bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Foam Stability using Treated Produced Water from Zero Liquid Discharge (ZLD) Technology
Authors: AlYousef Zuhair , Ayirala Subhash , Algadrah Abdulkaream , Alsaleh Salah 
Published: April 2024

Abstract
One of the major drawbacks of using foam to reduce the gas mobility in oil fields is its stability at harsh reservoir conditions. A key factor that impacts the foam stability is the type and chemistry of the water used to prepare the treatment fluid. The objective of this work is to investigate the impact of treated produced water obtained from the Zero Liquid Discharge (ZLD) technology on foam stability and to promote environmental sustainability/water circularity in foam assisted gas injection projects.
In this study, a high-pressure high-temperature (HPHT) foam analyzer was used to investigate foam properties. High salinity brine (HSW) and treated produced water (TPW) from the ZLD technology were used to prepare the surfactant solutions. One foaming agent was used to conduct this assessment. Foam half-life, foam structure, and bubble counts were measured to assess foam stability. The results demonstrated that the TPW has a significant impact on foam stability. The foam generated using the TPW from the ZLD technology is more stable than that generated using the HSW. The foam generated using the TPW has a greater foam density (higher bubble count and smaller size) when compared to that produced using the HSW. In additions, the results showed that the foam generated using TPW has at least 24 times longer foam half-life than that produced using the HSW. Smaller bubble size, larger bubble count, and longer foam half-life are indicative of more stable and stronger foams.
This work, for the first time, evaluates the impact of TPW on foam stability. The promising results obtained suggest that the proposed method of using TPW for generating stable foams may overcome some of the challenges associated with conventional foam applications besides promoting environmental sustainability in foam assisted gas injection projects due to effective produced water recycle/reuse.
Integrated Experimental and Simulation Study of Miscible Gas Flooding in Multi-Layered Light Oil Reservoir, Onshore Oil Field Thailand
Authors: Laochamroonvorapongse Rapheephan , Pancharoen Monrawee , Srisuriyon Jantakan , Worawutthichanyakul Thanawut , Hanchaiphiboolkul Suwapich , Rujipimolkit Chuthanart , Doungprasertsuk Chonlada 
Published: April 2024

Abstract
The remote area in Thailand’s onshore oil field has been under waterflooding. The improved oil recovery study was initiated to seek opportunities for infill well drilling, waterflood improvement, and enhanced oil recovery (EOR). The technical EOR screening results show that the miscible hydrocarbon gas injection is the most suitable EOR method. This study aims to conduct an integrated laboratory and simulation research of hydrocarbon gas injection in this area.
The integrated laboratory studies include PVT analysis, oil swelling test, asphaltene deposition test, minimum miscibility pressure (MMP) measurement, and three gas coreflood tests at a pressure of 2,500 psi (at MMP), 3,000 psi (above MMP), and 2,000 psi (below MMP). The coreflood results are used to calibrate the input parameters in the core-scaled simulation before utilizing them in the field-scaled compositional simulation model. The gas injection scenarios include gas injection alone and water-alternating-gas (WAG) and are sensitized based on injector locations, injection rates, and WAG parameters to identify the optimal injection strategy.
The SARA analysis shows an asphaltene content of 0.2%, and the asphaltene onset measurement test suggests the potential of asphaltene deposition when mixing live oil with injection gas. The slim tube tests indicate that an MMP of 2,535 psi is required to achieve the miscibility state. From the coreflood tests, the gas injection at a pressure of 3,000 psi is the most favorable condition, which could achieve the highest oil recovery factor at 95%. After gas injection, the permeability reduction is observed between 4 – 7%, and a small trace of asphaltene solid was detected from core thin-section images. From the simulation study, the optimal strategy is injecting water-alternating-gas (WAG) at updip locations by converting two existing producers, yielding an incremental recovery factor of 3.4%.
This study presents the integrated laboratory and simulation study workflow of hydrocarbon gas injection in complex multi-layer light oil reservoirs. The investigation of asphaltene deposits and their impacts is included.
Addressing Realtime Formation Evaluation Data Transmission Challenges with Microbubble and Hollow Glass Sphere Mud System - A Case Study from India
Authors: Pawandeep Bagga , Shubhada Khatri 
Published: April 2024

Abstract

Objectives/Scope
The paper outlines the obstacles encountered during the initial implementation of Hollow Glass Sphere (HGS) and Microbubble Mud Systems for formation evaluation data transmission while using mud pulse telemetry in Western Offshore India. The oil and gas operator encountered significant challenges when drilling and assessing formations in directional wells within these low-pressure and depleted reservoirs. HGS and Microbubble Mud Systems were employed to decrease the density of drilling fluids to prevent and address losses while drilling through a producing reservoir section with low pore pressures.

Methods, Procedures, Process
In an effort to address the issue of significant or complete loss of drilling fluid during operations in a low-pressure reservoir, a low-density mud system was introduced with a density ranging between 6.3 to 7.5 pounds per gallon (ppg). However, the inclusion of micro-bubbles or hollow glass spheres in the drilling mud resulted in poor compression, substantial distortion, and weakening of the mud pulse telemetry signal. As a result, the real-time logging-while-drilling (LWD) log lacked data density, diminishing its value to the client. To rectify this, an in-depth analysis was conducted, considering factors such as pump efficiency, flow rate, mud pulse telemetry principles, and pulser design, leading to the development of a novel technique aimed at delivering high-density formation evaluation LWD Data.

Results, Observations, Conclusions
Identifying the factors that posed limitations and implementing strategies to mitigate risks were pivotal actions taken to minimize the risk of data loss and ensure a continuous and uninterrupted stream of logging-while-drilling (LWD) data for real-time decision-making by the operator. This involved servicing the pulser, making changes to pulser design, and enhancing the accompanying software, resulting in the capability to transmit mud pulse data at rates of up to 20 BPS in place of 5 BPS initially. The modified configurations of the mud-pulse telemetry module proved highly valuable in delivering an uninterrupted LWD log with a sufficient data density, thus meeting the requirements of the operator’s subsurface team.

Novel/Additive Information
The paper ends with concluding the best practices which should be incorporated to deliver quality data. This pulser and telemetry system can be combined with any LWD services including NMR, formation pressures and electrical imaging while drilling.
Application of Wellbore Stability Improvement and Drilling Risk Reduction with Static Geomechanical-A Case Study from China
Authors: Cai Jingshun , Zhang Peiyu , Wen Ran , Li Jianhai , Zhang Xin , Lou Yumeng , Huang Xingning 
Published: April 2024

Abstract
Yi 202 block has experienced multiple phases of tectonic movement, resulting in extensive development of natural fractures in the region. Actual drilling indicates that the presence of these natural fractures poses great challenges to drilling operations. However, the wells in this area are ultra-deep, and many sets of complex and difficult-to-drill formations are encountered in top-down drilling, which brings significant challenges to the drilling engineering. Based on triaxial and shear experiments, transverse isotropy theory and weak surface criterion, and integrating the mechanical damage under stress unloading and hydration in drilling wells, a well wall stability model under the synergistic effect of stress unloading and hydration has been established, and an analysis of the factors influencing the stability of the well wall of the formation has been carried out. The study shows that stress unloading occurs after drilling. The greater the confining pressure and axial stress, the more significant the shale strength weakening caused by stress unloading, and the magnitude of stress unloading is positively correlated with the degree of mechanical strength weakening. The more developed the laminations are, the easier it is to damage along the laminations. When stress unloading occurs, the weak structural surface acts synergistically with stress unloading, and the higher the degree of shale strength weakening is, the worse the mechanical stability is and the higher the risk of well wall instability. External fluids are prone to intrude along the bedding and promote shale hydration, making the shale mechanically less stable and reducing the well wall's stability. The effect of stress unloading on shale formation collapse pressure mainly occurs in the pre-drilling stage, and the effect of hydration damage on well wall instability mainly occurs in the late drilling stage. Beddings, stress unloading, and hydration affect the well wall stability together. The shale well wall stability model under stress unloading-hydration synergistic effect considers the influence of the three comprehensively. The prediction results align with the drilling actuality with good reliability after the field application test.
Full Field Implementation of Physics-Based Analytical Model to Optimize Steamflood in Mukhaizna Heavy Oil Field in Oman
Authors: Al Qasabi Nasar , Al Asimi Mohammed , Al Mujaini Majid M , Le Duc , Gao Chao , Dornier David M 
Published: April 2024

Abstract
To optimize steamflood in Mukhaizna Field, Occidental developed connections-based simulation models that retains most of the steam flooding physics. These models address the issue of lengthy run time of traditional 3D reservoir models and resolve the predictability issues of fast physics-less AI/ML models. As these models are being used for full field optimization since 2020, ensuring models reliability and accuracy was a key consideration to optimally operate such large asset.
To gain more trust in these models, models input/output, historical match, applied constraints and recommended steam changes are validated with Reservoir Management Teams (RMTs) before field implementation. After implementation, actual steamflood performance is monitored on regular basis with the RMTs relative to model expectations considering assumed constrains. Predictability of the models were checked in the forms of blind tests and comparison of models prediction with actual field data on well level. Furthermore, to QC the reliability of these models, their outputs were validated with actual measurements and reservoir performance for the applicability be used in understanding reservoir dynamics in areas with no/limited data acquisitions.
With multiple optimizations and implementations, it was observed that these physics-based models managed to align steam allocation with available opportunities and constraints given the continuous improvement and dynamic challenges in the field. This resulted in observed increase in oil production rate in some areas, reduction in production decline rate in other areas, and increased overall steam efficiency. It was observed also that good handling of production constraints and limitations are essential factors in deciding steam distribution even if reservoir quality and flood efficiency are on the high side. Finally, having history matched physics-based models, enabled the use of model outputs in the day-to-day surveillance, understand subsurface wells connections, unlock hidden opportunities, and provided a reliable tool for optimum operating scenarios going forward.
This paper describes one of the largest full field application of physics-based closed-loop reservoir management system in steamflood projects, demonstrate the steps to ensure models reliability, present observed results and challenges, and share lessons learned.
A Data Driven Approach to Optimizing Gas Reservoir Management Through Machine Learning and Phase Behavior Analysis of Production Data
Authors: Bestman S. , M. Khatrawi F. , M. Almahdi R. , M. Dalbahy B. 
Published: April 2024

The significance of reservoir management has been recognized by the Oil and Gas industry as a strategy for maximizing resource recovery while minimizing investment. Fowler et al (1996) identify reservoir management as a tool to manage risks while optimizing profitability. Fanchi (2018) points out that successful reservoir management requires an understanding of the reservoir structure, the distribution of fluids within the reservoir, drilling and maintaining wells which can produce fluids from the reservoir, transport and processing of produced fluids, refining and marketing the fluids, safely abandoning the reservoir when it can no longer produce, and mitigating the environmental impact of operations throughout the life cycle of the reservoir.
Wiggins et al (1990) underline the three primary components of reservoir management as: Knowledge about the entity being managedManagement environmentAvailable technology
Thakur (1996) highlights the increasing role of data in reservoir management activities along with the need for comprehensive, cost-effective surveillance with surveillance management programs and well-planned data-collection with data-collection management programs.
A Strain-Driven Model for Anisotropic Permeability Evolution of Shale and Coal Incorporating Creep Deformation, Anisotropic Internal Swelling/Shrinkage, and Gas Rarefaction Effects
Authors: Zeng Jie , Guo Jianchun , Liu Junchen , Zhang Tao , Zhao Zhihong , Liu Jishan , Chen Zhongwei 
Published: April 2024

Abstract
Permeability of shale and coal is a main controlling factor for gas migration and is sensitive to effective stress, sorption/desorption-induced internal swelling/shrinkage (swelling/shrinkage at fracture/pore surfaces), and gas rarefaction effects. The dependence of gas permeability on effective stress and rarefaction effects has been extensively studied. However, the impacts of anisotropic strains and their time-dependent evolution (creep deformation) on permeability variation were still not fully understood, which makes it difficult to accurately predict permeability evolution and simulate gas transport, especially for deep coal.
To fill this knowledge gap, a modified sugar-cube conceptual model that captures the structural anisotropy of coal and shale is used to develop a generic fully anisotropic strain-driven permeability model incorporating anisotropic creep deformation, directional internal matrix swelling/shrinkage, and gas rarefaction effects. The time-dependent creep deformation is described by the Nishihara quasi-static rheological model with elastic, viscoelastic, and visco-plastic strain elements. Unlike previous studies where anisotropic internal swelling/shrinkage is ignored or simulated by simply using three sets of independent Langmuir pressure and swelling strain constants, a mechanical-property-based swelling model is used to truly couple directional internal swelling/shrinkage strain with mechanical anisotropy according to the energy balance theory. The Beskok-Karniadakis model is employed to accurately characterize full-Knudsen-number-ranged gas rarefaction effects.
The proposed permeability model is verified against coal permeability measurement data. Analyses results indicate that the permeability evolution in each direction shows unique features depending on the anisotropic structure, directional internal swelling, and mechanical properties. The permeability reduction contributed by three-stage creep deformation can be larger than 90%. Internal swelling strain variation in all directions also exhibits a noticeable impact on the magnitude of permeability, which is more obvious at the third stage. The overall influence of the gas rarefaction phenomenon turns heavier as time increase due to the continuous narrowing of flow channel.
Due to its analytical feature, the proposed model is suitable for different permeability measurement conditions, including constant effective stress, constant confining pressure, and constant average pore pressure conditions. It can be easily incorporated into a more complex and realistic Multiphysics framework for field-scale simulation and well production prediction.
Developing an ESP Lifespan Predictive Model Using Artificial Intelligence: A Case Study On an Omani Oilfield
Authors: Al Sawafi Ali , Kazemi Alireza , Ganat Tarek , Al Saadi Faisal , Al Ghadani Adnan 
Published: April 2024

Abstract
The Electrical Submersible Pump (ESP) is the most effective and consistent artificial lift method for medium to high production rates. Although the capital cost of ESP is high, it pales in comparison to the production losses resulting from its failure. Recently, Machine Learning (ML) has gained significant attention in the oil and gas industry due to its predictive power. This paper aims to develop a ML model to predict ESP lifespan and identify the key features that influence its longevity. The study reviewed the failure history of more than 100 wells from an Omani oilfield, with 132 ESP failures attributed to sand and scale accumulation. The dataset includes 36 static features related to ESP design, installation, commissioning, failure, pull-out, and teardown. Three algorithms, namely Support Vector Regressor (SVR), Random Forest Regressor (RFR), and Extreme Gradient Boosting Regressor (XGBR), were selected. Hundreds of tests were performed on each algorithm to optimize the parameters and hyperparameters, based on mean absolute error, average residual, and determination coefficient. The study developed a model with two levels to predict the lifespan of ESP before installation and after the last valid well test. The model had a mean absolute error of 25 days and 8 days for the first and second levels, respectively, with a determination coefficient of 60% and 73%. The model showed that certain factors related to pump and motor design have the most significant impact on the longevity of the ESP before installation. Pump discharge pressure and flow rates of oil and water are crucial to monitor and control during its operational lifespan. The findings emphasize the importance of careful selection and design of ESP components to ensure a long-lasting lifespan. By scheduling ESP maintenance before failure, these findings can help mitigate capital costs, while preparing the necessary hoist, rig, and materials for ESP replacement can avoid deferred operational costs.
Effectiveness of Surfactant-Polymer Flooding at High-Temperature and High Salinity Reservoirs: Moderate-Low or Ultra-Low Ift?
Authors: Hou Jian , Huang Tianping , AlOtaibi Mohammed 
Published: April 2024

Abstract
To implement an effective chemical flooding process in enhanced oil recovery in a sustainable way, it requires a careful selection of surfactant-polymer (SP) formulation, regarding on the interfacial tension (IFT) with oil. Usually, a unltra-low IFT is preferred to achieve a low residual oil saturation and a high oil production rate. The question is how low of the IFT is enough for an effective oil production. Targeting at high temperature and high salinity carbonate reservoirs, this work deeply discussed the interfacial tension (IFT) factor on the effectiveness by injecting two SP formulations with similar viscosity but moderate-low and ultra-low IFT respectively.
The SP formulations BC-O1/PST-10 (zwitterionic surfactant / sulfonate polyacrylamide) and APA-H1/SPAM-A5 (zwitterionic surfactant / sulfonate polyacrylamide) were selected since their good compatibility with a high salinity brine with total dissolved solids of 57,670 ppm. The IFT measurements of both SP formulations were conducted using a spinning drop tensiometer (SVT20N, Dataphysics) at a temperature of 90 °C. The rheological properties were measured using a rheometer (Discovery HR-2, TA Instruments). And the injection of BC-O1/PST-10 and APA-H1/SPAM-A5 for oil displacements was performed in a homogeneous medium oil-wet microchannel slice at 90°C, following a water injection process. The incremental oil production rate was calculated from the microchannel images.
It was observed that the IFT values between oil and the SP solution composed of BC-O1/PST-10 and APA-H1/SPAM-A5 are in the moderate-low range (10-2 mN/m) and ultra-low range (10-3 mN/m), respectively. It also presented the viscosities of the polymer solutions are similar when polymer concentrations were at 2,000 ppm, which ensured a similar sweeping efficiency in the displacing process. The oil displacement experiments showed the incremental oil production rate of BC-O1/PST-10 injection (40%) was a little higher than APA-H1/SPAM-A5 injection (37%) though the IFT was a magnitude higher. This study presented that in oil-wet or mixed wet carbonate reservoirs, despite IFT factors, other influences such as surfactant-polymer interactions also play an important role. The moderate-low IFT could be sufficient for SP flooding in high salinity high temperature reservoirs.
This work intends to provide an effective SP flooding technique regarding the interfacial tension. In high salinity high temperature carbonate reservoirs, zwitterionic surfactants with a medium-low IFT for oil production could be a good choice. This gives more options to select green surfactants instead of pursuing lower IFT.