bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Wellbore Modeling for Multilayered Gas Condensate Wells with Water Vapor Content Using Olga: A Case Study in Camisea Field.
Authors: Dorival Vargas Jose Miguel , Zuloaga Molero Pavel , Segama Candiotti Elizabeth , Gomez Erik 
Published: November 2019

Abstract
This paper discusses the historical evolution and future performance of wellbore dynamics in a multilayered gas condensate well (100 MMSCFD) in the Camisea Field - Peru. The analysis included the modeling of water vapor content produced within the gas condensate stream and its multiphase behavior and interaction with other fluids inside the borehole through the reservoir depletion under commingled production. The goal of this study is to quantify the impact of the wellbore dynamics in well deliverability and the effective recovery of hydrocarbons for each individual layer, and propose actions to achieve an optimum production scheme.
The approach is based on the modeling and matching of dynamic behavior of the wellbore and individual layers with the observed data during 9 years. For this purpose a dynamic wellbore model was built using OLGA. The inputs to the model are: 1) the properties for each productive layer characterized using multirate test combined with PLT logs to get the individual IPR's; 2) the model of the reservoir fluid to properly represent the retrograde condensation and the behavior of water in the vapor phase; and 3) the liquid levels in the wellbore from historical PLTs and density logs.
In the field case studied, the analysis showed that the water vapor present in the fluid stream is a fundamental key to understand the evolution of fluid levels inside the wellbore. This is quite important since the water in the gas phase is not usually included in the EOS for reservoir simulation purposes and its impact in the wellbore dynamics is neglected because of the very low BSW (less than 1%). For the well that has been studied, the analysis revealed that the lower zone was prone to stop producing due to the higher productivity of the upper reservoirs. Consequently, the increase in liquid level was a result of the production decrease and not vice versa. After the lower layer stopped producing, it was observed that there was a quicker increase of the liquid column between the upper and lower reservoirs. This column was mostly condensate but it was gradually replaced by water in the liquid phase, which came from the vapor phase produced in the upper reservoirs. This slow replacement represents a more restrictive condition for the lower reservoir, as the column becomes denser.
This study allowed for the understanding the complex interaction between retrograde condensation and water vapor behavior with the wellbore dynamics. The study also describes the process of the liquid accumulation during the decline of production of multilayered reservoirs which was successfully matched with observed data. As a result of the analysis, a new completion scheme was proposed to effectively recover the hydrocarbons in the layers affected by liquid loading issues.
Automated & Enriched Reservoir Inflow Performance Relationship Expedites Massive Wells Diagnosis to Assist Production Engineering Decision Making, Maximize Efficiency and Overall Asset Performance
Authors: Davila Rayner , Caicedo Sergio , Rubio Erismar 
Published: November 2019

Abstract
Enriched Reservoir Inflow Performance Relationship (ER-IPR) is a novel, expert and intuitive surveillance tool to manage by exception underperforming wells, using smart analytics for well problem classification, prescribe possible remedial actions or opportunity generation as well as predicting wells that potentially will cease to flow, exploiting smart field architecture capabilities by adding value to big data through meaningful visualization plots.
Although existing intelligent systems (IS) updates massive amount of well models automatically, engineers require high expertise and time to understand well performance, identify root cause problem and capitalize opportunities. The ER-IPR is a holistic approach that display multiple well operating-points in one normalized reservoir performance curve that systematically drives users to identify underperforming wells, along with their associated problems and give insights of the reservoir management strategy by implementing simple four steps: 1) Obtain all well operating-points from IS. 2) Generate the ER-IPR. 3) Execute expert diagnostic module. 4) Perform short-term production forecast for the highlighted problematic wells using Integrated Asset Model.
The tool was tested in a Digital Oil Field (DOF) in two different reservoirs. One reservoir is an anticline with a strong compositional gradient starting from gas condensate to black oil with saturation pressure and GOR varying in a wide range. The other one is an undersaturated reservoir under peripheral water injection with very stable bubble pressure and GOR across all areas. ER-IPR facilitates reservoir/sector/well performance review, providing proper well diagnostic evaluation as well as recommending possible remedial action based on analytics that consider the physics phenomenal of the production system and user performance acceptance limits according to field real time data observation. ER-IPR tool automatically compares, classifies and visualizes all wells simultaneously, translating big data in effective recommendations to sustain/increase production. ER-IPR minimize the number of inactive strings by proactively identifying wells that potentially will cease to flow, prioritizing well remedial actions, considering production forecast analysis and resources. ER-IPR enables proactive surveillance and monitors well performance thought nodal analysis over time, to have fully well behavior assessment and instantaneous asset awareness.
An Efficient Method to Control Oilfield Wells Through Advanced Field Management Ensemble Based Optimization Capabilities
Authors: Abbas Hicham , Mustapha Hussein 
Published: November 2019

Abstract
Field development optimization is a crucial and important problem considering economic and physical constraints. Advanced technologies such as smart wells and completions, and well performance optimization, allow for maximizing recovery without the need of additional drilling activities and all associated costs. This type of strategy applies to mature and challenging heterogeneous reservoirs with water and gas coning, and to low permeability and gas condensate deposits, and others. The presented method elegantly considers all field constraints and delivers predictive optimal well control settings taking into consideration reservoir uncertainties and offers optimized development strategies while minimizing on risk and cost.
We will present a new field development technology to optimize well performance in both oil and gas fields. The methodology allows for simultaneous optimization under uncertainty of multiple wells using surface constraints and subsurface flow control devices. The method is very fast and uses a combination of gradient and stochastic methods. Starting from an ensemble of realizations of the reservoir model, the best well control settings are searched using a steepest ascent gradient search method, where the search direction can be approximated using the cross covariance of the ensemble of objectives predicted using cloned reservoir simulations for a user defined future time horizon. The workflow solution employs several levels of computational complexity reduction combining advanced hardware architecture and localization algorithms to speedup optimization procedures and cover wider range of spatial uncertainty.
We present two examples that include control of surface liquid rates of producers and injection rates of injectors as well as controlling the flow control valves of producer and injector wells to demonstrate both efficiency and robustness of the optimization method. The method presented is very robust and offers with the highest confidence optimal field developments making best use of the most advanced software and hardware technology. The novel presented process results in significant cost reduction on drilling and other operational activities.
Development and Application of IoT Platform for Gas Lift Recovery
Authors: Yu Lei , Wei Wu Zhenghua , Zhigang Fang , zhensong Wang 
Published: November 2019

Abstract
Gas Lift Recovery IoT Platform is integrated IoT management and control platform self-dependently developed by Tuha Gas Lift Technical Center. Via real-time monitoring parameters e.g. surface tubing, casing pressures and gas injection volume etc., the behavior of gas lift valves can be reversely inferred by the platform. Through the control of the gas injection rate, the diagnosis of malfunctioned well and system optimization can be realized.
As to software, based on calculation method, basic logic algorithms for failure diagnosis & behavior diagnosis model are established. Further, by taking the profit maximization as target, mathematical model for gas lift system optimization is established. By taking mathematical model as core, early warning diagnosis & system optimization modules are developed. Further, the database, interactive expert and control & communication modules are developed. For hardware, based on flow characteristics, a new method based on flow measurement for variable opening degrees of regulating valve is proposed and flow control method of regulating valve based on incremental PID control is proposed.
As to software development, via study, the real-time monitoring and optimization diagnosis software for gas lift recovery IoT platform is formed, capable of realizing real-time diagnosis of gas lift well behavior and real-time optimization of the system. For hardware development, the integrated device for gas flow detection and control with STM32 as the core is developed. Through flow & opening control experiments, it is verified that the average measurement accuracy is up to 96%, the average control accuracy is 97.1% and the precision control of remote gas injection is realized. In combination with the control & communication modules for real-time monitoring, optimization and diagnosis software, the closed-loop control for gas lift recovery IoT platform integrating field data acquisition, remote diagnosis & optimization and field feedback execution is formed.
Gas lift IoT platform features safety, efficiency and good economics, capable of realizing real-time monitoring of production parameters as well as remote diagnosis, troubleshooting and production optimization etc., which significantly saves cost and could make up for the insufficiency of resources at fields.
Synchrotron-Based X-ray Micro-Computed Tomography for Real Time Investigation of Alkaline Surfactant Flooding
Authors: Aborshaid Hussain , Alzahid Yara , Mostaghimi Peyman , McClure James , Chen Cheng , Sun Chenhao , Armstrong Ryan , Asali Muhannad 
Published: November 2019

Abstract
Alkaline Surfactant (AS) flooding is an enhanced oil recovery (EOR) method to mobilize residual oil. Deatailed understanding of transport during these recovery mechanisms requires detailed pore-scale studies. This point leads to the utilization of X-ray imaging for its application in pore-scale characterization. Synchrotron-based X-ray imaging is an advanced technique that is capable of capturing the dynamics of pore fluids at the microscopic scale. The aim of this project is to investigate the pore-scale flow of AS flooding at two different salinities in carbonate rocks using real time 3D images collected by synchrotron-based X-ray imaging. The morphologies of the non-wetting phase are first computed, and oil recovery in the two scenarios is estimated. In addition, the wetting states of the two conditions are assessed by contact angle measurements. It was observed that optimum, or Winsor type III mobilized more oil, since it yielded a higher recovery value, as compared to under-optimum or Winsor type II-. Alkaline surfactant at optimal salinity was marked as an ideal condition that effectively reduces interfacial tension (IFT) to mobilize residual oil. This study provides insights in the pore-scale flow mechanisms that occur during AS flooding, which are important for understanding the basic EOR mechanism of this particular flood.
FEED Competition for Mega Upstream Projects
Authors: Al Ali Salah , Al Habshi Shaikh , Al Ashqar Ameed , Bin Ruken Saud 
Published: November 2019

Executive Summary
In accordance with the Global trend in Oil & Gas industry to invest in innovation and smart growth and capital efficiency (Project Light), Al Yasat has launched a new contracting scheme for the accelerating the development of its marginal oil fields. In view of difficult oil recovery cost and ease of contractor capacity due to nearing completion of previous field developments such as SARB and Umm al-Lulu, Al Yasat has contracted three EPC firms to compete on Front End Engineering and Design of the Belbazam field development with a grand prize for the winning design being selected to immediately proceed to Engineering, Procurement and Construction. The two losing bidders will be awarded consolation prizes in the form of partial recovery of their investments on the FEED. The attraction of this contracting scheme derives not from cost savings during the FEED stage, but most importantly from the omission of the bidding process for the EPC stage, with the winning contractor bearing full responsibility of their design whilst being fully deployed, with little to no variation costs.
This paper discusses some of the success factors and concerns associated with design competition from a Clients perspective, with the objective of extracting the difficult oil from marginal fields in a profitable context.
Effective Supply Flow Control: An Oil And Gas Capital Project Case Study
Authors: Arbulu Roberto , Shenoy Ramachandra 
Published: November 2019

Abstract
In an earlier report, Professors Iris Tommelein and Glenn Ballard of the University of California, Berkeley, analyzed the underlying principles of the construction practice of Advanced Work Packaging (AWP) and provided a critique to its standard design, making a number of predictions. Fundamental in their critique is the operations policies and parameters that dictate the final behavior of a project production system when AWP is applied. They predicted undesirable consequences to the performance of project production systems including, but not limited to, inventory growth, longer cycle times, lower labor utilization and higher costs.
Using an Operations Science framework, this paper reviews a capital project example that implemented AWP and uses this project experience to validate each of the predictions previously made by Professors Tommelein and Ballard. This paper also introduces the technical approach that the owner operator adopted to address the project performance gaps created by AWP, which included the application of CONWIP control protocols for more effective control of supply of materials and permanent equipment to the point of installation.
MEIDP – India's Transnational Pipeline from the Middle East
Authors: Nash Ian , Spradbery Chas 
Published: November 2019

Abstract
This paper presents details of the development of the Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth.
High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets.
The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The pipeline project history and current design status will be reviewed together with findings of the Marine Reconnaissance survey between Oman and India. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan. The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas.
As a project that builds from the Oman-India project of the 1990's; the changes in risk profile in terms of industry and vessel readiness are reviewed, and the readiness of the next generation of installation vessels to install such a pipeline is discussed.
Augmented and Virtual Reality Applications for Separation Solutions Improve Service Provider-Operator Collaboration and Technology Placement
Authors: Stephen Mark , Clarke Stephen , Kapila Ketan 
Published: November 2019

Abstract
Originally developed as an enhanced entertainment technology, advancements in augmented and virtual hardware catapulted the development and adoption of these tools for industrial applications and, more recently, the oilfield. These tools have vast use potential—from training to solution creation to operations. The benefits of newly developed applications for rigsite virtual mapping and holographic model viewing and the improvements they introduce for service provider/operator collaboration are discussed.
Conventional methods for rig survey execution and optimization for separation solutions, which include solids control and waste management technologies, can be time consuming, technically challenging, and costly. This can be particularly true for offshore operations where weather, logistics, drilling programs, and environmental regulations can rapidly increase project complexity. Additionally, the equipment selection process commonly involves communication and collaboration with multiple subject matter experts (SMEs) and operator representatives globally in an iterative and labor-intensive process that lends itself to the opportunity for miscommunication and errors.
The preliminary use of rigsite virtual mapping and holographic model viewer applications is to demonstrate improvements to cross-organizational collaboration. Using rigsite virtual mapping allows specialists to conduct a rapid wide area scan (RWAS) to accurately map the rig space to create fully functional and scaled three-dimensional (3D) models that can be used in augmented reality (AR) and virtual reality (VR) to develop more robust visualization of system design and placement. Using rigsite virtual mapping allows the separations solutions team to more safely, efficiently, and accurately measure and scan a rig space to achieve the optimal equipment orientation and integration. The improved visual assets enable better alignment with operator teams.
Using the holographic model viewer allows 3D models of where separation equipment can be placed within the physical space at the rigsite or in the office. On location, rig surveys can be enhanced by enabling personnel to more effectively identify obstacles that might impede installation. For the office, the service provider and operators can more effectively discuss technologies and technology solutions using enhanced visualization. Bringing the technology "into the room" enables more dynamic solution creation and ideation.
A renowned global research and consulting firm lists AR/VR as a major emerging technology trend that has the capability to influence how companies do business. The application of these technologies can revitalize remote engineering collaboration and personnel optimization and reduce service/product delivery costs. Already successfully introduced in other markets, AR/VR in the oilfield has the potential to expand rapidly and become an essential tool for more efficient operations.
Highly Scalable Digitalization Platform for Oil and Gas Operations Enables Total Asset Visibility for Predictive, Condition-Based Fleet Management Across Single and Multiple Sites
Authors: Settemsdal Stig Olav 
Published: November 2019

Abstract
This paper describes a sophisticated yet easy-to-use digital solution with dashboards arranged with a browser-accessible graphical interface that provides E&P operators with real-time, end-to-end transparency of their operating assets, whether located offshore, onshore or a combination of both. This condition-monitoring application is called SOGO (Siemens Oil and Gas Offshore). In a reacent deployment, the solution is condition monitoring up to 1,300 equipment assets including approximately 60 asset types. It incorporates artificial intelligence, machine learning, and digital twin concepts to help operators implement predictive, condition-based maintenance and fleet management across single and multiple sites. Ample illustrations will enable readers to visualize the application’s use. Readers will gain insights to how digitalization can radically transform their management of operational assets to achieve quantum improvements in efficiencies, transparency, decision-support, and responsiveness, while gaining wholly new diagnostic, mitigation, and remediation capabilities.
Making the Case for Dry Low Emissions Technology in Offshore Oil and Gas Applications
Authors: Bulat Ghenadie , Rickert Matthew 
Published: November 2019

Abstract
This paper focuses on the use of gas turbines (GTs) equipped with Dry Low Emissions (DLE) combustion technology in offshore oil and gas (O&G) applications. The paper presents information from offshore GT units and discusses improvements in operational reliability and fuel flexibility that have been achieved as a result of extensive testing on combustion systems. These improvements, coupled with significant NOx emissions reductions have made DLE gas turbines a viable alternative to non-DLE gas turbines, the latter of which have traditionally dominated the offshore market.
Field operating data will be presented on three lightweight industrial gas turbine models that have been offered with DLE as a standard configuration for over 20 years. Currently, 394 units operate in offshore applications. The DLE configuration has accumulated more than 22 million hours of service. The paper outlines the performance, reliability, and fuel profiles of the current offshore fleet, confirming that DLE combustion systems have now achieved reliability on par with non-DLE combustion systems.
A brief review of the testing experience proving the reliability and the range of fuels that can be burned within the DLE system will also be discussed in the paper.