As the number of new exploration and development wells continues to increase, guiding the bit while drilling in real time is becoming one of the most requested technologies. Seismic-while-drilling may enable accurate prediction of high-pressure zones, fractures and cavities, coring points, target depths, and geosteering in high-quality reservoir zones to optimize drilling decisions and reduce costs. A fully integrated real-time system to map and predict ahead of the bit and geosteer in high-quality reservoir zones is presented, showing application of seismic while drilling (SWD). We call this technology DrillCAM. Recent enabling technological advances were made in wireless high-channel recording, signal enhancement and imaging algorithms, as well as high-performance computational resources that are easily deployable to the field. Such technological advances open a completely new set of possibilities for real-time drill bit guidance and navigation. One key enabler for DrillCAM is the use of wireless seismic receiver stations. Compared to conventional cabled geophones and cableless nodal systems, wireless receivers can provide real-time recording and transmission without the need for extra equipment for data retrieval, flexible receiver spacing and areal coverage. This, in turn, results in a flexible lightweight system for easy mobilization and ultralow power consumption for extended battery life. We show a carefully designed field data acquisition experiment using the drill bit as a downhole seismic source and a large number of seismic receivers at the surface. The wireless receivers are arranged in flexible geometries that adapt to target bit depths. Using dedicated sensors, the bit signature (pilot signal) is recorded using high-frequency surface and downhole accelerometers. The system integrates surface seismic recordings and surface noise recordings with pilot signal recordings. The initial field experiment is conducted on a nearly vertical onshore well. This experiment demonstrates the feasibility of an integrated DrillCAM SWD system. The paper presents the motivation, objectives, numerical studies, and first field test of a novel integrated real-time SWD system. Not only does such a system detect bit signals while drilling, it also validates these signals against other measured data and drilling activities.
{"title":"DrillCAM Seismic System to Aid Geosteering and Drilling Optimization","authors":"E. Hemyari, A. Bakulin, I. Silvestrov, Yujin Liu","doi":"10.2118/194876-MS","DOIUrl":"https://doi.org/10.2118/194876-MS","url":null,"abstract":"\u0000 As the number of new exploration and development wells continues to increase, guiding the bit while drilling in real time is becoming one of the most requested technologies. Seismic-while-drilling may enable accurate prediction of high-pressure zones, fractures and cavities, coring points, target depths, and geosteering in high-quality reservoir zones to optimize drilling decisions and reduce costs. A fully integrated real-time system to map and predict ahead of the bit and geosteer in high-quality reservoir zones is presented, showing application of seismic while drilling (SWD). We call this technology DrillCAM.\u0000 Recent enabling technological advances were made in wireless high-channel recording, signal enhancement and imaging algorithms, as well as high-performance computational resources that are easily deployable to the field. Such technological advances open a completely new set of possibilities for real-time drill bit guidance and navigation. One key enabler for DrillCAM is the use of wireless seismic receiver stations. Compared to conventional cabled geophones and cableless nodal systems, wireless receivers can provide real-time recording and transmission without the need for extra equipment for data retrieval, flexible receiver spacing and areal coverage. This, in turn, results in a flexible lightweight system for easy mobilization and ultralow power consumption for extended battery life.\u0000 We show a carefully designed field data acquisition experiment using the drill bit as a downhole seismic source and a large number of seismic receivers at the surface. The wireless receivers are arranged in flexible geometries that adapt to target bit depths. Using dedicated sensors, the bit signature (pilot signal) is recorded using high-frequency surface and downhole accelerometers. The system integrates surface seismic recordings and surface noise recordings with pilot signal recordings. The initial field experiment is conducted on a nearly vertical onshore well. This experiment demonstrates the feasibility of an integrated DrillCAM SWD system.\u0000 The paper presents the motivation, objectives, numerical studies, and first field test of a novel integrated real-time SWD system. Not only does such a system detect bit signals while drilling, it also validates these signals against other measured data and drilling activities.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82271598","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. Rueda, J. Valbuena, S. Baki, Karim Mechkak, Mahfouz Mohannad, A. Momin, N. Mulhim
There is little understanding on how the fracture networks in unconventional source plays, commonly referred as Stimulated Reservoir Volumes (SRV), grow with distance and time during the fracturing jobs and connect other offset laterals with or without hydraulically created SRVs. Understanding of this connectivity with offset wells helps on defining the distance among the laterals to avoid any potential negative impact during fracturing and production. In Jafurah field, several pads have been used to monitor pressures during the fracturing jobs (crosslinked, hybrids and slickwater) and flowbacks. This provides a unique way of measuring the fracturing network pressures at different distances for the initial life of the wells, starting from the generation of the fracture system up to pressures responses due to the production of offset wells. This paper summarizes the layout and technologies used in a series of pads to understand the connectivity among the wells. Bottom-hole and surface pressures were collected during frac and production in the pads. Also, the outer wells on the pads were monitored from offset contiguous pads. Once the pressure data was synchronized in the different events during fracturing, pressures are plotted to determine the level of pressure disturbance with time. Simultaneously, the absolute values are compared with the minimum stresses, re-opening pressures of natural fractures, and the vertical stresses from the area to determine if the fracture network is reaching the monitor wells and stimulating them. Pressures and derivative behavior are also plotted during the production of the offset wells, to see the level of interference during the initial production, and how the intensity changes as function of time. It was observed in all the pads that pressures in the monitor wells during the fracturing jobs have four periods: 1) no pressure disturbance is observed (compressibility effects); 2) pressure slowly increases up to equivalent minimum stress (closure pressure); 3) pressure continues increasing from the minimum horizontal stress up to re-opening pressure of the natural fracture systems; and 4) pressure stays above the natural frac re-opening pressure but below the vertical stresses (overburden). It can be seen that pressures in the monitor wells present a cumulative effect, suggesting a generation of fracture systems all hydraulically communicating. This paper will present the different levels of interference observed in the pads as a function of frac types, distance to the monitor wells, and existence of hydraulic fracture in the monitor area. The methodology can investigate interference in unconventional wells during the fracturing treatments and production. This approach will help in understanding how the fracture networks in unconventionals grow and connect to other offset wells.
{"title":"Measuring Fracture Network Pressures During Fracturing and Production in Unconventionals in Saudi Arabia","authors":"J. Rueda, J. Valbuena, S. Baki, Karim Mechkak, Mahfouz Mohannad, A. Momin, N. Mulhim","doi":"10.2118/194817-MS","DOIUrl":"https://doi.org/10.2118/194817-MS","url":null,"abstract":"\u0000 There is little understanding on how the fracture networks in unconventional source plays, commonly referred as Stimulated Reservoir Volumes (SRV), grow with distance and time during the fracturing jobs and connect other offset laterals with or without hydraulically created SRVs. Understanding of this connectivity with offset wells helps on defining the distance among the laterals to avoid any potential negative impact during fracturing and production.\u0000 In Jafurah field, several pads have been used to monitor pressures during the fracturing jobs (crosslinked, hybrids and slickwater) and flowbacks. This provides a unique way of measuring the fracturing network pressures at different distances for the initial life of the wells, starting from the generation of the fracture system up to pressures responses due to the production of offset wells.\u0000 This paper summarizes the layout and technologies used in a series of pads to understand the connectivity among the wells. Bottom-hole and surface pressures were collected during frac and production in the pads. Also, the outer wells on the pads were monitored from offset contiguous pads. Once the pressure data was synchronized in the different events during fracturing, pressures are plotted to determine the level of pressure disturbance with time. Simultaneously, the absolute values are compared with the minimum stresses, re-opening pressures of natural fractures, and the vertical stresses from the area to determine if the fracture network is reaching the monitor wells and stimulating them. Pressures and derivative behavior are also plotted during the production of the offset wells, to see the level of interference during the initial production, and how the intensity changes as function of time.\u0000 It was observed in all the pads that pressures in the monitor wells during the fracturing jobs have four periods: 1) no pressure disturbance is observed (compressibility effects); 2) pressure slowly increases up to equivalent minimum stress (closure pressure); 3) pressure continues increasing from the minimum horizontal stress up to re-opening pressure of the natural fracture systems; and 4) pressure stays above the natural frac re-opening pressure but below the vertical stresses (overburden). It can be seen that pressures in the monitor wells present a cumulative effect, suggesting a generation of fracture systems all hydraulically communicating. This paper will present the different levels of interference observed in the pads as a function of frac types, distance to the monitor wells, and existence of hydraulic fracture in the monitor area. The methodology can investigate interference in unconventional wells during the fracturing treatments and production. This approach will help in understanding how the fracture networks in unconventionals grow and connect to other offset wells.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76958628","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}
Plug and Perf (P&P) still remains one of the most prolific methods used in multi-stage hydraulic fracturing operations. Recent changes in the materials chosen to manufacture frac plugs is leading to increased efficiencies during installation as well as the plug milling phase of P&P operations. Historically, the fluid diversion devises used in multi-stage hydraulic fracturing operations have been manufactured using mainly glass/epoxy based composite materials and in recent years, in an effort to increase efficiencies, disintegrating materials. Most efforts have been focused on reducing the amount of metallic parts as well as reducing the overall amount of material used to manufacture these plugs in an effort maintain plug performance during fracturing operations while reducing time/costs during post-frac milling operations by making plug removal more efficient. Recent advances in metallic based composite materials are allowing for plugs to be manufactured out of light weight alloys that are higher strength than traditional composite plug materials while also being easier to remove and circulate out during plug milling operations. Also, because the materials are not designed to disintegrate, there is no need to consider fluids that the plugs will be exposed to thus ensuring a high performance plug without the careful balancing act between an environment that causes the plug to disintegrate too fast or not at all. In addition to this, changes in how slips and packing elements are being designed is allowing for additional gains in efficiencies during plug deployment and removal. Using real-world results, we can now demonstrate how these design changes can allow for a new level of operational efficiencies not previously available in P&P operations.
{"title":"Increasing Efficiencies During Cased Hole Fracturing Operations Through Frac Plug Material Selection","authors":"Beau Wright, Y. Parekh, F CasanovaGabriel","doi":"10.2118/195053-MS","DOIUrl":"https://doi.org/10.2118/195053-MS","url":null,"abstract":"\u0000 Plug and Perf (P&P) still remains one of the most prolific methods used in multi-stage hydraulic fracturing operations. Recent changes in the materials chosen to manufacture frac plugs is leading to increased efficiencies during installation as well as the plug milling phase of P&P operations.\u0000 Historically, the fluid diversion devises used in multi-stage hydraulic fracturing operations have been manufactured using mainly glass/epoxy based composite materials and in recent years, in an effort to increase efficiencies, disintegrating materials. Most efforts have been focused on reducing the amount of metallic parts as well as reducing the overall amount of material used to manufacture these plugs in an effort maintain plug performance during fracturing operations while reducing time/costs during post-frac milling operations by making plug removal more efficient.\u0000 Recent advances in metallic based composite materials are allowing for plugs to be manufactured out of light weight alloys that are higher strength than traditional composite plug materials while also being easier to remove and circulate out during plug milling operations. Also, because the materials are not designed to disintegrate, there is no need to consider fluids that the plugs will be exposed to thus ensuring a high performance plug without the careful balancing act between an environment that causes the plug to disintegrate too fast or not at all. In addition to this, changes in how slips and packing elements are being designed is allowing for additional gains in efficiencies during plug deployment and removal.\u0000 Using real-world results, we can now demonstrate how these design changes can allow for a new level of operational efficiencies not previously available in P&P operations.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"121 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74689658","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}
Point counting is time consuming and requires extensive geologist/petrographer effort. In addition, point counting results are subjective and depend on the petrographer's knowledge and expertise. In this work, we introduce a fully automated workflow for thin section textural analysis in clastic rocks, using high resolution petrographic images of the thin sections acquired with a digital camera mounted on an optical microscope. This innovative workflow reduces the thin section textural analysis turnaround time and provides an objective and consistent analysis. The strength of this workflow resides in its high level of automation, which offers thin section analysis tool in much less time compared to the conventional point counting. The workflow is fully automated to process and analyze the entire thin section without manual involvement. The kernel of this workflow is based on a region growing algorithm for individual grain identification. An iterative loop, built on the top of this kernel, allows the completely automated scan of the entire thin section. The workflow was first rigorously validated for a single thin section. Grain by grain, results from the automated analysis are compared to the petrographer (point counting) analysis. Excellent agreement between the two analyses was obtained (porosity and grain size). The efficiency of the analysis was largely in the favor of the automated approach (3 minutes) compared to the 2 hours needed by the petrographer for this counting exercise (approximately 150 grains). This first validation test proved the workflow's accuracy and the efficiency. This workflow was then extensively validated using large set of thin sections (50 thin sections) showing an excellent qualitative agreement with conventional point counting. This second validation test proved the robustness and the efficiency of the workflow.
{"title":"Advances in Rock Petrography: Image Processing Techniques for Automated Textural Thin Section Analysis","authors":"M. Mokhles, Anifowose Fatai, Masrahy Mohammed","doi":"10.2118/194835-MS","DOIUrl":"https://doi.org/10.2118/194835-MS","url":null,"abstract":"\u0000 Point counting is time consuming and requires extensive geologist/petrographer effort. In addition, point counting results are subjective and depend on the petrographer's knowledge and expertise. In this work, we introduce a fully automated workflow for thin section textural analysis in clastic rocks, using high resolution petrographic images of the thin sections acquired with a digital camera mounted on an optical microscope. This innovative workflow reduces the thin section textural analysis turnaround time and provides an objective and consistent analysis.\u0000 The strength of this workflow resides in its high level of automation, which offers thin section analysis tool in much less time compared to the conventional point counting. The workflow is fully automated to process and analyze the entire thin section without manual involvement. The kernel of this workflow is based on a region growing algorithm for individual grain identification. An iterative loop, built on the top of this kernel, allows the completely automated scan of the entire thin section.\u0000 The workflow was first rigorously validated for a single thin section. Grain by grain, results from the automated analysis are compared to the petrographer (point counting) analysis. Excellent agreement between the two analyses was obtained (porosity and grain size). The efficiency of the analysis was largely in the favor of the automated approach (3 minutes) compared to the 2 hours needed by the petrographer for this counting exercise (approximately 150 grains). This first validation test proved the workflow's accuracy and the efficiency.\u0000 This workflow was then extensively validated using large set of thin sections (50 thin sections) showing an excellent qualitative agreement with conventional point counting. This second validation test proved the robustness and the efficiency of the workflow.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73555180","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}
For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan. A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3. The main objectives of this study are: Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data. The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.
{"title":"Integrating Production and Formation Pressure Testers Analysis for Field Development in Complicated Carbonate Reservoir","authors":"O. Matar, Ahmad Al Janahi, E.A.E. Ali","doi":"10.2118/195032-MS","DOIUrl":"https://doi.org/10.2118/195032-MS","url":null,"abstract":"\u0000 For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan.\u0000 A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3.\u0000 The main objectives of this study are:\u0000 Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data.\u0000 The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74040303","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 present paper is concerned with an experimental study of the acoustic signature of phase inversion in an oil-water mixture system. The system studied was used to correlate the process of phase inversion with the acoustic field generated during the two fluid mixing. The experimental results revealed that the relation between the acoustic fields produced by a water continuous dispersion and the phase inversion has a clear and different signature from an oil-continuous system using a batch mixing system. This dynamical characteristic of the phase inversion phenomenon could be of use in practical systems to detect phase inversion when it occurs based on the acoustic field measured in the subject process.
{"title":"Acoustic Characterisation of Phase Inversion in a Water-Oil System","authors":"Yusuf Ahmed, M. Arsalan, T. Ahmed, M. Noui-Mehidi","doi":"10.2118/194885-MS","DOIUrl":"https://doi.org/10.2118/194885-MS","url":null,"abstract":"\u0000 The present paper is concerned with an experimental study of the acoustic signature of phase inversion in an oil-water mixture system. The system studied was used to correlate the process of phase inversion with the acoustic field generated during the two fluid mixing. The experimental results revealed that the relation between the acoustic fields produced by a water continuous dispersion and the phase inversion has a clear and different signature from an oil-continuous system using a batch mixing system. This dynamical characteristic of the phase inversion phenomenon could be of use in practical systems to detect phase inversion when it occurs based on the acoustic field measured in the subject process.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74157199","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}
Rajeev Kumar, N. Bennett, A. Donald, G. Martinez, E. Velez
Sonic imaging is a technique to obtain a high-resolution acoustic image of the earth formation structures several meters away from the well by utilizing the azimuthal sonic waveforms recorded for extended listening times downhole. The method has been used since the early 1990's to identify subseismic scale features (boundaries, faults, fractures, etc.) by migrating the sonic waveforms into a high- resolution 2D image. Over the past two decades, the sonic imaging in the oil industry has been looked at as a ‘niche’ service. Limitations in acquisition telemetry to handle large datasets downhole and surface software processing capabilities as well as long job turnaround times have meant that sonic imaging service was primarily done on very few wells. Recently, sonic imaging has regained the interest of the community for input to structural modeling along with advancements of higher downhole data transmission capabilities and more powerful processing capabilities. The processing workflow itself, however, has mainly largely remained the same and has consisted of first filtering the sonic waveforms to reduce the interference of the borehole modes and then migrating the filtered waveforms to obtain a 2D image of a well section. Although the 2D image obtained from sonic data is of much higher resolution as compared to other available images such as surface seismic data and vertical seismic profiling (VSP), it does not provide quantitative information on the true dip and azimuth of the acoustic reflectors. With the advancements in the use of borehole resistivity images for geomodeling, the true dip and azimuth information is now essential for fracture characterization and structural geomodeling. We introduce a new technique to obtain reflector location and associated attributes such as true dip and azimuth from fractures, faults, and layering from azimuthal sonic waveform measurements. The technique consists of two main steps. In the first step, an automated time pick and event localization procedures collect possible reflections from filtered waveforms; in the second step, an automatic ray tracing and 3D slowness time coherence (STC) procedure determines the ray path type and a 3D structural map of the reflector, as well as its true dip and azimuth. This technique also provides appropriate parameters for the orientation of the optimum 2D plane to migrate for the traditional image. The new technique enables determining the key parameters of true dip, azimuth, and reflector locations from higher-resolution sonic data required for reservoir evaluation and geomodeling. Direct integration with borehole resistivity images provides an opportunity to build a more accurate single-well structural model for identifying formation dip as well as a near-wellbore connectivity to far-field fractures. This technique has been demonstrated using a case study, where sonic data were recorded in a horizontal well placed in unconventional Wolfcamp formation of North Americ
{"title":"3D Borehole Sonic Imaging for Input to Structural Modeling-A Quantitative Approach","authors":"Rajeev Kumar, N. Bennett, A. Donald, G. Martinez, E. Velez","doi":"10.2118/194810-MS","DOIUrl":"https://doi.org/10.2118/194810-MS","url":null,"abstract":"\u0000 Sonic imaging is a technique to obtain a high-resolution acoustic image of the earth formation structures several meters away from the well by utilizing the azimuthal sonic waveforms recorded for extended listening times downhole. The method has been used since the early 1990's to identify subseismic scale features (boundaries, faults, fractures, etc.) by migrating the sonic waveforms into a high- resolution 2D image.\u0000 Over the past two decades, the sonic imaging in the oil industry has been looked at as a ‘niche’ service. Limitations in acquisition telemetry to handle large datasets downhole and surface software processing capabilities as well as long job turnaround times have meant that sonic imaging service was primarily done on very few wells. Recently, sonic imaging has regained the interest of the community for input to structural modeling along with advancements of higher downhole data transmission capabilities and more powerful processing capabilities. The processing workflow itself, however, has mainly largely remained the same and has consisted of first filtering the sonic waveforms to reduce the interference of the borehole modes and then migrating the filtered waveforms to obtain a 2D image of a well section. Although the 2D image obtained from sonic data is of much higher resolution as compared to other available images such as surface seismic data and vertical seismic profiling (VSP), it does not provide quantitative information on the true dip and azimuth of the acoustic reflectors. With the advancements in the use of borehole resistivity images for geomodeling, the true dip and azimuth information is now essential for fracture characterization and structural geomodeling.\u0000 We introduce a new technique to obtain reflector location and associated attributes such as true dip and azimuth from fractures, faults, and layering from azimuthal sonic waveform measurements. The technique consists of two main steps. In the first step, an automated time pick and event localization procedures collect possible reflections from filtered waveforms; in the second step, an automatic ray tracing and 3D slowness time coherence (STC) procedure determines the ray path type and a 3D structural map of the reflector, as well as its true dip and azimuth. This technique also provides appropriate parameters for the orientation of the optimum 2D plane to migrate for the traditional image. The new technique enables determining the key parameters of true dip, azimuth, and reflector locations from higher-resolution sonic data required for reservoir evaluation and geomodeling. Direct integration with borehole resistivity images provides an opportunity to build a more accurate single-well structural model for identifying formation dip as well as a near-wellbore connectivity to far-field fractures.\u0000 This technique has been demonstrated using a case study, where sonic data were recorded in a horizontal well placed in unconventional Wolfcamp formation of North Americ","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"504 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80061542","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. Lofts, Adrian Zett, P. Clifford, Yaoguo Li, R. Krahenbuhl, A. Seshia
The advantages of measuring gravity in the borehole environment have been well established in the literature and through first-generation instruments. These measurements can be very effective for directly imaging mass distributions at-depth in the subsurface and at large-distances from well bores. To date, a breakthrough has been limited by the sensor form factor (size) and measurement stabilization. Newly emerging MEMS three-axis microgravity technology, deployable by wireline, is showing the potential for a host of applications and capable of realizing the long-coveted advantages. For reservoir surveillance, a primary application is to perform more pro-active, frequent flood front monitoring. With its large volume of investigation, the proposed three-axis borehole gravity measurements would complement as well as fill the existing gap between traditional methods such as Pulsed Neutron and 4D seismic. Further applications extend to saturation monitoring, by-passed pay, and thin-bed identification. In conjunction with a collaborative program to develop a three-axis gravity sensor that is now being incorporated into a 54-mm diameter wireline tool with a targeted sensitivity ≈5 μGal (microGal), we have carried out extensive numerical studies to understand the signal strength of such measurements produced by the dynamic processes in different types of reservoirs, and demonstrate the capabilities and limitations of borehole gravity and its potential use within a revised reservoir surveillance plan. We show examples of forward modelling data from reservoirs with varying fluid displacement mechanisms. Reservoir porosity and saturation data are used to model the predicted three-component (i.e., vector) gravity anomaly (gz, gx, and gy) responses along the wellbore in a variety of wells as the fluid-water front progresses through the field and the modelling included both producing wells and injector wells. The paper will present a description of a forward modeling workflow, simulation studies based on real reservoir data and the validating measurements. The paper examines the results of the forward modelling and compares the results with the target sensitivity of the new three-axis borehole gravity sensor. The results will show that a wireline deployed three-axis gravity tool with a noise floor of ≈5 μGal will provide additional important surveillance to constrain reservoir models. It will also provide vital information to help reduce uncertainty when actively managing waterfront movement (sweep), secondary recovery and for detecting early breakthrough of water; and for monitoring and adjusting strategy when producing through reservoir depressurization. The described workflow is seen as very important for any future survey that planning to understand the time-lapse gravity signal and the feasibility of time-lapse gravity surveillance under different reservoir conditions. A three-axis borehole gravity tool with a form factor enab
{"title":"Three-Axis Borehole Gravity Logging for Reservoir Surveillance","authors":"J. Lofts, Adrian Zett, P. Clifford, Yaoguo Li, R. Krahenbuhl, A. Seshia","doi":"10.2118/194845-MS","DOIUrl":"https://doi.org/10.2118/194845-MS","url":null,"abstract":"\u0000 \u0000 \u0000 The advantages of measuring gravity in the borehole environment have been well established in the literature and through first-generation instruments. These measurements can be very effective for directly imaging mass distributions at-depth in the subsurface and at large-distances from well bores. To date, a breakthrough has been limited by the sensor form factor (size) and measurement stabilization. Newly emerging MEMS three-axis microgravity technology, deployable by wireline, is showing the potential for a host of applications and capable of realizing the long-coveted advantages. For reservoir surveillance, a primary application is to perform more pro-active, frequent flood front monitoring. With its large volume of investigation, the proposed three-axis borehole gravity measurements would complement as well as fill the existing gap between traditional methods such as Pulsed Neutron and 4D seismic. Further applications extend to saturation monitoring, by-passed pay, and thin-bed identification.\u0000 In conjunction with a collaborative program to develop a three-axis gravity sensor that is now being incorporated into a 54-mm diameter wireline tool with a targeted sensitivity ≈5 μGal (microGal), we have carried out extensive numerical studies to understand the signal strength of such measurements produced by the dynamic processes in different types of reservoirs, and demonstrate the capabilities and limitations of borehole gravity and its potential use within a revised reservoir surveillance plan.\u0000 \u0000 \u0000 \u0000 We show examples of forward modelling data from reservoirs with varying fluid displacement mechanisms. Reservoir porosity and saturation data are used to model the predicted three-component (i.e., vector) gravity anomaly (gz, gx, and gy) responses along the wellbore in a variety of wells as the fluid-water front progresses through the field and the modelling included both producing wells and injector wells. The paper will present a description of a forward modeling workflow, simulation studies based on real reservoir data and the validating measurements.\u0000 \u0000 \u0000 \u0000 The paper examines the results of the forward modelling and compares the results with the target sensitivity of the new three-axis borehole gravity sensor. The results will show that a wireline deployed three-axis gravity tool with a noise floor of ≈5 μGal will provide additional important surveillance to constrain reservoir models. It will also provide vital information to help reduce uncertainty when actively managing waterfront movement (sweep), secondary recovery and for detecting early breakthrough of water; and for monitoring and adjusting strategy when producing through reservoir depressurization. The described workflow is seen as very important for any future survey that planning to understand the time-lapse gravity signal and the feasibility of time-lapse gravity surveillance under different reservoir conditions.\u0000 \u0000 \u0000 \u0000 A three-axis borehole gravity tool with a form factor enab","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91255850","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 paper presents a trajectory control and automated directional steering method for drilling operations. The core philosophy behind the trajectory automation and control is a multi-layered primary-secondary based approach in cascade. The complexity of the system increases with additional layers. This methodology improves the overall trajectory control system efficiency when dealing with nonlinearities, delays and uncertainties that are present during drilling as well as dealing with different frequencies of interest. This principle has been previously applied to several operational modes of trajectory automated control for RSS tools (e.g., attitude control with vertical drilling control as a special case). The remaining significant challenges facing trajectory automation include automated kick-off, automatic curve control for geometric and geological steering, and combining them into automated trajectory control by combining the surface and downhole information. This paper presents the next level of directional trajectory automation and control that are currently handled and controlled by the directional drillers [e.g., geometric and geological steering (automated curvature control) as outer (primary) layer to the attitude controller]. The proposed method removes the surface drilling parameters dependencies on the downhole trajectory response. The performance of the curvature controller method has been investigated in virtual field test environment using model-based design process methodology.
{"title":"An Automated Trajectory Control for Drilling Operations","authors":"M. Ignova, Michael Montois, Katharine Mantle","doi":"10.2118/194727-MS","DOIUrl":"https://doi.org/10.2118/194727-MS","url":null,"abstract":"\u0000 The paper presents a trajectory control and automated directional steering method for drilling operations. The core philosophy behind the trajectory automation and control is a multi-layered primary-secondary based approach in cascade. The complexity of the system increases with additional layers. This methodology improves the overall trajectory control system efficiency when dealing with nonlinearities, delays and uncertainties that are present during drilling as well as dealing with different frequencies of interest. This principle has been previously applied to several operational modes of trajectory automated control for RSS tools (e.g., attitude control with vertical drilling control as a special case). The remaining significant challenges facing trajectory automation include automated kick-off, automatic curve control for geometric and geological steering, and combining them into automated trajectory control by combining the surface and downhole information.\u0000 This paper presents the next level of directional trajectory automation and control that are currently handled and controlled by the directional drillers [e.g., geometric and geological steering (automated curvature control) as outer (primary) layer to the attitude controller]. The proposed method removes the surface drilling parameters dependencies on the downhole trajectory response. The performance of the curvature controller method has been investigated in virtual field test environment using model-based design process methodology.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78656665","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}
Zeeshan Tariq, M. Mahmoud, A. Abdulraheem, A. Al-Nakhli, M. Bataweel
The enormous resources of hydrocarbons hold by unconventional reservoirs across the world along with the growing oil demand make their contributions to be most imperative to the world economy. However, one of the major challenges faced by oil companies to produce from the unconventional reservoirs is to ensure economical production of oil. Unconventional reservoirs need extensive fracturing treatments to produce commercially viable hydrocarbons. One way to produce from these reservoirs is by drilling horizontal well and conduct multistage fracturing to increase stimulated reservoir volume (SRV), but this method of increasing SRV is involved with higher equipment, material, and operating costs. To overcome operational and technical challenges involved in horizontal wells multistage fracturing, the alternative way to increase SRV is by creating multiple radial fractures by performing pulse fracturing. Pulse fracturing is a relatively new technique, can serve as an alternative to conventional hydraulic fracturing in many cases such as to stimulate naturally fractured reservoirs to connect with pre-existing fractures, to stimulate heavy oil with cold heavy oil production technique, to remove condensate banking nearby wellbore region, and when to avoid formation damage near the vicinity of the wellbore originated due to perforation. Pulse fracturing is not involved with injecting pressurized fluids into the reservoir, so it is also a relatively cheaper technique. The purpose of this paper is to present a general overview of the pulse fracturing treatment. This paper will give general idea of the different techniques and mechanisms involved in the application of pulse fracturing technique. The focus of this review will be on the comparison of different fracturing techniques implemented normally in the industry. This study also covers the models developed and applied to the simulation of complex fractures originated due to pulse fracturing.
{"title":"A Review of Pulse Fracturing Treatment: An Emerging Stimulation Technique for Unconventional Reservoirs","authors":"Zeeshan Tariq, M. Mahmoud, A. Abdulraheem, A. Al-Nakhli, M. Bataweel","doi":"10.2118/194870-MS","DOIUrl":"https://doi.org/10.2118/194870-MS","url":null,"abstract":"\u0000 The enormous resources of hydrocarbons hold by unconventional reservoirs across the world along with the growing oil demand make their contributions to be most imperative to the world economy. However, one of the major challenges faced by oil companies to produce from the unconventional reservoirs is to ensure economical production of oil. Unconventional reservoirs need extensive fracturing treatments to produce commercially viable hydrocarbons. One way to produce from these reservoirs is by drilling horizontal well and conduct multistage fracturing to increase stimulated reservoir volume (SRV), but this method of increasing SRV is involved with higher equipment, material, and operating costs.\u0000 To overcome operational and technical challenges involved in horizontal wells multistage fracturing, the alternative way to increase SRV is by creating multiple radial fractures by performing pulse fracturing. Pulse fracturing is a relatively new technique, can serve as an alternative to conventional hydraulic fracturing in many cases such as to stimulate naturally fractured reservoirs to connect with pre-existing fractures, to stimulate heavy oil with cold heavy oil production technique, to remove condensate banking nearby wellbore region, and when to avoid formation damage near the vicinity of the wellbore originated due to perforation. Pulse fracturing is not involved with injecting pressurized fluids into the reservoir, so it is also a relatively cheaper technique.\u0000 The purpose of this paper is to present a general overview of the pulse fracturing treatment. This paper will give general idea of the different techniques and mechanisms involved in the application of pulse fracturing technique. The focus of this review will be on the comparison of different fracturing techniques implemented normally in the industry. This study also covers the models developed and applied to the simulation of complex fractures originated due to pulse fracturing.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83056567","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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