U. Prasad, Ashabikash Roy Chowdhury, Mark Anderson
Operators face the continuing challenge to improve drilling efficiency for cost containment, especially in deepwater drilling environments where drilling costs are significantly higher. Innovative drilling technologies have been developed and implemented continuously to support the initiative. In many areas of the world, including the Gulf of Mexico (GOM), hydrocarbon reservoirs exist below thick non-porous and impermeable sequences of salt that are considered a perfect cap rock. However, salt poses varied levels of drilling challenges due to its unique mechanical properties. At ambient conditions, the unconfined compressive strength (UCS) of salt varies between 3,000 to 5,000 psi; however, the strain at failure for salt can be an order of magnitude higher when compared to other rocks. Consequently, during drilling salt's viscoelastic behavior requires that its must be broken with an inter-crystalline or trans-crystalline grain boundary breakage. When compared to other rock types, the unique isotropic nature of salt results in a level of strain that is much higher for the given elastic moduli. This strain level makes salt failure mechanics different from other rock types that are prevalent in the GOM. Hybrid bits combine roller-cone and polycrystalline diamond compact (PDC) cutting elements to perform a simultaneous on-bottom crushing / gouging and shearing action. Two divergent cutting mechanics pre-stresses the rock and apply high strain for deformation and displacement, resulting in highly efficient cutting mechanics. To meet the drilling objectives, different hybrid designs have been implemented to combine stability and aggressiveness for improved drilling efficiency. An operator, while drilling salt sections at record penetration rates, has successfully used this innovative process of rock failure utilizing the dual-cutting mechanics of hybrid bits. This has resulted in significant value additions for the operator. This paper analyzes field-drilling data from successful GOM wells and attempts to correlate salt failure mechanics and provide insight into dual-cutting mechanics and its correlation with salt failure. The paper also reviews the drilling mechanics of hybrid bits in salt and highlights importance of dual-cutting mechanics for achieving higher penetration rates in salt through improved drilling efficiency.
{"title":"Drilling Mechanics Analysis of Record Hybrid Drill Bit Runs in Gulf of Mexico Salt Formation and its Correlation with Rock-Mechanical Properties of Salt","authors":"U. Prasad, Ashabikash Roy Chowdhury, Mark Anderson","doi":"10.2118/195860-ms","DOIUrl":"https://doi.org/10.2118/195860-ms","url":null,"abstract":"\u0000 Operators face the continuing challenge to improve drilling efficiency for cost containment, especially in deepwater drilling environments where drilling costs are significantly higher. Innovative drilling technologies have been developed and implemented continuously to support the initiative. In many areas of the world, including the Gulf of Mexico (GOM), hydrocarbon reservoirs exist below thick non-porous and impermeable sequences of salt that are considered a perfect cap rock. However, salt poses varied levels of drilling challenges due to its unique mechanical properties.\u0000 At ambient conditions, the unconfined compressive strength (UCS) of salt varies between 3,000 to 5,000 psi; however, the strain at failure for salt can be an order of magnitude higher when compared to other rocks. Consequently, during drilling salt's viscoelastic behavior requires that its must be broken with an inter-crystalline or trans-crystalline grain boundary breakage. When compared to other rock types, the unique isotropic nature of salt results in a level of strain that is much higher for the given elastic moduli. This strain level makes salt failure mechanics different from other rock types that are prevalent in the GOM.\u0000 Hybrid bits combine roller-cone and polycrystalline diamond compact (PDC) cutting elements to perform a simultaneous on-bottom crushing / gouging and shearing action. Two divergent cutting mechanics pre-stresses the rock and apply high strain for deformation and displacement, resulting in highly efficient cutting mechanics. To meet the drilling objectives, different hybrid designs have been implemented to combine stability and aggressiveness for improved drilling efficiency. An operator, while drilling salt sections at record penetration rates, has successfully used this innovative process of rock failure utilizing the dual-cutting mechanics of hybrid bits. This has resulted in significant value additions for the operator.\u0000 This paper analyzes field-drilling data from successful GOM wells and attempts to correlate salt failure mechanics and provide insight into dual-cutting mechanics and its correlation with salt failure. The paper also reviews the drilling mechanics of hybrid bits in salt and highlights importance of dual-cutting mechanics for achieving higher penetration rates in salt through improved drilling efficiency.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76285502","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}
Ramin Dabirian, Mobina Mohammadikharkeshi, R. Mohan, O. Shoham
Sand transport in multiphase flow has recently gained keen attention of the oil and gas industry owing to the negative effects associated with it. These include partial pipe blockage, pipe corrosion, excessive pressure drop and production decline. To date, no comprehensive literature review and models evaluation have been published, which compare the experimental data collected for the prediction of the critical sand deposition velocity under intermittent flow with the related model predictions. This study can be used by engineers and researchers to determine the conditions under which the developed models perform the best. The intermittent flow critical sand deposition velocity data acquired by Najmi (2015) are presented in detail. Next, the effects of important parameters such as phase velocities, liquid viscosity as well as particle size and concentration on the critical velocity are investigated. The collected data are utilized to evaluate the performance of the models developed by Salama (1998), Hill (2011), Stevenson et al. (2001) and Danielson (2007), in order to determine the best model for the prediction of the sand critical velocity. The experimental data of Najmi (2015) indicate that higher critical velocities are required with increasing the liquid viscosity, particle size and particle concentration. However, the predictions of the models of Salama (1998), Stevenson et al. (2001) and Danielson (2007) demonstrate that these models do not take into account the effect of particle concentration. Depending on the liquid viscosity, Stevenson et al. (2001) model significantly over-predicts or under-predicts the critical velocity over different ranges of the phase velocities, while Salama (1998) model under-predicts the critical velocity under all experimental conditions. An overall comparison of the data with the published model predictions confirms that the Hill (2011) model has the best performance capturing the physical phenomena, including the effects of phase velocities, particle size, particle concentration and liquid viscosity.
{"title":"Critical Sand Deposition Velocity in Intermittent Flow – Models Evaluation","authors":"Ramin Dabirian, Mobina Mohammadikharkeshi, R. Mohan, O. Shoham","doi":"10.2118/196085-ms","DOIUrl":"https://doi.org/10.2118/196085-ms","url":null,"abstract":"\u0000 Sand transport in multiphase flow has recently gained keen attention of the oil and gas industry owing to the negative effects associated with it. These include partial pipe blockage, pipe corrosion, excessive pressure drop and production decline. To date, no comprehensive literature review and models evaluation have been published, which compare the experimental data collected for the prediction of the critical sand deposition velocity under intermittent flow with the related model predictions. This study can be used by engineers and researchers to determine the conditions under which the developed models perform the best.\u0000 The intermittent flow critical sand deposition velocity data acquired by Najmi (2015) are presented in detail. Next, the effects of important parameters such as phase velocities, liquid viscosity as well as particle size and concentration on the critical velocity are investigated. The collected data are utilized to evaluate the performance of the models developed by Salama (1998), Hill (2011), Stevenson et al. (2001) and Danielson (2007), in order to determine the best model for the prediction of the sand critical velocity.\u0000 The experimental data of Najmi (2015) indicate that higher critical velocities are required with increasing the liquid viscosity, particle size and particle concentration. However, the predictions of the models of Salama (1998), Stevenson et al. (2001) and Danielson (2007) demonstrate that these models do not take into account the effect of particle concentration. Depending on the liquid viscosity, Stevenson et al. (2001) model significantly over-predicts or under-predicts the critical velocity over different ranges of the phase velocities, while Salama (1998) model under-predicts the critical velocity under all experimental conditions. An overall comparison of the data with the published model predictions confirms that the Hill (2011) model has the best performance capturing the physical phenomena, including the effects of phase velocities, particle size, particle concentration and liquid viscosity.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76551872","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}
Yan Li, K. Zaki, Yunhui Tan, Ruiting Wu, Peggy Rijken
PI (Productivity Index) degradation is a common issue in many oil fields. To obtain a highly reliable production forecast, it is critical to include well and completion performance in the analysis. A new workflow is developed to assess and incorporate the damage mechanisms at the wellbore, fracture and reservoir into production forecasting. Currently, most reservoir models use a skin factor to represent the combined well damages mechanisms. The skin factor is adjusted based on the user's experience or data analysis instead of physical modeling. In this workflow, a detailed model is built to explicitly simulate the damage mechanisms, assess the dynamic performance of the well and completion with depletion, and generate a physics-based proxy function for reservoir modeling. The new workflow closes the modeling gap in production forecasting and provides insights into which damage mechanisms impact PI degradation. In the workflow, a detailed model is built, which includes an explicit wellbore, an explicit fracture and the reservoir. Subsurface rock and flow damage mechanisms are represented explicitly in the model. Running the model with an optimization tool, the damage mechanisms’ impact on productivity can be assessed separately or in a combination. A physics-based proxy is generated linking the change in productivity to typical well parameters such as cumulative production, drainage region depletion and drawdown. This proxy is then incorporated into a standard reservoir simulator through the utilization of scripts linking the PI evolution of the well to the typical well parameters stated above. The workflow increases the reliability of generated production forecasts by incorporating the best representation of the near wellbore flow patterns. By varying the damage mechanism inputs the workflow is capable of history matching and forecasting the observed field behavior. The workflow has been validated for a high permeability, over pressured deep-water reservoir. The history match, PI prediction and damage mechanism analysis are presented in this paper. The new workflow can help assets to: (1) history match and forecast well performance under varying operating conditions; (2) identify the key damage mechanisms which allows for potential mitigation and remediation solutions and; (3) set operational limits that reduce the likelihood of future PI degradation and maintain current performance.
{"title":"Productivity Decline: Improved Production Forecasting Through Accurate Representation of Well Damage","authors":"Yan Li, K. Zaki, Yunhui Tan, Ruiting Wu, Peggy Rijken","doi":"10.2118/196213-ms","DOIUrl":"https://doi.org/10.2118/196213-ms","url":null,"abstract":"\u0000 PI (Productivity Index) degradation is a common issue in many oil fields. To obtain a highly reliable production forecast, it is critical to include well and completion performance in the analysis. A new workflow is developed to assess and incorporate the damage mechanisms at the wellbore, fracture and reservoir into production forecasting. Currently, most reservoir models use a skin factor to represent the combined well damages mechanisms. The skin factor is adjusted based on the user's experience or data analysis instead of physical modeling. In this workflow, a detailed model is built to explicitly simulate the damage mechanisms, assess the dynamic performance of the well and completion with depletion, and generate a physics-based proxy function for reservoir modeling. The new workflow closes the modeling gap in production forecasting and provides insights into which damage mechanisms impact PI degradation.\u0000 In the workflow, a detailed model is built, which includes an explicit wellbore, an explicit fracture and the reservoir. Subsurface rock and flow damage mechanisms are represented explicitly in the model. Running the model with an optimization tool, the damage mechanisms’ impact on productivity can be assessed separately or in a combination. A physics-based proxy is generated linking the change in productivity to typical well parameters such as cumulative production, drainage region depletion and drawdown. This proxy is then incorporated into a standard reservoir simulator through the utilization of scripts linking the PI evolution of the well to the typical well parameters stated above. The workflow increases the reliability of generated production forecasts by incorporating the best representation of the near wellbore flow patterns.\u0000 By varying the damage mechanism inputs the workflow is capable of history matching and forecasting the observed field behavior. The workflow has been validated for a high permeability, over pressured deep-water reservoir. The history match, PI prediction and damage mechanism analysis are presented in this paper. The new workflow can help assets to: (1) history match and forecast well performance under varying operating conditions; (2) identify the key damage mechanisms which allows for potential mitigation and remediation solutions and; (3) set operational limits that reduce the likelihood of future PI degradation and maintain current performance.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91297897","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}
Shale reservoirs are estimated to account for approximately 10-30% of oil and gas worldwide, yet operators rarely produce more than 10% of the original hydrocarbons in place from them. These poor production numbers are a result of the assumption that the same pressure-volume-temperature (PVT) analysis procedures that are employed in conventional reservoirs are also applicable to shale and tight reservoirs. However, traditional PVT analysis does not account for the nanoporosity of the shale and, therefore, neglects the ability of nanopores to significantly alter the phase behavior of reservoir fluids. To quantify the effects of shale nanoporosity on the phase behavior of reservoir fluids, a novel gravimetric apparatus was developed. Unlike other gravimetric apparatuses in the literature, ours is compatible with both simple and complex experimental fluids and up to several hundred grams of unconsolidated or consolidated porous media at temperatures and pressures up to 232ᵒC and 5,000 psi, respectively. Furthermore, our apparatus does not require a buoyant force correction, which is one of the major shortcomings of most commercially available gravimetric apparatuses. These unique features allow us to study fluid phase behavior in shale and tight cores with high accuracy and efficiency. In the course of an exhaustive three-year research program, we have used this apparatus to measure the first capillary condensation isotherm for a fluid mixture with more than two components and discovered new phenomena of capillary condensed and supercritical fluids in the nanopores of shale rock and synthetic porous media. By reviewing the works produced over the course of this research, we are now able to answer longstanding questions as to when and how nanoconfinement-induced phase behavior occur in shale reservoirs and the implications that different types of phase behavior, including capillary condensation and nanoconfined supercriticality, have for oil and gas production.
{"title":"Capillary Condensation in Shale: A Narrative Review","authors":"E. Barsotti","doi":"10.2118/199768-stu","DOIUrl":"https://doi.org/10.2118/199768-stu","url":null,"abstract":"\u0000 Shale reservoirs are estimated to account for approximately 10-30% of oil and gas worldwide, yet operators rarely produce more than 10% of the original hydrocarbons in place from them. These poor production numbers are a result of the assumption that the same pressure-volume-temperature (PVT) analysis procedures that are employed in conventional reservoirs are also applicable to shale and tight reservoirs. However, traditional PVT analysis does not account for the nanoporosity of the shale and, therefore, neglects the ability of nanopores to significantly alter the phase behavior of reservoir fluids. To quantify the effects of shale nanoporosity on the phase behavior of reservoir fluids, a novel gravimetric apparatus was developed. Unlike other gravimetric apparatuses in the literature, ours is compatible with both simple and complex experimental fluids and up to several hundred grams of unconsolidated or consolidated porous media at temperatures and pressures up to 232ᵒC and 5,000 psi, respectively. Furthermore, our apparatus does not require a buoyant force correction, which is one of the major shortcomings of most commercially available gravimetric apparatuses. These unique features allow us to study fluid phase behavior in shale and tight cores with high accuracy and efficiency. In the course of an exhaustive three-year research program, we have used this apparatus to measure the first capillary condensation isotherm for a fluid mixture with more than two components and discovered new phenomena of capillary condensed and supercritical fluids in the nanopores of shale rock and synthetic porous media. By reviewing the works produced over the course of this research, we are now able to answer longstanding questions as to when and how nanoconfinement-induced phase behavior occur in shale reservoirs and the implications that different types of phase behavior, including capillary condensation and nanoconfined supercriticality, have for oil and gas production.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"2015 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83165442","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}
S. Rajput, I. Abdullah, A. Roy, Aizuddin Khalid, C. Onn, A. Khalil
Low electrical resistivity and low contrast reservoirs (LRLC) pay zones are composed of thinly-bedded laminated layers containing hydrocarbon accumulations surrounded by non-reservoir layers indicating lack of resistivity contrast. These pay zones are difficult to be distinguished at seismic and log scale due to lower vertical and lateral resolution. Traditionally, deep-resistivity logs in LRLC zones read 0.5 to 5 ohm-m. Low contrast pay zone occurs mainly when the formation waters are fresh or having low salinity resulting in a very little resistivity contrast between oil and water zones. Major challenges imposed in LRLC reservoirs include identification, characterization, and evaluation of the hydrocarbon interval, which is usually masked by the lack of resistivity contrast between the hydrocarbon and water zones. The identification and characterization of the lowdown on resistivity pay is essential for the re-development of mature assets for improved oil recovery. This paper deals with the characterization of low resistivity hydrocarbon-bearing thinly-bedded reservoirs from a brownfield. To unlock the hidden potential of LRLC pay sands in the offshore Sarawak Malaysia, the effective integration of subsurface disciplines including petrophysics, geology and quantitative derivatives from the seismic analysis is vital. This study covers the geological perspective of low contrast reservoirs from an offshore oil field deposited in lower coastal plain settings located within offshore Sarawak Malaysia. An improved understanding of the geological, petrophysical and geophysical parameters was achieved by adopting a holistic and multidisciplinary approach. This includes the integration of core, logs, rock physics modeled parameters, stratigraphic, depositional and lithofacies information along with stochastic inversion derivatives. Acoustic Impedance shows the facies changes in broader terms between producing and non-producing zone. The paper quantifies rock physics parameter uncertainties for LRLC pay zones and establishes a framework for LRLC reservoir characterization. Stochastic inversion derived P-Impedance and Vp/Vs ratio are used to predict fluid and facies probabilities (Rajput S., 2014) for LRLC reservoirs, which then further integrated with stratigraphic information. The results offered an effective way of establishing analogs of producing and non-producing LRLC zones. Analysis of fluid and facies probabilities derivatives driven surface attributes is a way seismic can potentially contribute to indicating areas of relatively better or worse LRLC reservoir continuity. Identified LRLC reservoirs proved to be of commercial-quality and increased oil production to the extent of several hundred thousands of barrels over the years and currently producing. Rock physics modeled parameters including AI and Vp/Vs are sensitive to LRLC pay zones and their effective integration with image logs, lithofacies, and seismic inversion lead to reduce uncertai
{"title":"Characterizing Thinly-Bedded Low Resistivity Reservoirs in Mature Fields","authors":"S. Rajput, I. Abdullah, A. Roy, Aizuddin Khalid, C. Onn, A. Khalil","doi":"10.2118/195862-ms","DOIUrl":"https://doi.org/10.2118/195862-ms","url":null,"abstract":"\u0000 Low electrical resistivity and low contrast reservoirs (LRLC) pay zones are composed of thinly-bedded laminated layers containing hydrocarbon accumulations surrounded by non-reservoir layers indicating lack of resistivity contrast. These pay zones are difficult to be distinguished at seismic and log scale due to lower vertical and lateral resolution. Traditionally, deep-resistivity logs in LRLC zones read 0.5 to 5 ohm-m. Low contrast pay zone occurs mainly when the formation waters are fresh or having low salinity resulting in a very little resistivity contrast between oil and water zones. Major challenges imposed in LRLC reservoirs include identification, characterization, and evaluation of the hydrocarbon interval, which is usually masked by the lack of resistivity contrast between the hydrocarbon and water zones. The identification and characterization of the lowdown on resistivity pay is essential for the re-development of mature assets for improved oil recovery. This paper deals with the characterization of low resistivity hydrocarbon-bearing thinly-bedded reservoirs from a brownfield.\u0000 To unlock the hidden potential of LRLC pay sands in the offshore Sarawak Malaysia, the effective integration of subsurface disciplines including petrophysics, geology and quantitative derivatives from the seismic analysis is vital. This study covers the geological perspective of low contrast reservoirs from an offshore oil field deposited in lower coastal plain settings located within offshore Sarawak Malaysia. An improved understanding of the geological, petrophysical and geophysical parameters was achieved by adopting a holistic and multidisciplinary approach. This includes the integration of core, logs, rock physics modeled parameters, stratigraphic, depositional and lithofacies information along with stochastic inversion derivatives. Acoustic Impedance shows the facies changes in broader terms between producing and non-producing zone.\u0000 The paper quantifies rock physics parameter uncertainties for LRLC pay zones and establishes a framework for LRLC reservoir characterization. Stochastic inversion derived P-Impedance and Vp/Vs ratio are used to predict fluid and facies probabilities (Rajput S., 2014) for LRLC reservoirs, which then further integrated with stratigraphic information. The results offered an effective way of establishing analogs of producing and non-producing LRLC zones. Analysis of fluid and facies probabilities derivatives driven surface attributes is a way seismic can potentially contribute to indicating areas of relatively better or worse LRLC reservoir continuity.\u0000 Identified LRLC reservoirs proved to be of commercial-quality and increased oil production to the extent of several hundred thousands of barrels over the years and currently producing. Rock physics modeled parameters including AI and Vp/Vs are sensitive to LRLC pay zones and their effective integration with image logs, lithofacies, and seismic inversion lead to reduce uncertai","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84566003","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}
Peng Li, Jonathan Lee, A. Taher, R. Coates, R. Marlow
Obtaining high-resolution borehole images in oil-based mud (OBM) from logging-while-drilling (LWD) tools has been made possible through the recent development of ultrasonic imaging technologies. High-resolution acoustic impedance images enable reservoir evaluation through the identification of faults and fractures, bedding and laminations, and assessment of rock fabric. This paper presents examples of high-resolution images from a 4¾-in. ultrasonic imaging tool in OBM applications and discusses their value in assessing reservoir quality. This paper provides details of field trials of an LWD ultrasonic imaging tool for use in boreholes ranging from 5¾ to 6¾ in. High-resolution images detailing both borehole caliper and acoustic impedance in both vertical and horizontal wellbores are shown, illustrating the high level of formation evaluation now available when OBM is used. The methodology used to address the impact of tool motion on the impedance images will also be covered. The value of real-time data on borehole stability assessment will be discussed, along with additional applications made possible from the real-time data, such as wellbore placement enhancement. Both real-time and recorded data from field trials show the potential applications for the ultrasonic imaging tool. High-resolution impedance images covering different formations and lithologies show bedding planes and laminations and enable the calculation of stratigraphic dip, while the identification and assessment of fractures show the potential to aid operators during the development of their hydraulic fracturing program. Borehole caliper and shape assessment in real time can be used to modify the drilling parameters and to adjust mud weight, while providing an input into geomechanics assessment. The LWD logs presented illustrate the factors that influence data quality and the methodology used to ensure high-resolution images are available in both vertical and high-angle wellbores using OBM. A direct comparison between data acquired while drilling and while re-logging sections is shown, highlighting the repeatability of the measurement while also illustrating the impact of time-since-drilled on the borehole. A comparison with wireline measurements highlights the potential for using the high-resolution LWD images as an alternative to wireline, where cost and risk of deploying the wireline may be high. The ability to collect high-resolution images in OBM in wellbores ranging from 5¾ to 6¾ in. ensures that increased reservoir characterization is possible, leading to significant improvements in determining the viability of unconventional and other challenging reservoirs. The high-resolution amplitude images are comparable with those available on wireline technologies, and the real-time application of borehole size and shape for input into wellbore stability and geomechanics analysis ensures that common drilling hazards can be avoided.
{"title":"High-Resolution Ultrasonic Borehole Imaging Enhances Reservoir Evaluation in Oil-Based Muds","authors":"Peng Li, Jonathan Lee, A. Taher, R. Coates, R. Marlow","doi":"10.2118/196126-ms","DOIUrl":"https://doi.org/10.2118/196126-ms","url":null,"abstract":"\u0000 Obtaining high-resolution borehole images in oil-based mud (OBM) from logging-while-drilling (LWD) tools has been made possible through the recent development of ultrasonic imaging technologies. High-resolution acoustic impedance images enable reservoir evaluation through the identification of faults and fractures, bedding and laminations, and assessment of rock fabric. This paper presents examples of high-resolution images from a 4¾-in. ultrasonic imaging tool in OBM applications and discusses their value in assessing reservoir quality.\u0000 This paper provides details of field trials of an LWD ultrasonic imaging tool for use in boreholes ranging from 5¾ to 6¾ in. High-resolution images detailing both borehole caliper and acoustic impedance in both vertical and horizontal wellbores are shown, illustrating the high level of formation evaluation now available when OBM is used. The methodology used to address the impact of tool motion on the impedance images will also be covered. The value of real-time data on borehole stability assessment will be discussed, along with additional applications made possible from the real-time data, such as wellbore placement enhancement.\u0000 Both real-time and recorded data from field trials show the potential applications for the ultrasonic imaging tool. High-resolution impedance images covering different formations and lithologies show bedding planes and laminations and enable the calculation of stratigraphic dip, while the identification and assessment of fractures show the potential to aid operators during the development of their hydraulic fracturing program. Borehole caliper and shape assessment in real time can be used to modify the drilling parameters and to adjust mud weight, while providing an input into geomechanics assessment.\u0000 The LWD logs presented illustrate the factors that influence data quality and the methodology used to ensure high-resolution images are available in both vertical and high-angle wellbores using OBM. A direct comparison between data acquired while drilling and while re-logging sections is shown, highlighting the repeatability of the measurement while also illustrating the impact of time-since-drilled on the borehole. A comparison with wireline measurements highlights the potential for using the high-resolution LWD images as an alternative to wireline, where cost and risk of deploying the wireline may be high.\u0000 The ability to collect high-resolution images in OBM in wellbores ranging from 5¾ to 6¾ in. ensures that increased reservoir characterization is possible, leading to significant improvements in determining the viability of unconventional and other challenging reservoirs. The high-resolution amplitude images are comparable with those available on wireline technologies, and the real-time application of borehole size and shape for input into wellbore stability and geomechanics analysis ensures that common drilling hazards can be avoided.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90561194","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}
Horizons in a seismic image are geologically signficant surfaces that can be used for understanding geological structures and stratigraphy models. However, horizon tracking in seismic data is a time consuming and challenging task. Saving geologist's time from this seismic interpretation task is essential given the time constraints for the decision making in the oil & gas industry. We take advantage of the deep convolutional neural networks (CNN) to track the horizons directly from the seismic images. We propose a novel automatic seismic horizon tracking method that can reduce the time needed for interpretation, as well as increase the accuracy for the geologists. We show the performance comparison of the proposed CNN model for different training data set sizes and different methods of balancing the classes.
{"title":"Deep Learning-Based Automatic Horizon Identification from Seismic Data","authors":"Harshit Gupta, Siddhant Pradhan, Rahul Gogia, Seshan Srirangarajan, J. Phirani, Sayan Ranu","doi":"10.2118/196087-ms","DOIUrl":"https://doi.org/10.2118/196087-ms","url":null,"abstract":"\u0000 Horizons in a seismic image are geologically signficant surfaces that can be used for understanding geological structures and stratigraphy models. However, horizon tracking in seismic data is a time consuming and challenging task. Saving geologist's time from this seismic interpretation task is essential given the time constraints for the decision making in the oil & gas industry. We take advantage of the deep convolutional neural networks (CNN) to track the horizons directly from the seismic images. We propose a novel automatic seismic horizon tracking method that can reduce the time needed for interpretation, as well as increase the accuracy for the geologists. We show the performance comparison of the proposed CNN model for different training data set sizes and different methods of balancing the classes.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83942758","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}
J. Brady, K. Passmore, F. Paskvan, Jason C. Wilkes, T. Allison, E. Swanson, M KleinJohn
This paper discusses component developments, validation testing, and yard testing of the subsurface process and reinjection compressor (SPARC) prototype tool approaching downhole flowing conditions (≈1200 psig and > 225°F). This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface. A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing. The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and > 450°F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls. This equipment will allow for the reduction of costly surface facilities to process, compress, and reinject produced gas into North Slope fields and some oil and condensate fields elsewhere globally, which are limited in liquid hydrocarbon production because of surface gas processing facility limitations. Another potential use of the SPARC technology is as an artificial lift mechanism for gas reservoirs. Using the SPARC as a gas well artificial lift system would require a redesign of the SPARC with an electric motor as its power source in place of the turbo-expander. However, no new technology breakthroughs are necessary because the technology has already been developed with the SPARC design. To date, there have been no small gas compressors, turbo expanders, and other necessary equipment built and tested that can be run through 4 1/2-in. tubing/casing and operate autonomously at downhole conditions. This technology opens up the possibilities of additional relatively inexpensive gas recycling on the North Slope and other condensate fields worldwide.
{"title":"Development of the Subsurface Process and Reinjection Compressor","authors":"J. Brady, K. Passmore, F. Paskvan, Jason C. Wilkes, T. Allison, E. Swanson, M KleinJohn","doi":"10.2118/195942-ms","DOIUrl":"https://doi.org/10.2118/195942-ms","url":null,"abstract":"\u0000 This paper discusses component developments, validation testing, and yard testing of the subsurface process and reinjection compressor (SPARC) prototype tool approaching downhole flowing conditions (≈1200 psig and > 225°F). This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface.\u0000 A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing.\u0000 The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and > 450°F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls.\u0000 This equipment will allow for the reduction of costly surface facilities to process, compress, and reinject produced gas into North Slope fields and some oil and condensate fields elsewhere globally, which are limited in liquid hydrocarbon production because of surface gas processing facility limitations.\u0000 Another potential use of the SPARC technology is as an artificial lift mechanism for gas reservoirs. Using the SPARC as a gas well artificial lift system would require a redesign of the SPARC with an electric motor as its power source in place of the turbo-expander. However, no new technology breakthroughs are necessary because the technology has already been developed with the SPARC design.\u0000 To date, there have been no small gas compressors, turbo expanders, and other necessary equipment built and tested that can be run through 4 1/2-in. tubing/casing and operate autonomously at downhole conditions. This technology opens up the possibilities of additional relatively inexpensive gas recycling on the North Slope and other condensate fields worldwide.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78422691","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}
Carbon dioxide (CO2) injection has recently been applied as an enhanced oil recovery (EOR) method to increase oil recovery from unconventional shale reservoirs. Many interactions will impact the success or failure of this EOR method. This research experimentally investigates the impact of two of these interactions, including asphaltene pore plugging and CO2 adsorption, on the success of CO2 EOR in unconventional shale reservoirs. Two sets of experiments were designed to study the asphaltene pore plugging and CO2 adsorption. The impact of varying CO2 injection pressure, temperature, oil viscosity, and filter membrane pore size on asphaltene pore plugging was investigated. Pertaining to the adsorption experiments, the impact of varying CO2 injection pressure, temperature, and shale particle size was investigated. Asphaltene pore plugging was found to be extremely severe especially in the smaller pore sizes, which indicates that asphaltene poses a serious problem when producing from unconventional nanopores. As the oil viscosity decreased, the asphaltene concentration in the oil decreased as well which made the asphaltene pore plugging less severe in the lower viscosity oils. The thermodynamic conditions, including pressure and temperature, also had a strong impact on asphaltene stability and pore plugging. When undergoing the CO2 adsorption experiments, it was found that increasing the CO2 injection pressure resulted in an increase in adsorption capacity to a certain limit beyond which no further adsorption will be possible. Increasing the temperature resulted in the CO2 molecules becoming highly active which in turn resulted in a decrease in the adsorption capacity significantly. Since experiments were conducted using shale particles, as opposed to an actual shale core, it was important to investigate the accuracy of the results by varying the shale particle size. It was found that as long as the void space volume was measured accurately using helium, the shale particle size had a negligible effect on the adsorption values. This research systematically investigates the impact of two significant interactions on the success of CO2 injection in unconventional shale reservoirs, and studies the impact of several factors within these interactions to determine the extent to which they may influence the success of this EOR method.
{"title":"Investigating Factors that May Impact the Success of Carbon Dioxide Enhanced Oil Recovery in Shale Reservoirs","authors":"Sherif Fakher","doi":"10.2118/199781-stu","DOIUrl":"https://doi.org/10.2118/199781-stu","url":null,"abstract":"\u0000 Carbon dioxide (CO2) injection has recently been applied as an enhanced oil recovery (EOR) method to increase oil recovery from unconventional shale reservoirs. Many interactions will impact the success or failure of this EOR method. This research experimentally investigates the impact of two of these interactions, including asphaltene pore plugging and CO2 adsorption, on the success of CO2 EOR in unconventional shale reservoirs. Two sets of experiments were designed to study the asphaltene pore plugging and CO2 adsorption. The impact of varying CO2 injection pressure, temperature, oil viscosity, and filter membrane pore size on asphaltene pore plugging was investigated. Pertaining to the adsorption experiments, the impact of varying CO2 injection pressure, temperature, and shale particle size was investigated. Asphaltene pore plugging was found to be extremely severe especially in the smaller pore sizes, which indicates that asphaltene poses a serious problem when producing from unconventional nanopores. As the oil viscosity decreased, the asphaltene concentration in the oil decreased as well which made the asphaltene pore plugging less severe in the lower viscosity oils. The thermodynamic conditions, including pressure and temperature, also had a strong impact on asphaltene stability and pore plugging. When undergoing the CO2 adsorption experiments, it was found that increasing the CO2 injection pressure resulted in an increase in adsorption capacity to a certain limit beyond which no further adsorption will be possible. Increasing the temperature resulted in the CO2 molecules becoming highly active which in turn resulted in a decrease in the adsorption capacity significantly. Since experiments were conducted using shale particles, as opposed to an actual shale core, it was important to investigate the accuracy of the results by varying the shale particle size. It was found that as long as the void space volume was measured accurately using helium, the shale particle size had a negligible effect on the adsorption values. This research systematically investigates the impact of two significant interactions on the success of CO2 injection in unconventional shale reservoirs, and studies the impact of several factors within these interactions to determine the extent to which they may influence the success of this EOR method.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86871011","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}
Hardikkumar Zalavadia, S. Sankaran, M. Kara, Wenyue Sun, E. Gildin
Model-based field development planning and optimization often require computationally intensive reservoir simulations, where the models need to be run several times in the context of input uncertainty or seeking optimal results. Reduced Order Modeling (ROM) methods are a class of techniques that are applied to reservoir simulation to reduce model complexity and speed up computations, especially for large scale or complex models that may be quite useful for such optimization problems. While intrusive ROM methods (such as proper orthogonal decomposition (POD) and its extensions, trajectory piece-wise linearization (TPWL), Discrete Empirical Interpolation Method (DEIM) etc.) have been proposed for application to reservoir simulation problems, these remain inaccessible or unusable for a large number of practical applications that use commercial simulators. In this paper, we describe a novel application of a non-intrusive ROM method, namely dynamic mode decomposition (DMD). We specifically look at reducing the time complexity involved in well control optimization problem, using a variant of DMD called DMDc (DMD with control). We propose a workflow using a training dataset of the wells and predict the state solution (pressure and saturation) for a new set of bottomhole pressure profiles encountered during the optimization runs. We use a novel strategy to select the basis dimensions to prevent unstable solutions. Since the objective function of the optimization problem is usually based on fluid production profiles, we propose a strategy to predict the fluid production rates from the predicted states from DMDc using machine learning techniques. The features for this machine learning problem are designed based on the physics of fluid flow through well perforations, which result in very accurate rate predictions. We compare the proposed methodology using another variant of DMD called ioDMD (input-ouput DMD) for system identification to predict output production flow rates. The methodology is demonstrated on a benchmark case and a Gulf of Mexico deepwater field that shows significant time reduction in production control optimization problem with about 30 – 40 times speedup using the proposed DMDc workflow as compared to fine scale simulations, while preserving the accuracy of the solutions. The proposed "non-intrusive" method in this paper to reduce model complexity can substantially increase the range of application of ROM methods for practical field development and reservoir management.
{"title":"A Hybrid Modeling Approach to Production Control Optimization Using Dynamic Mode Decomposition","authors":"Hardikkumar Zalavadia, S. Sankaran, M. Kara, Wenyue Sun, E. Gildin","doi":"10.2118/196124-ms","DOIUrl":"https://doi.org/10.2118/196124-ms","url":null,"abstract":"\u0000 Model-based field development planning and optimization often require computationally intensive reservoir simulations, where the models need to be run several times in the context of input uncertainty or seeking optimal results. Reduced Order Modeling (ROM) methods are a class of techniques that are applied to reservoir simulation to reduce model complexity and speed up computations, especially for large scale or complex models that may be quite useful for such optimization problems. While intrusive ROM methods (such as proper orthogonal decomposition (POD) and its extensions, trajectory piece-wise linearization (TPWL), Discrete Empirical Interpolation Method (DEIM) etc.) have been proposed for application to reservoir simulation problems, these remain inaccessible or unusable for a large number of practical applications that use commercial simulators.\u0000 In this paper, we describe a novel application of a non-intrusive ROM method, namely dynamic mode decomposition (DMD). We specifically look at reducing the time complexity involved in well control optimization problem, using a variant of DMD called DMDc (DMD with control). We propose a workflow using a training dataset of the wells and predict the state solution (pressure and saturation) for a new set of bottomhole pressure profiles encountered during the optimization runs. We use a novel strategy to select the basis dimensions to prevent unstable solutions. Since the objective function of the optimization problem is usually based on fluid production profiles, we propose a strategy to predict the fluid production rates from the predicted states from DMDc using machine learning techniques. The features for this machine learning problem are designed based on the physics of fluid flow through well perforations, which result in very accurate rate predictions. We compare the proposed methodology using another variant of DMD called ioDMD (input-ouput DMD) for system identification to predict output production flow rates.\u0000 The methodology is demonstrated on a benchmark case and a Gulf of Mexico deepwater field that shows significant time reduction in production control optimization problem with about 30 – 40 times speedup using the proposed DMDc workflow as compared to fine scale simulations, while preserving the accuracy of the solutions. The proposed \"non-intrusive\" method in this paper to reduce model complexity can substantially increase the range of application of ROM methods for practical field development and reservoir management.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87389789","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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