bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil Pipeline Leak Detection Using Deep Learning: A Review on POC Implementation
Authors: AlAzri Ahmed , Alkaabi Sultan , AlZakwani Saud , Altamimi Fadhil , AlMamari Maadh , AlSulaimani Mohammed 
Published: March 2023

Abstract
Oil and gas production operations are key sources of environmental pollution which exposing the people and effect the human activity in the world. Petroleum Development Oman (PDO) is the leading exploration and production oil and gas companies in the Sultanate of Oman which lead to avoid adverse health effects in Oman. Oil pipline leakes could be undetected for a long time. However, the precise methods could help improve the oil leaking detection response process in channel required resources with more effectively to be concerned regions. Existing Synthetic-aperture radar (SAR) approaches are limited by their algorithm complexity which difficult to work with imbalanced data sets, doubts to select optimal features, and the relatively slow detection. Using deep learning approach could speed up the oil detection. convolutional neural network U-Net segmentation models based on oil leaking detection could be achieve promising automated results. However, there are insufficient features extraction due to loss of target to detect oil leaking or shadows in drone images that commonly appear in various size, shapes, and brightness levels, which the images that captured under many conditions. To overcome all these limitations, we utilized a deep learning model named Pyramid Scene Parsing Network (PSPNet). The proposed algorithm can probabilistically detect oil leak from drone imagery at the frequency of data collection. Thus, PDO Oman could reduce millions of Dollars when direct action from operators that received a quick true alarm of oil leaking. The effectiveness of the proposed method is demonstrated through A proof of concept (POC) based on a realistic dataset that collected history data that our deep learning algorithms achieved the perfect predict the oil leaking before occurs.
Automated Geomechanics Modelling Workflow Supports Real-Time Decision Making and Risk Mitigation in Challenging Horizontal Wells
Authors: Dorantes Arnott , Franco Nata , AlSameen Rawan , Amer Syed Mohamed , Karpfinger Florian , Corona Mauricio , Levario Jesus , Abdul Kader Mansoor 
Published: March 2023

Abstract
Geo-steering a horizontal well to the pay zone is commonly deployed across the globe but combining it with real-time geomechanics is very advantageous under challenging wellbore conditions. The normal practice is to have the geomechanics expert receiving the measurements data, updating the pre-drill model and giving recommendations. This paper will describe efficiency improvements brought by an innovative workflow of automation of the geomechanics model in real-time from the remote operations center.
Horizontal drilling can be very challenging, especially if the wellbore stability starts deteriorating. This can hugely impact operations, such as downhole fluid losses, extensive back-reaming, stuck pipe incidents and in extreme cases, sidetrack, and re-drilling the section might be needed. To further improve support to drilling team, a thorough review of the geomechanics process was carried out. A performance improvement opportunity was identified in the way real-time geomechanics was conducted in the project and the potential benefits of a more automated process would bring.
The Automated Geomechanics Modelling Workflow enabled real-time updates of the geomechanics model when logging-while-drilling (LWD) is transmitted to a Real-time Operations Center (RTOC). The pre-drill geomechanics model was built for a given wellbore trajectory by experts, shared with the RTOC and connected to real-time LWD drilling data. The model was automatically updated while drilling and made available to the RTOC specialist, who identified the breakout zones from caliper log, and porosity trend from density image, and could initiate immediately the communication protocol with drilling operations team. The same information was also shared in real-time with geomechanics expert for interpretation and recommendations.
Enabling real-time update of the geomechanics model accelerates the interpretation, recommendation, and reaction from both geomechanics expert and drilling team. Identification of critical intervals by changes of trends of hole enlargement, geological failure or porosity can be immediately communicated to act accordingly. The drilling, tripping and fluids practices can be adjusted on spot, and the main impact is the minimization of wellbore instability and stuck pipe incidents. The benefits from the automated geomechanics modelling are numerous, including safe drilling operations at lower non-productive time, better hole and reservoir quality, and cost saving opportunity.
This workflow is a breakthrough on how wellbore instability is monitored in the wells in the gas project, creates a unique interaction of geoscience and drilling disciplines to monitor hole condition and to manage risks. This work will benefit other operators and service companies in the region to deploy similar process, driving efficiency while lowering well construction costs.
Hydraulic Fracturing of Highly Azimuthally-Deviated Horizontal Wells Enhanced by Wellbore Notching
Authors: AlTammar Murtadha J. , Alruwaili Khalid M. , Al-Dakheel Hussain K. , Aidagulov Gallyam , Abbad Mustapha 
Published: March 2023

Abstract
Multistage hydraulic fracturing is an effective stimulation method as it opens communication between the wellbore and larger reservoir volumes. Nevertheless, there are cases where the formation cannot be fractured within the completion pressure limitations. This problem can be addressed by placing weak points, such as perforations and notches, so fractures could initiate there at lower pressure. This paper discusses this remedy applied in horizontal open holes that are highly deviated from the minimum horizontal stress.
In this study, cement grout block samples (24×18×18 in.) were prepared to cast precisely weak points and boreholes. The cured blocks were completed with 1.25×12 in. (diameter × length) long openhole section in the center. Hydraulic fracturing experiments were conducted inside a polyaxial load-frame to simulate the wellbore under strike-slip stress regime. Boreholes of two azimuthal deviations from minimum stress were considered: 0° (straight) and 35° (inclined). For each, two weak points were tested: V-notch and single perforation. Fracturing fluid was injected at low rate into the borehole. The obtained injection pressure trends were interpreted with open holes cored out to analyze the initiated fractures.
Both fracture initiation pressure (FIP) and fracture breakdown pressure (FBP) (i.e., the maximum) were selected for comparisons, as the former is not influenced by the fracture size nor by the fluid-rock interactions during propagation. FIP was estimated indirectly as deviation from linearity in the borehole injection pressure trend. The results revealed remarkably that the notch significantly reduces FIP and FBP, compared with the reduction by the single perforation, in both the straight and inclined boreholes. Each of the weak points delivered very similar FIP and FBP in straight and inclined boreholes. All the weak points initiated a fracture that is transverse to the borehole axis, which provides the advantage of 360° communication with the reservoir. It was noticed that the inclined borehole with one perforation initiated a transverse fracture with a distinct angle from the preferred plane. To summarize, even if the wellbore is drilled at a high angle of deviation from the minimum horizontal stress in the strike-slip regime, the notch still outperforms perforation in terms of FIP reduction.
This work presents experimental comparisons of hydraulic fracturing pressure reductions caused by notches and single perforation holes placed in horizontal open holes aligned with and highly deviated from the minimum horizontal stress. The experiments showed how notches outperform conventional perforation, and by this, provide insights for stimulation design of horizontal wells where trajectories were influenced by factors other than stimulation, such as geology and reservoir location.
A Simulator for Minimizing Openhole Breakdown Pressure through Notch Shape Optimization
Authors: Han Yanhui , AlTammar Murtadha J. , Alruwaili Khalid M. 
Published: March 2023

Abstract
Wellbore breakdown pressure is an important parameter utilized in hydraulic fracturing stimulation design. Because of the stress concentration around wellbore and formation strength, the borehole breakdown pressure is often much higher than the minimum confining stress plus tensile strength. To overcome the barrier of the stress concentration and locate the fracture initiation spot, well is often perforated or notched before the hydraulic fracturing treatment. Qualitatively, it is well observed and accepted that perforations and notches can reduce the breakdown pressure; quantitatively, however, there is a demand for reliable and accurate method to predict how much various perforating or notching configurations can help reduce the breakdown pressure. In this paper, a computational mechanics simulator is developed to predict the breakdown pressure inside a notched wellbore subjected to loading of in-situ stresses. The simulator can predict the breakdown pressure for a well with a given notch stimulated with fluid injection. It can also be used to optimize the design of a notching tool which can minimize the breakdown pressure during hydraulic fracturing. The simulator is applicable to cases of both longitudinal and transverse notches.
Toward Combining Multi Seismic Attributes, A Novel Machine Learning Approach
Authors: Alshuala Mustafa 
Published: March 2023

Abstract
The objective of this study is to develop and examine a machine learning model that combines multiple seismic attributes in a way that preserves all the features of the combined attributes with, hopefully, better resolution and efficiency than the conventional seismic attributes integration method. We used the Auto- Encoder algorithm, which is a neural network method. It consists of two identical networks known as encoder and decoder. Auto-Encoder was initially developed to compress data in the encoder part, and then the same structure is used to decompress data in the decoder part. Our interest is in the output of the encoder which is the reduced version of the input.
For fault and fracture detection, we examined and compared the results of Octree as a conventional multi- seismic quantization method and Auto-Encoder as a new machine learning technique. The study used five 3D volumes, one for each of the five attributes Raw Data, Skeleton, Detect, Negative Curvature 1 and Negative Curvature 3. Each 3D volume is divided into 100 slices. One slice per attribute (i.e. a set of five slices) comprise an input dataset to the encoder. The process is iterated 100 times to obtain 100 slices of encoded attributes.
The result of the Auto-Encoder solution is compared with that of Octree. The Auto-Encoder accurately preserved the three faults from the input attribute images whereas Octree preserved only one fault. Additionally, the details of the fractures in the Curvature attributes are also preserved with more clarity in the Auto-Encoder solution than Octree. The machine learning technique (Auto-Encoder) preserves all the features (i.e. faults and fractures) from the combined attributes and shows better resolution than Octree. It can also combine unlimited number of attributes whereas Octree is limited to eight attributes only.
A Workflow to Estimate Critical Drawdown Pressure Utilizing 1-D Geomechanics Modelling
Authors: Qatari Ammar 
Published: March 2023

Abstract
The active mobility of sand particles during the production phase has put extra burden on the efficiency of hydrocarbon extraction for both oil and gas. It plays a significant role on completion design during the drilling phase. Minimizing the effect of sanding has been a major topic to tackle due to the added operational costs and time associated. Unconsolidated sand reservoirs are vastly affected worldwide due to the nature of sand particles accompanying hydrocarbon during the production phase. Sand production poses potential risks for surface and subsurface equipment within the completion design. The objective of this paper is to estimate and quantify the potentials of sand production and wellbore instability using 1-D Mechanical Earth Model (MEM). A clear workflow of the utility of raw petrophysical and 1-D geomechanics modelling data is showcased to aid production and completion operational personnel.
Excessive stress concentrated around the wall of a borehole can cause the release of sand particles into the hydrocarbon stream. This process poses risks for drilling and completion operations as it affects the productivity of a well along with potential equipment damage. Unconsolidated sand reservoirs are prone to rock failure which induces the mobility of sand particles. Stress orientation regimes are properly captured by assessing the orientation of current petrophysical data. Acoustic data is also reviewed for proper in-situ rock strength property calculation. Formation pressure testing is vital to the process to estimate pore pressure gradients. Once MEM is finalized, Critical Drawdown Pressure (CDDP) is analytically calculated using the linear elastic methodology to predict sand production.
The use of 1-D MEM sand management analysis to predict critical drawdown pressure is vital to avoid equipment damage and production limitations associated with sand production in a weakly consolidated reservoir. A workflow to produce an in-depth critical drawdown pressure analysis captures the changes that might occur for a perforation completion over time as it undergoes depletion. A representation of sand potential prediction and critical bottom-hole flowing pressure as a function of reservoir pressure is to be illustrated in a single depth format which allows for sensitivity analysis.
This paper examines the direct impact of the analytical estimation of critical drawdown pressure as a guide to predict the potentials of sand production intervals within a certain reservoir. The mechanical properties, petrophysical raw data, and depletion status are the ingredients to produce a thorough analysis to guide drilling, production, and completion personnel to minimize sand production effects operationally. Further improvement to the model can be made by the integration of production data and reservoir properties that are captured over time.
Strengthening of Carbonate-Based Formation Rocks Natural, Sustainable Materials
Authors: Alarawi Abeer A. , AlTammar Murtadha J. , Alruwaili Khalid M. , Alrubeh Jasim A. 
Published: March 2023

Abstract
Generating hydraulic fractures with good conductivity is essential for well productivity in unconventional formations. However, hydraulic fractures gradually lose conductivity with hydrocarbon production as fracture surfaces creep closer due to proppant embedment or failure of fracture asperities under increasing effective in-situ stresses and high temperatures. This work proposes adding a widely available, natural-based metal carbonate (MC) to fracturing treatments in carbonate formations to make fractures mechanically harder and enhance long-term well productivity. An MC-based formula of varying concentrations was prepared and tested on homogenous carbonate core samples. Two solutions were formulated by mixing 10 and 20 gm of MC powder in 100 ml of organic solvent. The core samples were immersed in different solutions for seven days, and the samples were thoroughly characterized before and after exposure to the solutions. Rebound hammer tests were also conducted to show the effect of the solutions on the samples’ mechanical properties, such as Young's modulus and compressive strength. The test results show that the physical properties such as dry weight, bulk density, and bulk volume of all core samples increased noticeably after treatment, reflecting the success of the precipitation reaction and the penetration of used MC into the bulk of the rock samples. Rock treatment with the 10-20 gm-powder solution led to a significant enhancement of the samples’ mechanical properties, where Young's modulus (E) and Unconfined Compressive Strength (UCS) were observed to increase by up to 34% compared to untreated rock samples. Rock hardening in fracturing applications is a relatively new concept. Compared to the consolidation additives in the literature, the proposed MC formula is ubiquitous, widely available, and inexpensive. Lastly, the MC formula is also a by-product of a few oilfield operations, making it a sustainable solution to industrial waste in the oil industry.
Role of Geomechanical Modeling and Analysis in Sand Management and Control
Authors: Ashtiani Abdi Hadi , Alward Wassem 
Published: March 2023

Abstract
Sand production erodes hardware, blocks tubulars, creates downhole cavities, and must be separated and disposed of on the surface. Completion methods that allow sand-prone reservoirs to be exploited often severely reduce production efficiency. The challenge is to complete wells to keep formation sand in place without unduly restricting productivity.
To avoid sands, the dependence of rock failure on drawdown must be analyzed properly using geomechanical methods. A wide range of methods has been used in the past for sand production prediction. Modeling and designing bottom hole features, mostly perforation geometry and wellbore trajectory, based on sand body mechanical properties and near wellbore stresses is the key to mitigating or eliminating sand production issues in clastic reservoirs.
In this paper, we present a full-scale geomechanical analysis and modeling using a 1D mechanical earth model (elastic and strength properties and stress field) to address the main challenges and the root causes of sanding in clastic reservoirs in South of Iraq. The analysis includes the following:
Critical Draw Down Pressure (CDPP) profile in different levels of reservoir depletion resulting in sand production. CDPP is the minimum borehole pressure for which no solids are produced from a sand reservoir. Well inclination sensitivity analysis and its role in sand production Sand grain size sensitivity analysis and its role in sand production Unconfined compressive strength (UCS) as rock strength indicator sensitivity analysis and its role in sand production Perforation direction sensitivity analysis relative to stress directions, and its role in sand production.
We present a case study to show how the methodology and workflows have been applied to identify sand-producing intervals for different completion scenarios, determine the optimum drawdown conditions for sand-free production and adjust completion configuration to obtain sand-free production from a clastic reservoir in the South of Iraq.
Pattern Recognition-Driven Automatic Drainage Region Mapping to Accelerate Reservoir Simulations
Authors: Shubbar Ahmed , Maucec Marko , Moriwawon Babatunde 
Published: March 2023

Abstract
History matching is widely considered as the most time- and resource-consuming phase of reservoir simulation modeling. Even with the advent of modern, computer-assisted, history matching methods, the dynamic calibration of large-scale simulation models represents a considerable computational undertake. The challenges become even more pronounced with incorporation of subsurface and production uncertainty.
This paper outlines a step forward in acceleration of reservoir simulation studies by applying a split/merge approach constrained by no-flow boundary drainage region. The method transforms the history-matching process into an accelerated progressive sequence of dynamic model updates in time and space. Each segment defined as distinctive drainage region, the boundaries of the drainage regions are mapped based on no-flow conditions. Each segment is dynamically calibrated and history matched simultaneously in parallel. Lastly, the segments are merged back to reconstruct the original model to run the prediction phase.
The detail of the workflow is described, as well as the implementation of the workflow in a synthetic model. A comparison between the conventional approach and the new approach is discussed. Recommendation and a way forward are shared to capitalize on the accelerated method for future reservoir studies.
Solving the Low Injectivity Challenges in Hydraulic Fracturing Tight Gas Reservoirs - Case Histories Review
Authors: Yudin Alexey , Nurlybayev Nurlan , Al-Jalal Ziad 
Published: March 2023

Abstract
Fracturing in tight and deep gas formations can be challenging when near-wellbore stresses reduce injectivity. The drilling fluid may contribute to a near-wellbore damage, and this will exaggerate the rock breakdown limits additional to the high local stresses. The paper will present case history review of different techniques in addressing low injectivity in tight gas wells to minimize delays in operations and associated risks.
Different stimulation techniques are utilized to enhance the production from tight gas carbonates reservoirs, including multistage fracturing completions and techniques as plug and perf, sliding sleeve systems, coiled tubing conveyed stimulation systems, etc. regardless of completion method type, the damage level could still be present, in addition to the stress cage around the wellbore, hence the injectivity can be very challenging. There are frequent cases, when during the injection stage the pumping rate barely reaches 1 bpm at maximum allowed pressures. And there are several solutions, such as acid squeeze treatment conveyed by coiled tubing, abrasive jet perforations, bullhead acid spearhead stage at lowest pumping rate, completion fluid solvents and others. Each method has different criteria for applicability, depending on the technical scenarios and require critical decision-making process during the operational performance.
Due to damage presence in the near-wellbore zone, the injection rate was observed to be below 1 bpm and surface pressure could be reaching the completion limitations, and the possibility of job cancellation becomes high. Therefore, proper solutions were required to improve the injection prior to fracturing treatment. The case study showcases some statistical analyses of solving the challenges concerning the near-wellbore damage and improving the injectivity prior to main stimulation treatment.
The case studies review will help optimizing the technical decision when injectivity challenges occur in tight gas reservoirs and could be used as a reference in other HPHT fracturing projects.