the fractures based on the sensor data.. Then, it updates the sensor locations in order to optimize the reservoir coverage.\u0000 We test the deep reinforcement learning framework on a synthetic fracture carbonate reservoir box model exhibiting a complex fracture system. Fracture Robots (FracBots, around 5 mm in size) technology will be used to sense key reservoir parameters (e.g., temperature, pressure, pH and other chemical parameters). The technology is comprised of a wireless micro-sensor network for mapping and monitoring fractures in conventional and unconventional reservoirs [1]. It establish a wireless network connectivity via magnetic induction (MI)-based communication since it exhibits highly reliable and constant channel conditions with sufficient communication range in the oil reservoir environment. The system architecture of the FracBots network has two layers: FracBot nodes layer and a base station layer. A number of subsurface FracBot sensors are injected in the formation fractures that record data affected by changes in water saturation. The sensor placement can be adapted in the reservoir formation to improve sensor data quality, as well as better track the penetrating waterfronts. They will move with the injected fluids and distribute themselves in the fractures where they start sensing the surrounding environment's conditions and communicate data, including their location coordinates, among each other to finally send the information in multi-hop fashion to the base station installed inside the wellbore. The base station layer consists of a large antenna connected to an aboveground gateway. The data collected from the FracBots network will be transmitted to the control room via aboveground gateway for further processing.\u0000 The results exhibited resilient performance in updating the sensor placement to capture the penetrating waterfronts in the formation. The framework performs well particularly when the distance between the sensors is sufficient to avoid measurement interference. The framework demonstrates the criticality of adequate sensor placement in the reservoir formation for accurate waterfront tracking. Also, it shows that itis a viabl","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85909761","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 single monitoring well configuration is a favorable option for microseismic monitoring considering risk and cost. It has commonly been used in various industries for decades. When using a single monitoring well, we rely among other things on the waveforms’ polarization information to accurately locate detected microseismic events. Additionally, using a large array aperture reduces hypocenter's uncertainty. Instead of solely relying on 3C geophones to achieve such objectives, we propose to combine 3C sensors and distributed acoustic sensing (DAS) equipment. It is quite a cost-effective solution, and it enables us to leverage each system's strength while minimizing their respective limitations when considered individually. We present the technical feasibility of such a hybrid microseismic monitoring system using data acquired during a monitoring campaign performed in the Montney formation, Canada. In this dataset, the optic fiber (DAS) is located in the wireline cable used to deploy the 3C geophones; themselves located at the bottom of the DAS wireline cable. Though different acquisition systems are employed for the geophone array and the DAS array, both datasets are GPS time stamped so that data can be processed properly. We scan the DAS data using an STA/LTA event detection, and we integrate with the 3C geophone data. We find the microseismic waveform in both the DAS and the geophone sections and confirm the arrival times are consistent between DAS and geophones. Once datasets are merged, we determine hypocenters using a migration-based event location method for such hybrid array. The uncertainty associated with the event located using the hybrid DAS – geophone array is smaller than for any of the systems looked at independently thanks to the increased array aperture. This case study demonstrates the viability and efficiency of the next generation of a single well acquisition system for microseismic monitoring. Not only does it lower event location uncertainty, but it is also more reliable and cost-effective than the conventional approaches.
{"title":"Single Well Microseismic Monitoring Leveraging Hybrid Cable Combining Both DAS and Traditional Geophones","authors":"Takashi Mizuno, Joël Le Calvez, T. Cuny, Yu Chen","doi":"10.2118/204613-ms","DOIUrl":"https://doi.org/10.2118/204613-ms","url":null,"abstract":"\u0000 The single monitoring well configuration is a favorable option for microseismic monitoring considering risk and cost. It has commonly been used in various industries for decades. When using a single monitoring well, we rely among other things on the waveforms’ polarization information to accurately locate detected microseismic events. Additionally, using a large array aperture reduces hypocenter's uncertainty.\u0000 Instead of solely relying on 3C geophones to achieve such objectives, we propose to combine 3C sensors and distributed acoustic sensing (DAS) equipment. It is quite a cost-effective solution, and it enables us to leverage each system's strength while minimizing their respective limitations when considered individually. We present the technical feasibility of such a hybrid microseismic monitoring system using data acquired during a monitoring campaign performed in the Montney formation, Canada. In this dataset, the optic fiber (DAS) is located in the wireline cable used to deploy the 3C geophones; themselves located at the bottom of the DAS wireline cable. Though different acquisition systems are employed for the geophone array and the DAS array, both datasets are GPS time stamped so that data can be processed properly. We scan the DAS data using an STA/LTA event detection, and we integrate with the 3C geophone data. We find the microseismic waveform in both the DAS and the geophone sections and confirm the arrival times are consistent between DAS and geophones. Once datasets are merged, we determine hypocenters using a migration-based event location method for such hybrid array. The uncertainty associated with the event located using the hybrid DAS – geophone array is smaller than for any of the systems looked at independently thanks to the increased array aperture. This case study demonstrates the viability and efficiency of the next generation of a single well acquisition system for microseismic monitoring. Not only does it lower event location uncertainty, but it is also more reliable and cost-effective than the conventional approaches.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78057412","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}
Steam-assisted gravity drainage (SAGD) technology, although a relatively new oil recovery method, has already proved its value in economic development of heavy-oil sands in Western Canada. The SAGD process requires a lifetime monitoring of steam chamber growth to optimize reservoir development, improve oil recovery, and minimize environmental impact. Operators have widely used pulsed neutron well logs to monitor their life cycles of oil sand reservoirs. Time-lapse pulsed neutron logs acquired in observation wells enable operators to effectively track the growth of the steam chamber and identify the changes of formation fluid saturations. We present high-temperature pulsed neutron logging technology and an algorithm to quantify steam, heavy oil and water saturations in SAGD wells. One of the major challenges in well logging operation is to withstand the thermal shock from the steam chamber. Reservoir temperature often varies abruptly, by as much as 250 degrees C in a very short interval, so the logging tool must be stable in drastic temperature variations. Well logging conditions such as a steam-filled wellbore, extra completion hardware and bad cement quality are challenging factors as well. Furthermore, formation fluid saturation analysis in Canadian oil sands is typically complex because the formation water salinity is relatively fresh but varies, clay properties are not homogeneous, and SAGD operations create conditions in which three-phase fluids coexist in the formation. These environmental conditions make it difficult to rely only on commonly used thermal neutron capture cross-section measurements (formation sigma). In this paper, case study examples present the above-mentioned challenges and solutions to identify the multi-component formation fluids. The multi-detector pulsed neutron well logging instrument has been modified with a custom-designed heat flask to handle the extreme temperature variations in the SAGD environment. This heat-flask equipped instrument ensures a stable data acquisition in the presence of rapid and extreme temperature variation and enables a prolonged and time-efficient operation through effective heat management. For saturation analysis, we demonstrate an advanced algorithm to quantify three fluid components using a combination of gamma ray ratio and carbon/oxygen (C/O) measurements.
{"title":"Time-Lapse Pulsed Neutron Well Logging in Oil Sands for Monitoring Steam Chamber Development","authors":"Yonghwee Kim, A. Kotov, D. Chace","doi":"10.2118/204576-ms","DOIUrl":"https://doi.org/10.2118/204576-ms","url":null,"abstract":"\u0000 Steam-assisted gravity drainage (SAGD) technology, although a relatively new oil recovery method, has already proved its value in economic development of heavy-oil sands in Western Canada. The SAGD process requires a lifetime monitoring of steam chamber growth to optimize reservoir development, improve oil recovery, and minimize environmental impact. Operators have widely used pulsed neutron well logs to monitor their life cycles of oil sand reservoirs. Time-lapse pulsed neutron logs acquired in observation wells enable operators to effectively track the growth of the steam chamber and identify the changes of formation fluid saturations. We present high-temperature pulsed neutron logging technology and an algorithm to quantify steam, heavy oil and water saturations in SAGD wells.\u0000 One of the major challenges in well logging operation is to withstand the thermal shock from the steam chamber. Reservoir temperature often varies abruptly, by as much as 250 degrees C in a very short interval, so the logging tool must be stable in drastic temperature variations. Well logging conditions such as a steam-filled wellbore, extra completion hardware and bad cement quality are challenging factors as well. Furthermore, formation fluid saturation analysis in Canadian oil sands is typically complex because the formation water salinity is relatively fresh but varies, clay properties are not homogeneous, and SAGD operations create conditions in which three-phase fluids coexist in the formation. These environmental conditions make it difficult to rely only on commonly used thermal neutron capture cross-section measurements (formation sigma).\u0000 In this paper, case study examples present the above-mentioned challenges and solutions to identify the multi-component formation fluids. The multi-detector pulsed neutron well logging instrument has been modified with a custom-designed heat flask to handle the extreme temperature variations in the SAGD environment. This heat-flask equipped instrument ensures a stable data acquisition in the presence of rapid and extreme temperature variation and enables a prolonged and time-efficient operation through effective heat management. For saturation analysis, we demonstrate an advanced algorithm to quantify three fluid components using a combination of gamma ray ratio and carbon/oxygen (C/O) measurements.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87934273","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}
P. Soupios, A. Stampolidis, M. Fedi, S. Kaka, K. Al-Ramadan, G. Tsokas, R. Pašteka
The study area is a part of Dammam Dome that is situated at King Fahd University of Petroleum & Minerals (KFUPM) campus, Dhahran, Kingdom of Saudi Arabia. The gravity survey was conducted as a pilot case study to explore part of Dammam Dome in greater detail. Gravity data were collected solely during night hours due to low noise levels. A significant part of the survey was conducted during the summer holiday period, , when there was no student are on campus. A total of 235 gravity measurements were made using a Scintrex CG5 gravitometer, while a Trimble R10+ differential GPS (DGPS) was used to measure the stations’ location and elevation with the highest accuracy. All gravity data were reduced using several algorithms, and their outcomes were cross-compared. The Complete Bouguer anomaly map for the campus was then generated. Several enhancement filters including edged detection and shallow to deeper source separation were applied. Data were inverted, and 2.5D and 3D models were created to image the subsurface conditions. The main purpose of this study is to better understand the subsurface geology, tectonic settings of the Dammam Dome by applying the high-resolution gravity method before carrying out any comprehensive geophysical (seismic) 3D survey.
{"title":"Gravity Survey of King Fahd University of Petroleum and Minerals Dammam Dome, Saudi Arabia","authors":"P. Soupios, A. Stampolidis, M. Fedi, S. Kaka, K. Al-Ramadan, G. Tsokas, R. Pašteka","doi":"10.2118/204564-ms","DOIUrl":"https://doi.org/10.2118/204564-ms","url":null,"abstract":"\u0000 The study area is a part of Dammam Dome that is situated at King Fahd University of Petroleum & Minerals (KFUPM) campus, Dhahran, Kingdom of Saudi Arabia. The gravity survey was conducted as a pilot case study to explore part of Dammam Dome in greater detail.\u0000 Gravity data were collected solely during night hours due to low noise levels. A significant part of the survey was conducted during the summer holiday period, , when there was no student are on campus. A total of 235 gravity measurements were made using a Scintrex CG5 gravitometer, while a Trimble R10+ differential GPS (DGPS) was used to measure the stations’ location and elevation with the highest accuracy.\u0000 All gravity data were reduced using several algorithms, and their outcomes were cross-compared. The Complete Bouguer anomaly map for the campus was then generated. Several enhancement filters including edged detection and shallow to deeper source separation were applied. Data were inverted, and 2.5D and 3D models were created to image the subsurface conditions.\u0000 The main purpose of this study is to better understand the subsurface geology, tectonic settings of the Dammam Dome by applying the high-resolution gravity method before carrying out any comprehensive geophysical (seismic) 3D survey.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86779604","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}
Miguel Gonzalez, Tim Thiel, C. Gooneratne, Robert W. Adams, C. Powell, A. Magana-Mora, J. Ramasamy, M. Deffenbaugh
During drilling operations, measurements of drilling fluid/mud viscosity and density provide key information to ensure safe operations (e.g., maintain wellbore integrity) and improve the rate of penetration (e.g., maintain proper hole cleaning). Nowadays, these measurements are still performed manually by using a calibrated funnel viscometer and a weight balance, as stipulated by current American Petroleum Institute (API) standards. In this study, we introduce an automated viscosity/density measurement system based on an electromechanical tuning fork resonator. The system allows for continuous measurements as fast as several times per second in a compact footprint, allowing it to be deployed in tanks or pipelines and/or gathering data from multiple sensors in the mud circulation system. The streams of data produced were broadcasted to a nearby computer allowing for live monitoring of the viscosity and density. The results obtained by the in-tank system in five wells were in good agreement with the standard reference measurements from the mud logs. Here, we describe the development and testing of the tool as well as general guidelines for integration into a rig edge-computing system for real-time analytics and detection of operational problems and drilling automation.
{"title":"A New Viscosity and Density Sensing Platform for Drilling Automation","authors":"Miguel Gonzalez, Tim Thiel, C. Gooneratne, Robert W. Adams, C. Powell, A. Magana-Mora, J. Ramasamy, M. Deffenbaugh","doi":"10.2118/204584-ms","DOIUrl":"https://doi.org/10.2118/204584-ms","url":null,"abstract":"\u0000 During drilling operations, measurements of drilling fluid/mud viscosity and density provide key information to ensure safe operations (e.g., maintain wellbore integrity) and improve the rate of penetration (e.g., maintain proper hole cleaning). Nowadays, these measurements are still performed manually by using a calibrated funnel viscometer and a weight balance, as stipulated by current American Petroleum Institute (API) standards. In this study, we introduce an automated viscosity/density measurement system based on an electromechanical tuning fork resonator. The system allows for continuous measurements as fast as several times per second in a compact footprint, allowing it to be deployed in tanks or pipelines and/or gathering data from multiple sensors in the mud circulation system. The streams of data produced were broadcasted to a nearby computer allowing for live monitoring of the viscosity and density. The results obtained by the in-tank system in five wells were in good agreement with the standard reference measurements from the mud logs. Here, we describe the development and testing of the tool as well as general guidelines for integration into a rig edge-computing system for real-time analytics and detection of operational problems and drilling automation.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80646141","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}
Natural fracture distribution is critical to the hydrocarbon production from the Early Triassic Montney unconventional oil and gas play. The formation underwent several tectonic events, creating a unique natural fracture system. Identifying tectonic events and their stress field evolution is an import component in fracture system modeling and prediction. The objective of this paper is to identify the evolution of paleo-stress domains, to establish related tectonic models, and to generate the drivers for fracture network modeling which will aid in reservoir understanding and overall play development. Compared with other geomechanical approaches, the boundary element method (BEM) is better suited for the structural characteristics in the study area. Hence, the corresponding boundary element simulation (BES) was applied for the evolution of the paleo-stress domains. The methodology is a combination of 3D BEM and Monte Carlo simulations. The inputs include seismic interpreted faults and natural fractures from Formation Microimager logs. After applying the methodology, several best fit realizations were calculated, and the admissible paleo-stress domains were characterized by the tectonic models which are consistent with the regional tectonic evolution of the formation. The study area is about 400 km2 located at northeast British Columbia in the Western Canada Basin. The main structural features are the thrust and back-thrust faults, forming different fault blocks without any significant deformation structures. The Montney formation within the study area underwent several tectonic events: (1) regime of terrane collision, indentation and lateral escape during end of Middle Jurassic to Middle Cretaceous; (2) regime of left-lateral transpression dominated by strike-slip during end of Late Cretaceous and Paleocene; and (3) regime of right-lateral transtension dominated by strike-slip during end of Early and Middle Eocene which is maintained till present day. Three major stress domains were identified in the study area by the application of the BES method, one reverse event and two strike-slip events, representing paleo and present-day stress domains. These stress domains are consistent with the regional tectonic evolution history of the foreland basin. The stress field parameters, such as stress ratio and maximum horizontal stress azimuth, are consistent. The derived tectonic models are shown to be reliable drivers for the subsequent fracture modeling and geomechanics study.
{"title":"Applying Boundary Element Simulation to Generate Stress-Based Fracture Drivers: A Case Study for the Montney Unconventional Oil/Gas Play in Western Canada Basin","authors":"Z. Cai, Craig I. Smith, J. Cole, C. Tan","doi":"10.2118/204678-ms","DOIUrl":"https://doi.org/10.2118/204678-ms","url":null,"abstract":"\u0000 Natural fracture distribution is critical to the hydrocarbon production from the Early Triassic Montney unconventional oil and gas play. The formation underwent several tectonic events, creating a unique natural fracture system. Identifying tectonic events and their stress field evolution is an import component in fracture system modeling and prediction. The objective of this paper is to identify the evolution of paleo-stress domains, to establish related tectonic models, and to generate the drivers for fracture network modeling which will aid in reservoir understanding and overall play development.\u0000 Compared with other geomechanical approaches, the boundary element method (BEM) is better suited for the structural characteristics in the study area. Hence, the corresponding boundary element simulation (BES) was applied for the evolution of the paleo-stress domains. The methodology is a combination of 3D BEM and Monte Carlo simulations. The inputs include seismic interpreted faults and natural fractures from Formation Microimager logs. After applying the methodology, several best fit realizations were calculated, and the admissible paleo-stress domains were characterized by the tectonic models which are consistent with the regional tectonic evolution of the formation.\u0000 The study area is about 400 km2 located at northeast British Columbia in the Western Canada Basin. The main structural features are the thrust and back-thrust faults, forming different fault blocks without any significant deformation structures. The Montney formation within the study area underwent several tectonic events: (1) regime of terrane collision, indentation and lateral escape during end of Middle Jurassic to Middle Cretaceous; (2) regime of left-lateral transpression dominated by strike-slip during end of Late Cretaceous and Paleocene; and (3) regime of right-lateral transtension dominated by strike-slip during end of Early and Middle Eocene which is maintained till present day. Three major stress domains were identified in the study area by the application of the BES method, one reverse event and two strike-slip events, representing paleo and present-day stress domains. These stress domains are consistent with the regional tectonic evolution history of the foreland basin. The stress field parameters, such as stress ratio and maximum horizontal stress azimuth, are consistent. The derived tectonic models are shown to be reliable drivers for the subsequent fracture modeling and geomechanics study.","PeriodicalId":11094,"journal":{"name":"Day 2 Mon, November 29, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75484566","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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