SPWLA HAHZ SIG 2025 Workshop 2
About
Welcome to SPWLA HAHZ SIG's Workshop for 2025.THIS EVENT IS A VIRTUAL EVENT, ATTENDANCE WILL BE VIA TEAMS MEETING
WORKSHOP 2 will be hosted online to correspond with Americas Time Zone.
Thursday 6th November, 9am Houston, 4pm Paris, 7pm Dubai, 11pm Singapore
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WORKSHOP 2 PRESENTERS:
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Ahmed Taha, Haliburton - Understanding Lateral Permeability Variations in Heterogeneous Carbonate Reservoirs Using Logging-While-Drilling NMR, Microresistivity Imaging, and Azimuthally Oriented Formation Testing
Alexei Bolshakov, Chevron - Understanding Acoustic Responses in Horizontal Wells: Tools, Techniques, and Lessons Learned
Brendon Negenman, Haliburton - Dipole Sonic Imaging Case Study and Analysis to Estimate Structural Dips for Deviated Well
Haijing Wang, Chevron - Drill Bit Walk and Near-Wellbore Heterogeneity Illuminated by Azimuthal Gamma Ray While Drilling into Hard and Interbedded Formations Along Unconventional Horizontal Wells
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ABSTRACTS:
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Understanding Lateral Permeability Variations in Heterogeneous Carbonate Reservoirs Using Logging-While-Drilling NMR, Microresistivity Imaging, and Azimuthally Oriented Formation Testing
Ahmed Taha, Haliburton
Permeability is a fundamental petrophysical attribute required to accurately evaluate recoverable reserves and design an appropriate field-development strategy. Because logging tools do not measure absolute permeability, minimizing uncertainty in the evaluation of log-derived permeabilities remains one of the most critical petrophysical challenges in the oil industry. Horizontal development in laterally heterogeneous carbonate reservoirs also requires evaluation of lateral permeability variations to optimize completion design while maximizing reservoir exposure via precise well placement in real time. This paper demonstrates innovative methods to evaluate lateral permeability variations in heterogeneous carbonate reservoirs.
The workflow for log-derived permeability predictions is based on empirical relationships using nuclear magnetic resonance (NMR) and high-resolution imaging tool measurements. These are normalized in an integrated multidisciplinary approach using core, well test, production logs, and formation-tester mobility data where available. Traditionally, formation-tester tools have been used to obtain single-pressure and mobility values at each test station. The logging-while-drilling (LWD) formation tester can be oriented azimuthally to help evaluate permeability anisotropy, which is a key factor for reservoir characterization in laterally heterogeneous reservoir layers. The oriented data can also be used to adjust the well plan in real time to maximize reservoir exposure in the desired “sweet spot.”
Variations in the oriented LWD formation-tester measurements at each depth station exhibited favorable correlations to azimuthal changes observed in the LWD high-resolution microresistivity image. Detailed image analysis further helped to understand the mechanism that governs the azimuthal permeability profile. The combination of oriented LWD formation-tester and highresolution image data also aided in making better realtime geosteering decisions, as well as in the planning and design of a future field-development program within the local reservoir sector. Operational considerations to maximize data quality rely on an optimized bottomhole assembly (BHA) design, accurate depth control, and robust orientation techniques based on best practices and lessons learned.
This paper presents an integrated approach for well placement and an improved understanding of flowunit characterization via the first-time use of oriented formation-tester data in conjunction with corresponding high-resolution images in a laterally heterogeneous reservoir.
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Understanding Acoustic Responses in Horizontal Wells: Tools, Techniques, and Lessons Learned
Alexei Bolshakov, Chevron
This presentation evaluates acoustic open-hole logging in a horizontal well, highlighting key differences from vertical wells and lessons learned from the operator’s perspective. It focuses on how nearby beds, fractures, faults, and anisotropy affect acoustic signal interpretation, emphasizing the need for integrated well data analysis.
Using azimuthal gamma ray, resistivity imaging, triple combo, and nuclear spectroscopy logs, we analyze compressional, shear, cross dipole, and Stoneley waves. We assess tool properties, acquisition parameters, and logging conditions like stick-slip, offering strategies to improve data quality.
Findings reveal distinct acoustic signatures in horizontal wells and demonstrate how optimized logging practices enhance interpretation accuracy and formation evaluation in complex environments.
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Dipole Sonic Imaging Case Study and Analysis to Estimate Structural Dips for Deviated Well
Brendon Negenman, Haliburton
Introduction:
One of the key advantages of dipole sonic data is the ability to look away from the borehole and provide high resolution images to identify structural features that may not be observed on borehole imaging logs or seismic images. Depending on the velocity of the formation & listening time of the record, radial distance of image can range from 60--250 plus feet. In addition, analysis from dipole sonic data can be used to quantify dip interpretations estimated from OH logs. Objectives of this paper are to show analysis techniques using dipole sonic image data that provide an estimate of dips over the well interval. The goal is also to show the value of dips extracted from the data without having to image it.
Methods, Procedures, Process:
An additional challenge of analysing dipole sonic image data is interpreting and integrating results with supplementary data. The first part of the analysis was to look at reflection moveout of the isolated down & upgoing reflections. Signal processing techniques were applied to the data to remove noise (direct wave) and to correct for amplitude losses. By measuring moveout of the reflected events, apparent velocities were estimated from the data. This analysis helps to identify possible zones with reflections coming back from the formation, as their apparent velocity is faster than energy travelling along the borehole. Using this estimated dip information from apparent velocity, 2D velocity models in depth were built using the sonic log slowness values converted to velocity. Depth migrations were performed on the data and then a statistical analysis was done to calculate dips from the imaged features. The analysis also provides the semblance of the dips as a measure of confidence.
Results/Observations:
The estimated apparent velocities show strong peaks between dipping formation scenarios for 50 and 60 degrees (dip relative to well). This result was used to build a 2D velocity model, and to define the size of the model to optimize running efficiency. Imaging quality is high and shows reflections with radial coverage up to ~60 ft away from the wellbore. The migrated image is a stack of all 13 receivers recording a dipole oriented near the horizontal plane. Part of the dip scan plots red quivers on the data to improve identification of linear features. Estimated dip data can then be plotted with depth to estimate an average over the entire well interval.
Semblance is also calculated to weight the confidence of each pick.
Conclusions
Case study shows that estimates of event dip can be calculated from dipole sonic data without having to image it by measuring the apparent velocity of reflected events in the recordings. This saves time as more sophisticated
imaging algorithms can take long to run and require extensive computing resources. Depth migrations using a 2D velocity model were output and provided geological dip information away from the borehole. True dips calculated from depth migrated image data showed the same trend as seen from first dip estimates using the velocity scan method. These dips were calculated over the well interval and can be output in a csv format to easily load into petrophysical & geological databases for future analysis.
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Drill Bit Walk and Near-Wellbore Heterogeneity Illuminated by Azimuthal Gamma Ray While Drilling into Hard and Interbedded Formations Along Unconventional Horizontal Wells
Haijing Wang, Chevron
Drilling horizontal wells in a safe and reliable manner is critical to the economic and efficient development of unconventional reservoirs. Local geology, if not fully understood, is a trigger of many drilling incidents, often leading to non-productive time and cost overruns. Encountering hard interbedded laminations along the lateral section can negatively impact drilling operations by reducing drilling rates, causing high localized doglegs, damaging bits, and requiring excessive steering corrections to penetrate or extricate the bit from the horizon. These geological features are below the seismic resolution and become unpredictable further away from the well-characterized pilot well. Standard long-spaced stationary surveys and non-azimuthal gamma rays (GR) are not adequate to characterize the geological features and doglegs along horizontal wells and quantify their impact or to improve drilling performance.
Most logging along horizontal wells is based on measurement-while-drilling (MWD) systems that are intended primarily for geosteering purposes. MWD data, such as azimuthal GR and continuous survey, are used in post-drill analysis to better understand geological features and assess their impact on drilling performance. Azimuthal GR measures GR around the circumference of the borehole that indicates both near wellbore lithologies and relative wellbore position to the nearest beds. Continuous survey provides detailed borehole deviation and azimuth to reduce the uncertainty of wellbore depth and position. Both measurements can be transmitted in real time and recorded in memory depending on MWD transmission bandwidth, compression algorithm, and rate of penetration (ROP).
Here we combine azimuthal GR and continuous survey measurements in the post-drill analysis of an unconventional horizontal well. The local geology is featured with significant cyclicity between soft shale and hard carbonate. We observed significant bit walk as the drill bit interacts with hard formations: the drill bit drops inclination and turns left when encountering a hard formation above the drill bit; the drill bit builds inclination and turns right when encountering a hard formation below the drill bit. The well later encountered a hard structure below the BHA, resulting in a significant bit deflection to the right and inclination build. Such encounters cause additional bit wear and wellbore tortuosity. By utilizing additional data, the hope is to reduce the number of incidents and improve drilling performance.
Total GR has been the primary input for evaluating lithology variation along the lateral. However, a key consideration has been missing: the up- and down-GR can differ significantly from the total GR as the BHA is at the interface of two formations. An interface between shale and carbonate could appear to be sand according to total GR. This shows the significance of azimuthal GR, not only for geosteering but also for post-drill analysis and formation evaluation. Combination of MWD data with drilling parameters is critical not only to understanding downhole BHA behavior, but also to the characterization of local geology. The knowledge accumulated from post-drill analysis can significantly reduce subsurface uncertainty and benefit real-time decision making for future drilling.
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