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Collaborating Authors
wellbore
Summary In the placement process of the cement slurry, treatment fluids such as the spacer are pumped ahead of the cementitious slurry to minimize the contamination of the slurry by drilling fluid and ensure superior bonding to the casing and formation. The spacer discussed in this work can harden with time and act as a settable spacer. This characteristic can be an advantage for well integrity if some spacer pockets are left in the annulus. Rheological compatibility of different mixtures of the spacer with oil-based drilling fluid (OBDF) has been studied using a rheometer, and the resulting R-factor, which indicates the degree of compatibility between fluids, has been calculated. An increase in the flow curve was observed for the mixture of the fluids. However, based on the R-index, these fluids are compatible with displacement in the wellbore. A nonionic surfactant, typically used in conventional spacers acting as an emulsifier and a water-wetting agent, was used in the hardening spacer design. The results show that the addition of OBDF to hardening spacer containing surfactant can increase viscoelasticity. Hardening spacer containing surfactant can successfully reverse the OBDF emulsion. By performing a small-scale mud displacement experiment, we observed that surfactant can improve the wall cleaning efficiency of the spacer while having minimal impact on the bulk displacement.
- Europe (1.00)
- North America > United States > California (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Summary Understanding gas dynamics in mud is essential for planning well control operations, improving the reliability of riser gas handling procedures, and optimizing drilling techniques, such as the pressurized mud cap drilling (PMCD) method. However, gas rise behavior in mud is not fully understood due to the inability to create an experimental setup that approximates gas migration at full-scale annular conditions. As a result, there is a discrepancy between the gas migration velocities observed in the field as compared to analytical estimates. This study bridges this gap by using distributed fiber-optic sensors (DFOS) for in-situ monitoring and analysis of gas dynamics in mud at the well scale. DFOS offers a paradigm shift for monitoring applications by providing real-time measurements along the entire length of the installed fiber at high spatial and temporal resolution. Thus, it can enable in-situ monitoring of the dynamic events in the entire wellbore, which may not be fully captured using discrete gauges. This study is the first well-scale investigation of gas migration dynamics in oil-based mud with solids, using optical fiber-based distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). Four multiphase flow experiments conducted in a 5,163-ft-deep wellbore with oil-based mud and nitrogen at different gas injection rates and bottomhole pressure conditions are analyzed. The presence of solids in the mud increased the background noise in the acquired DFOS measurements, thereby necessitating the development and deployment of novel time- and frequency-domain signal processing techniques to clearly visualize the gas signature and minimize the background noise. Gas rise velocities estimated independently using DAS and DTS showed good agreement with the gas velocity estimated using downhole pressure gauges.
- North America > United States > Texas (0.68)
- Europe (0.68)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.93)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.51)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.35)
Abstract This paper describes a proposed high-specification standard format that is ideally suited for the data management of definitive records of wellbore logs. For this reason, it is a good standard for data exchange between applications. The format is suitable for complex three-dimensional (3D) data, including those generated by deep azimuthal resistivity (DAR) and ultradeep azimuthal resistivity (UDAR) tools, acoustic borehole reflection images, vertical seismic profiles (VSP), borehole imaging tools, multifingered caliper logs, and array data with multiple depths of investigation. It is applicable for use with logging-while-drilling (LWD) and wireline-conveyed logging tools. The format also naturally collapses down when utilized to store simple conventional logs that contain one value per depth in the wellbore. The proposed format provides spatial details of every data point collected by or interpreted from a wellbore-logging tool. The position of each data point is defined by reference back to the measure point of the sonde, which in turn is defined by the wellbore deviation survey and its coordinate reference system (CRS). Each data point in space may have an unrestricted number of parameters. An example might be most likely horizontal and vertical resistivity, maximum value based on uncertainty, minimum value based on uncertainty, and flags indicating the data position with respect to depth of detection (DOD). The new proposed format is so versatile. It is suitable as an Open Group Open Subsurface Data Universe (OSDU) standard to store and exchange all data measured by logging tools in a wellbore and can possibly be extended to include all well data (for example, core, cuttings, and more). The proposed format requires a detailed definition so that computer scientists can implement it in applications used for subsurface modeling. The OSDU will also require this detailed definition in order to adopt it as a standard.
Gravity drive is simply like draining a tank. Gas drive depends on the expansion of the gas in a reservoir to provide the driving energy; the pressure is reduced as the reservoir is produced. Solution gas drive depends on gas coming out of solution in the oil as the pressure is reduced. Water drive depends on water pressure to force hydrocarbons into the wellbore, and depends on the connectivity of the reservoir with a surrounding aquifer. Water drive is much more efficient at driving oil than is gas drive.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
When interpreting seismic or well data in desktop software, it's easy to forget that the data are discretely sampled in space and time. Even when you look at an apparently continuous log curve, there are really only samples, typically every 0.1524 m (6 inches). When you display seismic data as wiggle traces, there are perhaps samples only every 2 or 4 ms in the time dimension. Some software lets you turn off the interpolation so you can see the discrete data samples, as in Figure 1a. So what happens when we want to read the amplitude from a seismic trace, but we are between two samples?
- Information Technology > Knowledge Management (0.50)
- Information Technology > Communications > Collaboration (0.40)
Schlumberger introduced the compensated dual resistivity (CDR) tool which allowed log data to be transmitted up the wellbore by mud pulses.[1] Storage devices at the bottom of the drillstring allow the driller to retrieve raw data when the bottom hole assembly (BHA) is pulled. The CDR tool uses a 2-MHz electromagnetic wave to measure the difference between phase shift and amplitudes measured downhole.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Information Technology > Knowledge Management (0.50)
- Information Technology > Communications > Collaboration (0.50)
Borehole geophysics is an aspect of geoscience that deals with the vertical analysis of the conditions of the subsurface and its fluid content. It is the technique employed in order to have a firsthand well evaluation in the exploration for hydrocarbons. One of the main results of Borehole Geophysical experiment is the Time to Depth relation curve. This curve can be used to generate an accurate calculation of interval, RMS and Average velocities. Those velocities helps us to relate our Seismic in Time to actual Geology in Depth.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Carlos Torres-Verdín is receiving this award for his body of work in advancing the science of exploration geophysics, especially in the preceding five years. He has made significant contributions in developing new methods in applied electromagnetics, physics-based understanding of fluid flow from borehole measurements, and new laboratory results for quantifying fluid transport in shale. Most recently, Carlos has extended his theoretical work to application in industry. This includes the development of new methods for modeling, processing, and interpreting borehole measurements in nonvertical wells and the geostatistical inversion of well-log and surface seismic data for reservoir description. His work on these topics continues to be on the leading edge of seismic technology.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract Multi-stage, multi-well completions cause pore-pressures to increase around each stage treated, compound from earlier offset treatment stages, then dissipate as the injected fluid leaks off into the rock formation. Rock stresses change in a dynamic fashion from virgin reservoir stress to an altered stress influencing subsequently treated stages which can restrict slurry propagation from these injections into regions experiencing excess stress. Stress shadows are time-dependent and dissipate over time and return to the virgin stress state. Microseismic focal mechanisms detected from a high-fold wide azimuth surface array can be used to observe and calculate stress changes in the reservoir and constrain the time it takes for stresses to return to the virgin reservoir state. Operators can take advantage of stress changes and contain fractures close to the stages by building stress wedges around subsequently treated stages. After stress dissipates fluid propagates into previously opened fractures leading to poor fracture containment. In this paper, we review the effects of time-dependent stress shadows on multi-well completions in the Wolfcamp Formation in Southeast New Mexico. Then radioactive tracer data from the Niobrara Formation in the Denver-Julsburg basin is analyzed to provide further verification of the time-dependent process. Increased stresses from previous treatments remain elevated for ∼7 days which push fluid injected on neighboring wells away from the stress shadow. Production of well-specific tracer corroborates the hypothesis that local stress-shadows are elevated for ∼7 days which can push fluid from subsequent neighboring wells. After stresses dissipate through the fractures created during the initial stimulation, new tracer on offset wells was produced as much as 3,000 ft away on a neighboring well. Introduction Microseismic monitoring is a proven technology for observing and mapping reservoir response to hydraulic fracture stimulations. The event radiation pattern of the P-wave first arrival reveals advanced characteristics of the fracture describing deformation at the source location when detected using a high-fold wide azimuth surface array. The full-moment tensor can be generally decomposed into the relative percentages of isotropic, double couple and compensated linear vector dipole components (e.g. Aki and Richards, 1980) which fully describes the failure process in terms of volume change, amount of shearing, and other complexities related to deformation. The local stress field can be calculated using a set of focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors (Angelier, 1989) where the local stress field extent is defined by the spatial extent of the observed focal mechanisms. The local stress field orientation and relative magnitude can be resolved for a group of microseismic focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors for the subsets using a method described by Vavrycuk, 2014.
- North America > United States > New Mexico (0.55)
- North America > United States > Texas (0.35)
- North America > United States > Wyoming (0.34)
- (3 more...)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (7 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
Abstract The main objective of this paper is to present a thermo-hydrodynamic 3D modeling approach for interpreting temperature surveys in horizontal wells with multiple fractures. The scope of the study includes predicting detailed homogeneous flow patterns in the porous matrix, fractures, and flow geometry inside smart completions. The model aims to provide 3D distributions of pressure and temperature along the horizontal wellbore, enabling quantitative flow analysis in liner, annulus, sandface, and each fracture. The 3D thermo-hydrodynamic modeling approach utilizes a grid covering the wellbore and the reservoir domain, considering the entire production/injection history. Advanced thermal and hydrodynamic equations are employed to describe physical processes in the reservoir, wellbore, and fractures. The scientific approach enables the model to quantify flow in various configurations, such as radial flow around the wellbore, semi-spherical flow at the toe and heel, and linear flow towards fractures, leading to improved accuracy and capabilities for reservoir production control. The 3D thermo-hydrodynamic modeling approach has been successfully applied in horizontal injectors and producers. A "blind" comparison to industry-standard PLT measurements and other temperature modeling products evaluated accuracy, thresholds, advantages, and limitations. The model matched PLT well in wellbore flow rates. In challenging cases, it depicted reliable reservoir flow profiles with complex flow paths, including annular flows, flows behind the casing, and swell packer failures. The model's quantitative assessment capability presents new opportunities for predicting diverse flow patterns in horizontal wells, advancing reservoir and fracture performance understanding. The 3D thermo-hydrodynamic modeling approach is of paramount importance in the oil and gas industry. By predicting flow patterns in horizontal wells with multiple fractures, the model offers valuable reservoir management insights. It surpasses conventional logging techniques, addressing limitations in detecting crossflow, high thresholds, and challenges with high viscosity fluids. The model's novelty lies in its comprehensive methodology, simulating 3D pressure and temperature distributions along the wellbore. Quantitative flow analysis in liner, annulus, sandface, and each fracture revolutionizes the industry. Successfully applied in horizontal wells with multi-stage hydraulic fractures, it enhances reservoir performance control and production efficiency.