bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Implementation of Polymer Flood in Aishwariya Field, Rajasthan, India - Concept to Full Field
Authors: Singh Aditya Kumar , Vegesna Pruthvi Raju , Prasad Dhruva , Kachodi Saideep Chandrashekar , Lohiya Sumit , Srivastava Deeksha , Raj Rahul , Koduru Nitish , Mishra Sudhakar , Barua Debaditya , Pandey Amitabh 
Published: December 2021

Abstract
The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project.
The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance.
Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved.
Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.
Offshore Health Innovations
Authors: Logunov Konstantin Valerievich , Antipov Sergei Anatolievich , Karpov Andrey Borisovich 
Published: December 2021

Objectives/Scope
Analysis of 15 years results of remote occupational health care in oil and gas production industries.

Methods, Procedures, Process
Continuous observation, statistical analysis of morbidity, mortality, and treatment results in industrial personnel at different endpoints depending on the variability of care models. Cost-efficacy analysis of several occupational health interventions. Targeted polls of Customers. Dynamics of new Customers.

Results, Observations, Conclusions
The best practices which provide the maximum efficacy include risk assessment and risk management, action planning for emergencies, telemedicine, education, registry maintenance. Each of all these gave a 10-100-fold rise in Customer satisfaction, seriously improved medical statistics. Telemedicine implies both: the delivery of highly specialized diagnostic technologies directly to the industrial production site, where a GP or paramedic is present, and it implements the direct replacement of medics with gadgets at the patient's bedside. Education involves hands-on training for both industrial personnel at remote sites and for medical professionals who provide care. The 2020-21 COVID19 pandemic was a great real stress test for remote health models when systemic integrated management procedures played a pivotal role in ensuring smooth industry operation due to the high quality of back medical services.

Novel/Additive Information
Modern efficient models of medical care for remote industries are necessarily comprehensive, modular, adaptive, and rely on personnel health registers. Remote health practices gain a 5-15% rise in price every year, but it pays off in greater labor productivity and in improving the health of industry personnel.
Integrated 1-D and 3-D Basin Modelling to Characterize the Deposition and Distribution of Asphaltenes Within Tar Zones from an Oil Field Offshore Abu Dhabi, UAE and Qatar
Authors: Holloway Daniel , Kelly Ranald , Kay Daniel , Gill Claire , Ishibashi Masatoshi , Al-Hitmi Ruqaya Hassan Ali 
Published: December 2021

Abstract
Increasing the recoverable reserves from oil fields by extracting from tar zones is becoming more desirable in the Middle East. One approach for improved definition of tar zones is to understand the factors which affected the deposition and distribution of asphaltenes within the target interval. In this paper we outline how integrated 1-D and 3-D basin modelling was used to identify the timing of hydrocarbon generation and expulsion from the Jurassic source rock to charge a prolific Jurassic carbonate reservoir formation of an oil field, offshore Abu Dhabi, UAE and Qatar.
The source rock is modelled to be in the peak oil mature window today, with the onset of oil generation from the Cenomanian to the Turonian, depending on modelled and assumed source rock kinetics. The onset of oil expulsion was from the earliest Paleocene. Measured bulk fluid parameters in the reservoir formation have a significantly higher Gas-Oil Ratio (GOR) and elevated API gravity values when compared with predicted values. A possible mechanism to explain this discrepancy would be to invoke the contribution of higher GOR fluids from more mature source rocks within the fetch area of the field.
Thermochemical sulphate reduction of anhydrite layers in the reservoir is predicted to have begun during the Eocene. Major uplift and erosion in the Oligocene and Mio-Pliocene significantly reduced reservoir pressure and temperature. This reduction in pressure and temperature is modelled to have caused precipitation of solids, gravity segregation and flocculation at the then oil-water contact, depositing the main tar zone and patchy tar in the reservoir beneath this zone as charge continued through time.
We present a detailed review, interpretation and 3-D basin model; the first study of its kind conducted on this oil field. The 3-D basin model predicts the timing of the deposition and distribution of asphaltenes in the carbonate reservoirs of the studied field and demonstrate that local problems need to be understood in their regional context.
Several Decades of Fluid Diversion Evolution, Is There a Good Solution?
Authors: Casero Alberto , Gomaa Ahmed M. 
Published: December 2021

AbstractThe success of any matrix treatment depends upon the complete coverage of all zones. Consequently, the selection of the diversion technology is critical for treatment success. While various types of diverting agents are commercially available, the proper selection of optimal diverter depends on many factors, including well completion and history, compatibility with reservoir and treatment fluids, treatment objectives, operational constraints, and safety and environment considerations.The study will cover five major types of non-mechanical diversion technologies considered as potential solutions for offshore deepwater oil reservoirs: dynamic diversion, relative permeability modifiers (RPM), viscoelastic surfactants (VES), particulate diversion, and perforation diversion. All of them, but a dynamic diversion, are based on different chemicals or products to be added to the injected treatment fluid, and occasionally some can be complementary to each other.Given the offshore and deepwater settings, mechanical diversion techniques were not covered in the study, aiming to find a solution that would achieve acceptable diversion while minimizing operational effort, which would enable riser-less intervention and the use of light intervention techniques.This study was driven by the need to effectively stimulate a 500ft of a cased and perforated interval with a permeability of 500 md, and injection rate limited to 16 bpm due to completion limitations. The sandstone formation, with static in situ temperature of 270F, was far beyond the applicability of dynamic diversion and, to achieve the desired full coverage for the planned scale inhibition treatment required and combination with another diverter system was needed.The process applied included compatibility tests, regained permeability tests, and test well trials. Depending on the specific diversion product analyzed the testing procedures were adapted to obtain the information to properly guide to the optimal solution.
Untapping the Full Potential of Long Length Tubular Grouted Connections to Ensure Sustainability of Offshore Structures
Authors: Abdelkhalek Ahmed , Atia Mohamed , Sarkar Anjan , Keys Matt , Patel Mahesh , Eissa Mohammed , Omar Tarek , Choo Yoo Sang 
Published: December 2021

Abstract
Questionable pile-jacket grouted connections’ reliability posed threat to the sustainability of 200 wellhead platforms with ages up to 60 years and averaging at 45 years. Industry standards fell short in guiding fitness for service assessments for these connections that fall outside the applicability limits of their formulae. This paper presents key findings from the laboratory testing supported study, which demonstrated the platforms’ long-term FFS and led to multi-billion Dollars savings.
Comparison of Z-Factor Correlations Using a Large PVT Dataset with Emphasis on the GERG-2008 EOS
Authors: Mogensen Kristian , Merrill Robert 
Published: December 2021

AbstractThe gas compressibility factor is an important property in reservoir simulation studies. It is directly linked to the gas formation volume factor and the gas density thereby impacting wellhead injection pressure, reservoir voidage, injectivity, as well as the tendency for gas gravity override to occur in the reservoir.ADNOC's PVT database contains experiments on almost 2,000 samples, of which more than 100 have been subject to advanced gas injection experiments. Z-factor data have been compiled from the liberated gas during DV experiments as well as from CCE experiments on reservoir gases, injection gases, and swollen fluid mixtures. Several of these mixtures are very rich in H2S, whereas pressure and temperature are in the range of 14.7-14,500 psia and 80-365 °F, respectively.We test several different methods for predicting the Z-factor, such as the industry-standard Hall-Yarborough method, in combination with various models for pseudo-critical pressure and temperature and including correction for non-hydrocarbon components. Other methods tested include the GERG-2008 model, considered to be state-of-the-art for predicting physical properties for well-described gas mixtures, as well as the well-known Peng-Robinson cubic equation of state.Based on close to 10,000 data points in our database, the GERG-2008 model typically predicts the Z-factor to be within 2% of the measured value, which is on par with the experimental uncertainty. However, for some rich gas condensate mixtures, the model gives larger errors because its parameters are only tuned to compositions with components up to C10. This is to our knowledge the first time that the GERG-2008 EOS has been compared to standard Z-factor correlations for such a large number of data points.If compositional information is available, we recommend using either the GERG-2008 model or the Hall-Yarborough model with pseudo-critical properties provided by Kay (1936). When compositions are not available, we find that the Standing correlation is more accurate than the Sutton model, also for sour mixtures.
A Comparative Evaluation of Thermodynamic Models for Prediction of Wax Deposition
Authors: Ismailova Jamilyam , Abdukarimov Aibek , Mombekov Bagdat , Delikesheva Dinara , Zerpa Luis E. , Dairov Zhasulan 
Published: December 2021

Abstract
Wax deposition on inner surfaces of pipelines is a costly problem for the petroleum industry. This flow assurance problem is of particular interest during the production and transportation of waxy oils in cold environments. An understanding of known mechanisms and available thermodynamic models will be useful for the management and planning of mitigation strategies for wax deposition. This paper presents a critical review of wax prediction models used for estimation of wax deposition based on chemical hydrocarbon compositions and thermobaric condition. The comparative analysis is applied to highlight the effective mechanisms guiding the wax deposition, and how this knowledge can be used to model and provide solutions to reducing wax deposition issues. One group of thermodynamic models assume that the precipitated wax is a solid solution. These models are divided into two categories: ideal (Erickson and Pedersen models) and non-ideal solutions (Won and Coutinho models). In the other group of models, the wax phase consists of many solid phases (Lira-Galeana model).
The authors summarized the limitations of the models, evaluated, and identified ways to represent the overview of existing thermodynamical models for predicting wax precipitation.
Within the strong demand from industry, the results of this manuscript can aid to aspire engineers and researcher.
Challenges and Mitigation in Achieving Successful Project Handover
Authors: Esro Murnisa , Yahaya Mohd Hafizd , Ahmad Nur Shairah 
Published: December 2021

Abstract
This paper will describe the common challenges faced by both Project Management Team (PMT) and Asset Owner when projects come to the tail end and due for handover. It highlights the impact of improper handover of projects to the company as a whole and provides some proposals to address the common project handover issues. This paper will cover mainly on project handovers for upstream projects especially related to offshore facilities. This paper is written based on sample of projects done at offshore Malaysia. It highlights the common handover issues such as PMT not able to handover timely to the Asset Owner although the facilities are running, and production had been achieved. The longer it takes to handover, the more monetary value leakage will be wasted as a result of no equipment preventive maintenance, warranty of equipment could expire or void, and paying higher construction insurance coverage. This can be prevented by a proper and early planning in managing handover, inclusion of segmented provisional acceptance criteria in the contract as well as having frequent engagement between PMT and Asset Owner prior to stages of handover during project execution. Understanding of each stakeholders' expectations is also one of the key success factors. This paper will conclude that there are many common handover issues when it comes to project handover. Most of the issues are the results of misunderstanding of each stakeholder's expectation, poor early handover planning and unclear scope of acceptance in the contract. In most cases the impact will lead to unrealized monetary value leakage. Early handover planning, clear scope covered in the contract, good coordination between PMT and Asset Owner, good teamwork and mindset, blending with some interpersonal skills in managing conflicts are among the key success factors. The key highlights in this paper will help PMT and Asset Owner in better managing the project handover. This will improve project delivery to meet target schedule within scope and budget. This will eventually safeguard overall company investment and avoid any risk on uncertainty of care and custody transfer at the end of a project life cycle.
Unlocking Opportunities for Gas Lift Well Surveillance - Building the Framework for Consolidated Data Capture and Processing
Authors: Cornwall Rachelle Christine , Shkorin Daniel Dima , Guzman Rodrigo Alberto , El-Majzoub Jalal Rojdi , El-Sedawy Mahrous Sadek , Pribadi Giftan Febrian , Deng Yunhui , Alhur Mohammed Abdulrahman 
Published: December 2021

Abstract
Gas lift operations are highly dependent on data quality and team competence to operate the asset efficiently. Traditional methods for gas lift well surveillance and diagnostics rely on wireline services, a method with growing constraints to adapt to constantly evolving well and operational challenges. The Well Intervention-less Tracer Surveillance System (WITSS) provides a cost effective, comprehensive approach to well surveillance without the reliance on tools entering the well. This results in reduced HSE risks and no associated deferred production.
This paper describes a pilot implementation to evaluate the adequacy and accuracy of this technology in the context of ADNOC Onshore gas lift producers. The objective is to evaluate its performance against conventional method data sets and assess the reproducibility of data where no reference existed. The 10 well pilot included both accessible and obstructed wells. Data from the custom designed modular portable kit used for executing the surveillance activities, was analyzed and compared against conventional flowing gradient surveys with full data consumption in well models for comprehensive nodal analysis and opportunity identification.
For this pilot, ten wells were surveyed twice using the WITSS method. Results were compared to traditional methods acquired through wireline surveys for accessible wells, and against established multi-phase flow correlations for obstructed wells. The pilot confirmed the WITSS method is as accurate as conventional gauge measurements in mapping pressure and temperature profiles in gas lifted wells.
The WITSS method provided additional insight on accurate gas consumption based on the assessment of total gas lift utilization per well and allowed comprehensive model calibration and well performance definition. It also identified potential integrity issues via identification of primary injection at designed stations and secondary unwanted injection sites. Continuous compositional gas analysis of both injected and produced gas streams provided additional verification for analyzing gas lift injection performance. It also highlighted a change in fluid compositional analysis opening discussions for material selection review of the assets.
Production uplift identified from 50% of wells was compliant with the reservoir management strategy. The value proposals of flow stabilization through gas lift valve re-calibrations and replacements, adjustment of injection flow rate and further controls on injection pressure management are under process for implementation. Full field scale up scenario is under preparation.
Application of Full Waveform Inversion to Time-Lapse Walkaway Vertical Seismic Profile Data for CO2-EOR Monitoring in Abu Dhabi: A Feasibility Study on Field and Synthetic Data
Authors: Mouri Takuji , Shigematsu Aijiro , Nakamura Yuki , Kato Ayato , Ichikawa Masaru , Kitawaki Yuta , Sakata Genki , Ishiyama Tomohide 
Published: December 2021

Abstract
This study aims to investigate the feasibility of CO2-EOR monitoring by full waveform inversion (FWI) of time-lapse VSP data in an onshore CO2-EOR site in Abu Dhabi. CO2-EOR monitoring using conventional time-lapse surface seismic in onshore oil fields in Abu Dhabi is often technically challenging for two main reasons. The first is that elastic property change in response to pore fluid substitution is relatively small because the elastic modulus of the reservoir rock frame is far larger than that of the pore fluids. The second is the low repeatability of time-lapse survey data due to high amplitude surface-related noise which varies temporally. However, seismic monitoring with FWI of time-lapse borehole seismic data may offer a solution for these issues. FWI is capable of detecting small velocity changes such as those associated with pore fluid substitution. Furthermore, borehole seismic surveys may provide more highly repeatable, higher quality data compared to surface seismic surveys because borehole seismic data is less affected by surface-related noise. This study consists of two parts, a field data analysis and a synthetic study. In the field data analysis, we studied the resolution and repeatability of FWI results at field-data quality, including the presence of actual noise using time-lapse VSP data. VSP data was acquired at the very early stage of EOR and there was no CO2 injection in the time between the two time-lapse VSP surveys. As a result, a high-resolution P-wave velocity model, consistent with a sonic log, was obtained. The P-wave velocity model also revealed excellent repeatability between the two survey data sets. In the synthetic study, time-lapse FWI was performed using synthetic VSP data representing pre- and post- CO2 injection periods. The results of the synthetic study showed that even in the presence of realistic 4D noise, which was estimated in the field data analysis, FWI successfully delineated the distribution of velocity changes caused by CO2 injection when the cross-sectional area of the injection-induced velocity changes were larger than the resolution of the FWI results. With these results, we demonstrated that FWI using time-lapse VSP data was applicable for CO2-EOR monitoring in the field as long as the criteria were met. This conclusion encourages the application of FWI using time-lapse VSP data for CO2-EOR monitoring in onshore Abu Dhabi.