bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delineating Karsts, Small-Scale Faults, and Fractures by Using a Global Stratigraphic Framework to Integrate Conventional Seismic Attributes with Diffraction Imaging in a Giant Offshore Field, Abu Dhabi.
Authors: Goraya Yassar , Felasi Ali Al , Daynac Nicolas , Walley Stuart , Dupont Marc-Antoine , Inoue Hiroyuki , Mubarak Al Khamiri Ahmed , Hindi Alia Hasan 
Published: October 2022

Abstract
Poor resolution and signal-to-noise ratio have often been key factors impacting an interpreter’s ability to directly delineate subsurface features from seismic data. Improvements in full azimuth, high-density acquisition and in diffraction imaging, have the potential to reveal greater subsurface detail. To date, the application of diffraction imaging has in part been limited by the methods available to parse and analyze that same data. For instance, visualization of diffraction images on time and or depth slices may show patterns, but as these slices can cut through successive seismic reflectors, they tend not to be geologically meaningful. An approach is described that uses machine automation to rapidly incorporate diffraction images into a full-volume 3D seismic interpretation. Delineation of key stratigraphic surfaces is driven by stacking patterns and stratigraphic terminations and performed in both structural and Wheeler domains. Stratal slicing is a highly flexible and rapid method of generating chronostratigraphic surfaces. These chronostratigraphic surfaces can be extracted at sub-sample resolution and therefore accurately matched to well log responses which typically fall well below the resolution of a seismic dataset. The diffraction image is then projected onto a series of chronostratigraphic surfaces, allowing the interpreter to parse through and compare diffraction data directly with conventional seismic attributes at the same chronostratigraphic layer. The novel approach described has been used to demonstrate both the value of diffraction imaging and the importance of using a global full volume 3D seismic interpretation when identifying features such as karsts and small-scale faults and fractures. When applied to a recently processed high-density wide azimuth seismic survey, the workflow was able to seamlessly integrate diffraction images to provide improved confidence in the delineation of karsts and other collapse features that can pose a drilling hazard within the Giant Field, offshore United Arab Emirates.
Subtle Fault Prediction Technique Based on the Integration of Deep Learning and Seismic Spectral Decomposition
Authors: Qiang Li , Xin Chen , Dengyi Xiao , Min Zhao , Qunli Qi , Jianfang Yang , Xiaoliang Li , Bo Peng , Fuli An , Bo Wang , Xiaoli Gao , Chen Yang 
Published: October 2022

Abstract
Faults often control the movement and aggregation of oil and gas. With the development of oil fields, the role of subtle faults is becoming more and more important. The accuracy of fault interpretation directly affects the direction of exploration and development. However, due to the limitation of the seismic resolution, it is hard to identify these faults according to routine methods such as coherence, variance, curvature, etc. To overcome such kind of challenge and better match the demand for fine fault identification, a method integrated deep learning and spectral decomposition was proposed.
Elimination of Pilot Hole and Successful Landing in Sweet Zone Using Ultra-Deep Resistivity Mapping in a Mature Field of Kuwait: Case Study
Authors: Rane Nitin , Al-Duraia Ebraheem , Bojarahs Khalid , Mudavakkat Anandan , Dashti Reham Abbas H , Hassan Jassim Mohammad , Al- Khaldy Ali D , Hassan Abdulaziz , Al-Hindi Khalid Ali , Al-Attar Tarek Fathy , Alhajri Nasser F. , Farhi Nadir , Kharitonov Alexander , Samie Mohamed , Clarion Benjamin , Abdulkarim Anar 
Published: October 2022

Abstract
The Great Burgan reservoir is the largest sandstone oilfield in the world, it has been developed and produced since the 1930s. Historically developed through deviated wells, a new project of horizontal wells was initiated recently to produce from the UB3 reservoir unit. A pilot hole is usually required to identify the presence of productive sublayers and the depth of the oil-water contact (OWC), which must be avoided in the horizontal section. Elimination of the pilot hole would help to minimize the time and cost of development (Al Khalifa et al. 2020).
The azimuthal ultra-deep resistivity mapping service (UDR) has proven its capability to eliminate the need for pilot holes by mapping reservoir boundaries and OWC on the fly, earlier than with traditional methods. This facilitates real-time geosteering to land the well in a single drilling run in the productive zone. Additionally, it helps to reduce non-productive time by making it easier to stop drilling and set casing above a target layer and to help optimize future well planning in field development.
A feasibility study performed on offset wells showed promising potential from application of this method in the UB3.
Real-time UDR geomapping detected multiple thin sand lenses on top of UB3 but showed that they were not of commercial capacity. The decision was made to continue drilling deeper for a larger sand layer. The UDR detected a massive sand below the smaller lenses and the well was landed in it. Early mapping also helped to optimize the landing with the desired inclination and dog-leg severity. The OWC was detected ~35 ft TVD below the landing point.
Without UDR it would have been impossible to detect the OWC and very challenging to perform an accurate landing. The target could have been missed by landing either too shallow or too deep or with the wrong inclination.
Following the landing of the well the lateral section was drilled through upper and lower lobes of the massive sand with a total cut of 1649 ft MD. This comprised 450 ft MD of upper lobe, 350 ft MD of transition interval, and 637 ft MD of lower lobe inside BU3, with an average porosity of 30 p.u. and a water saturation of less than 10%. Formation pressure tests measured mobility of up to ~3.4 D/cp.
This case study demonstrates that utilization of the ultra-deep resistivity mapping service enabled a new approach to drilling lateral wells in the Burgan field development, improving reservoir insight and reducing well drilling time and cost.
Geomechanical Modelling to Identify Sub-Seismic Faults and Fractures Characteristics Using Elastic Dislocation (ED) Theory: A Case Study from Potwar Foldbelt, Upper Indus Basin (UIB) of Pakistan
Authors: Khan Imran , Ahmad Shakeel , Shahzad Rana Faisal , Qureshi Muhammad Akram , Khan Zahoor , Ahmad Shabeer , Awan Uzair Hamid 
Published: October 2022

Abstract
The study will address the failure reasons of wells and point out the high-density fracture zones, to drain out the remaining hydrocarbons in the field. A robust 3D geological model was developed based on 3D seismic interpretation. The rock mechanical properties of carbonates were incorporated. The total strain i.e., the background or remote strain (Bulk deformation) and the strain from displacement along the fault surfaces are mapped to each segment/element of the generated fault surfaces. This total strain calculates stresses and the failure for deformation surface. The geomechanical model based on Elastic Dislocation (ED) theory identified strain fields on horizon surface / observation grids and then finally fractures corridor and their characteristics i.e. distribution, orientation.
Fault planes generated from interpretation play a major role in the ED method for fracture analysis. The fault surface consists of an array of panels, each contributing to the ED equation calculation. The main outcome is the sub-seismic faults and fractures identification around larger faults on the horizontal observation medium. The identified fractures corridors characteristics, distribution and orientation changes along the strike of the major fault system. In the developed ED model the predicated fractures system are parallel to the major reverse fault direction, but oblique fractures corridor is also observed along the middle segments, aligning with observed variations in structure dip. The crestal portion of the anticline has a higher density of fractures than the rim.
The ED modelling fractures results were verified against FMI data of the targeted horizon, which demonstrated that the wells which were drilled in high-density fracture zones (modelled) have produced hydrocarbons and vice versa. There is a correlation between modelled results with image logs and well-testing results (DST's), which increases the reliance on the ED theory's ability to correctly identify small-scale (sub-seismic) fractures, joints and faults system.
The Eocene carbonate reservoirs have low primary porosity and permeability. The productivity of these reservoirs is dependent on permeable natural fractures and sub-seismic faults. The identification of these features is a major problem before drilling while, conventional techniques do not provide optimum solutions to their understanding. A case study of compressional tectonic regime in Himalayan fold & thrust belts is presented here, where an integrated approach is applied in the form of geomechanical modelling, which is built on the ED theory provide a reliable base for well planning.
Time-Lapse Walkaway VSP Analysis Using Advanced 4D Attributes to Monitor CO2 WAG EOR Pilot in a Carbonate Field Onshore Abu Dhabi
Authors: Mohamed Moza , Humphries Mary , Waqas Muhammad , Ahmed Jahan , Ofowena Frank , Alhamedi Aysha , Bailey James 
Published: October 2022

Abstract
Reservoir monitoring is a key initiative for efficient management and development of hydrocarbon reservoirs. Time-lapse feasibility studies are available in literature, however; actual time-lapse seismic surveys are very limited in Abu Dhabi.
A time-lapse Walkaway Vertical Seismic Profile (VSP) was acquired as part of the reservoir monitoring plan during a Water Alternation Gas (WAG) Enhanced Oil Recovery (EOR) pilot in an onshore carbonate field in UAE. The purpose of the study is to monitor the injected fluid in the reservoir. A 4D feasibility study predicted saturation changes &gt;50% after 6 years of water and CO2 injection resulting in &gt;10% change in reflection amplitude. Time-lapse Pulsed Neutron logs showed saturation changes of about 25% for both water and CO2 after 3 years of injection.
Walkaway VSP survey design was performed but in practice optimum receiver depths could not be achieved due to well tubing resulting in reduced lateral image extent. Three surveys were recently acquired: Baseline survey after 6 months of CO2 injection, Monitor-1 after 6 months of water injection and Monitor-2 after 3 years of WAG injection.
The surveys achieved excellent data quality. There were some small inconsistences between all the surveys that were revealed and partially resolved during detailed parallel pre-image re-processing of the three datasets. 4D image attribute analysis recovered a subtle time-lapse response. The time-lapse response was compared to the observed CO2 and water saturation differences and some correlation was observed. Further modeling is required to investigate these small observed differences. Future monitors will take into account lessons from these surveys.
It is hoped that this study will provide confidence to operators for deployment of borehole seismic survey technology for future time-lapse monitoring in carbonate reservoirs. Workflows applied in this study will provide a reference point for future geophone or fiber VSP surveys for 4D monitoring. This study also highlights significance of source consistency and quality control that should be performed at wellsite during acquisition.
Determination of Caprock Porosity and Permeability Using Drill Cuttings and Core Samples of a Potential CO2 Storage Site – A Case Study
Authors: Sazali Wan Muhammad Luqman bin , Busch Andreas 
Published: October 2022

Abstract
Carbon capture and storage (CCS) provides a safe option to reduce carbon footprint on a large scale. Here, carbon dioxide (CO2) is stored in a reservoir formation, overlain by a seal with low permeability and high capillary entry pressure. Understanding CO2 migration through the seal is one of the main components to assess caprock integrity, thereby ensuring safe and long-term CO2 containment and storage. This research is a combined and detailed study of caprock porosity and permeability using core and well log data to overcome a major issue: Coring and logging operation are expensive, and rarely done in caprocks. Drill cuttings, however, are available as byproduct of all drilled wells. By studying the caprock porosity and permeability of a potential CO2 storage site, this study aims to develop porosity/permeability relationships which can be used as input to predict matrix migration and capillary leakage to ensure permanent storage of CO2. In this paper, drill cuttings and core samples, which were obtained from a potential CO2 storage site, went through a series of laboratory measurements to determine porosity and permeability. This includes mercury injection capillary pressure (MICP), unsteady state pulse decay permeability on plug samples, and poro-permeameter measurements on crushed samples. Preliminary results have shown that drill cuttings produce higher porosity and permeability values than core samples. Nevertheless, further analysis is needed to establish relationships and correlations between drill cuttings and core samples. By applying a multi-method approach, resulting in trends for porosity and permeability, we may be able to reduce the operational costs of coring by using drill cuttings as alternatives and at the same time help de-risking CO2 storage projects for wider scale of deployment.
Spending Less and Getting More: Impact of 3D Seismic Processing and Inversion in an HPHT Carbonate Field Development With Only Single Well & Legacy 3D Seismic
Authors: Lai Chee Leong , Choo Matthew , Fahmi Fariz 
Published: October 2022

Abstract
This paper will focus on a High-Pressure High-Temperature (HPHT) carbonate gas field in Central Luconia, Field X, offshore Sarawak, Malaysia. Discovery of field X was made based on a 2009 3D legacy Pre-Stack Time Migration (PreSTM) seismic data and an exploration well drilled in 2013. The main challenge for this field is to move from the exploration phase into the field development phase, without acquiring additional seismic or well data. One of the ways forward, is to extract new information via seismic data reprocessing. The reasons for this are the cost of seismic reprocessing is marginal compared to drilling an appraisal well and there is significant improvement in the seismic processing and seismic inversion technology over the last decade. Full Waveform Inversion (FWI), combined with other latest processing technology, are the key workflows in this seismic reprocessing that determines the quality of the results. A quantitative interpretation (QI) study was subsequently performed to conclude the seismic study and enhance reservoir understanding in preparation for field development planning.
FWI Using Reflections in Shallow Waters Offshore Abu Dhabi
Authors: Hermant Olivier , Khakimov Oleg , Barajas Carlos , Hutahayan Bastian , Mahgoub Mohamed , Cambois Guillaume 
Published: October 2022

Abstract
The Arabian Gulf near-surface geology is complex, with extremely shallow waters and a hard water bottom generating high amplitude short period multiples and thinly bedded high and low velocity layers creating high apparent anisotropy in the bandwidth of seismic surveys. Obtaining an accurate description of the velocity variations in the near-surface and at intermediate depths is a necessity for reliable imaging and positioning of the reservoir layers located underneath. We propose a two-step full-waveform inversion (FWI) of ocean-bottom node (OBN) seismic data from offshore Abu Dhabi. We update a velocity model, using both diving and reflected waves, to reach the required depth of penetration.
FWI has become an industry standard for velocity model building. However, due to the oscillatory nature of seismic data, FWI is known to be subject to cycle-skipping, where the inversion process falls into a local minimum. This risk is mitigated by using an accurate enough initial model and the use of low frequencies. In the shallow waters of offshore Abu Dhabi, near-offset data suffer from strong mud-roll and guided-wave energy that are not properly modeled with acoustic FWI. We exclude these offsets from the input data and use diving waves, starting at 3.5Hz, to update the near surface.
The diving waves penetration is limited to approximately one kilometer in this area and corresponds to the base of a shallow high velocity layer. To reconcile the kinematics of reflected waves, travelling mostly vertically and used for imaging, and diving waves, travelling mostly horizontally, and used in the velocity update, we need an accurate estimation of the anisotropy. This is obtained using Backus averaging from available well logs.
For deeper updates, the data are processed to remove the mud-roll and guided wave energy. This allows for the inclusion of reflections and near offsets. The FWI update is performed to 10Hz and penetrates about 3km into the sub-surface.
We applied this FWI workflow to a recent node survey acquired offshore Abu Dhabi. The velocity model obtained follows the main geological structures and accurately describes the velocity variations in the shallow sub-surface. The estimation of anisotropy is important to ensure good convergence of the FWI and for imaging and vertical positioning of the migrated events. The reverse-time migration (RTM) image obtained with the updated model shows improved focusing and simplified depth structures compared to the RTM image obtained with the smooth initial model.
To the best of our knowledge, this is the first successful implementation of FWI, here combining diving and reflected waves, on a dataset from offshore Abu Dhabi. It is a step towards resolving buried anomalies such as karst features, that cause imaging distortions at deeper reservoir levels.
Interpreting Subtle Faults and Multiple Horizons Layers Using Machine Learning and Data Driven Approach
Authors: Syed Bilal Saeed , Mukherjee Jagannath , Ditia Tadeo , Seliem Abdulla , Al Kobaisi Abdulla Saad , Andrews Ben , Jaramillo Alejandro , Norlund Phil 
Published: October 2022

Abstract
The Lower Cretaceous Thamama Group is one of the proven and productive hydrocarbons bearing intervals within Abu Dhabi area. The geological setting of Thamama Group is complex due to the nature of its structural evolution in a strike-slip regime with high-angle fault and subtle vertical displacement. Additionally, the stratigraphy of Thamama Group consists of multiple stacks of Carbonate reservoirs which are separated by various Anhydrite layers. Some of the carbonate layer cannot be interpreted properly due to data resolution and quality of the seismic reflector.
Due to the geological complexities, using the existing 3D Seismic Data to interpret faults and horizons within due time frame for critical decision making can be extremely challenging. Vertical displacement of the fault often cannot be easily recognized from seismic section and auto-tracking horizon interpretation doesn't produce a good result due to lack of reflector continuity.
In the specific area of this study, the main geological challenge was to interpret those N45W subtle faults developed at the central region of the seismic volume. To address this challenge, we first applied one of the existing machine-learning models proposed by Jiang and Norlund (2020) to pre-train a multi-channel convolutional neural network model with a set of synthetic seismic volumes (over 200 different cases), that resembles multiple geological scenarios with similar structural characteristics to those observed in the study area.
We utilize a new point-based method that leverages a network analysis technique to automatically extract fault surfaces from fault imaging volumes.
For horizon interpretation we use a new Assisted Horizon Interpretation workflow we are developing. This approach is good for identifying and tracking larger, more continuous surfaces throughout a seismic volume. This results in many output horizons that fill the entire seismic cube, we refer to this as “Dense Horizon” extraction. This portion of the project uses a deterministic approach for identifying & tracking patches throughout the entire seismic volume & then uses several automated and manual tools to join those patches to generate complete surfaces.
The results achieved with this study helped to improve the quality of faults and horizon generation in complex geological area with improved efficiency and accuracy.
New Scheme for Sonic Verticalization in a Highly Deviated Well, in a Complex Carbonate Field, Onshore Abu Dhabi, UAE
Authors: Gao Xiaoli , Grover Anurag , Wang Ailing , Ahmed Jahan Zeb , Zhao Wenhao , Al Mesmari Abrar , Lv Lu , Deng Anxiong 
Published: October 2022

Abstract
Reliable sonic and density logs are key inputs for seismic driven reservoir characterization. Anisotropic surface vertical velocities are essential for seismic well ties, estimation of wavelets and low frequency modeling. These help us to understand the relationship between reservoir and acoustic properties. In this study, sonic logs were acquired in highly deviated wells penetrating highly anisotropic shale formations. These logs needed corrections before integrating in the reservoir characterization workflows.
In allusion to problem existed in traditional methods, an iterative inversion method based on multi-well models composed of adjacent vertical and deviated wells was proposed. Well data was optimized after matching depth of vertical and deviated wells. Thomson approximation formula was re-derived based on multivariate linear fitting and least square coefficient matrix was constructed to obtain delta and epsilon respectively. Best Thomsen parameters were obtained to address shale anisotropy.
The results show that the Nahr-Umr shale formation have strong anisotropy for highly deviated wells in the field of study. The correction was not required for deviation less than 20 degrees. The correction gradually increases and reaches as much as 20% to 30% at 60 degrees. It was observed that there is a huge difference between the measured velocity of highly deviated wells and the true vertical velocity in the shale formation. This anisotropy can affect seismic imaging, time-depth conversion, AVO, well-seismic calibration. Therefore, sonic log correction is necessary for highly deviated wells in the shale formations. Corrected sonic logs in deviated wells provide accurate acoustic velocities for further reservoir characterization & seismic inversion studies. The real acoustic data of deviated wells can be obtained from shale formations with strong anisotropy such as Nahr-Umr and Laffan formations.