bluuebunny/crossref_metadata_2025_split huggingface dataset:
Qualification of a Subsea Sulphate Removal System
Authors: Plasencia Jose , Sabedotti Sergio , Andrews Abel , Costa Ana , De Almeida Cristina , Nunes Elizabete , Santos Gabriel , Martins Filipa , Ribeiro Mario , Andreotti Marcelo , Russo Juliano Diego 
Published: April 2020

Abstract
This paper presents the ongoing development and qualification program of a subsea sulphate removal and injection system and provides an overview of the system together with the features that enable its operation subsea. The ongoing development program has completed a dry piloting phase that focused on the design of the system, subsystems, assembly of the pilot and qualification of the process, including the modified operation of the filtration technologies. This development is in cooperation with 5 leading global oil companies. The pilot operation took place over a period of 6 months.
Injection of seawater to provide reservoir pressure support is often the choice to increase oil recovery in a field. Traditionally, large and heavy topside processing systems are deployed to treat and inject seawater. This creates significant operational challenges, especially in brownfields, where topside space and weight capacity are constrained. Moving the system to the seabed will greatly reduce the capacity demand imposed on the floating facility and will eliminate the need for an expensive high-pressure riser and flowline system. The subsea system requires a different operational approach in which the conventional chemical cleaning is eliminated. Special design considerations must be made to maintain operational robustness without the chemical cleaning in place unit.
Baker Hughes and its partners are proposing to move the seawater treatment system to the seabed to simplify and debottleneck the topside facilities and reduce the total cost of ownership. Seawater treatment systems for injection are conventionally topside units. Necessary operational modifications have to be implemented to enable its reliable operation in subsea conditions. These modifications are being validated through piloting.
New Generation Fracturing Fluid
Authors: Perez Oswaldo J. , Lin Genyao , Fragachan Francisco E. , Le Hoang , Qu Qi 
Published: April 2020

Abstract
In the past, high-viscosity fluids have been the preferred method for increased proppant suspension and transport. This methodology has been effective using systems such as borate-crosslinked fluid with the downside of considerable damage to the proppant pack, typically resulting in about 85% percent regain conductivity. While this may still be acceptable, the major limitation of these systems is the additional loss of needed fracture length. Often, with low viscosity fluids such as linear gels and friction reducers, fracture length may be established allowing breaks into the secondary fractures and mechanical reactivation of the pre-existing natural fracture network may be enhanced. However, these low viscosity fluids cannot offer efficient suspending characteristics within the fracture under static conditions, which may lead to early settling. As a response to this industry demand, a novel fluid has been developed to optimize the hydraulic fracturing process by enhancing proppant transport with reduced friction losses, less fresh water requirements and smaller footprint of pressure pumping equipment.
Novel fluid technology from which the polymer was engineered to form a network of packed structures from polymer associations providing the maximum proppant suspension, breaking with the traditional concept relying on viscosity to enhance proppant transport during treatments, is described with extensive experimental testing. The results show that the fluid exhibits outstanding properties and benefits to transport proppant without settling in addition to a considerable reduction in fresh water requirements and maintenance costs associated with surface equipment footprint, as the current trend is unsustainable.
New physics consisting of a hybrid rheology analytical model and fluid structures to correlate elastic fluids rheology parameters, firstly, n′ and k′ values, and secondly the storage, and loss moduli profile (G′ and G″ accordingly), is presented. The complex fluid behavior deviates from common rheology models and, its elastic properties, such as storage modulus (G′), loss modulus (G″), and angular frequency (rad-sec) are discussed in the context of the unique fluid characteristics of a network of packed structures from polymer associations. Physics-based analytical model results compute the viscosity, and elastic parameters based on shear rate to calculate the pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture, optimizing horse power requirements based on reduced pressure loses, will be presented [16].
The presentation will demonstrate that such physics and unique fluid behavior are achieved via a novel elastic and a network of packed structures from accociative polymer fluid, having proper proppant suspension, effectively placed at low viscosity, less fresh water requirement, low injection pressures, with no settling and 98% retained conductivities.
Subsea Local Heating, a Versatile Thermal Booster to Optimize Flow Assurance
Authors: Anres Stéphane , Muguerra Philippe , Bacati Fabrice , Hallot Raymond , Capela-Moraes Carlos Alberto , Valdenaire Thomas 
Published: April 2020

A new technology called Local Heating offers the possibility of significantly raising the temperature of the multiphase production fluid in order to improve flow assurance and consequently the economics of field developments. Heating the flowlines is a way to overcome the thermal constraints, mitigate hydrate & wax risks and provide operational flexibility. Indeed, in the case of long tiebacks, very deepwater applications or when the fluid temperature at the wellhead is too low, conventional flow assurance solutions might be very expensive or even not applicable.
While other heating technologies such as DEH and Heat Tracing have been designed mainly to operate under transient operations (start-up, shutdown, preservation), this heating technology can be operated continuously during production and also during transient operations as long as there is fluid circulation in the flowline. The device is a very simple and robust system integrated into a compact subsea module, installed in parallel or in-line with the main flowline and which can be retrieved for maintenance or relocated. It is compatible with any type of field architecture and can be implemented either on greenfields or brownfields. In the case of greenfields, the use of Local Heating could also be a way to mitigate uncertainties on production fluid temperature or solve an unexpected poor thermal performance of the design. This solution is based on induction and is therefore able to provide very high-power levels (several MW) with a compact module. The temperature is continuously monitored throughout the heating module by means of fiber optic distributed sensors. The technology is fully compatible with preservation by flushing and allows pigging in the event of deposits.
The main principles of the technology will be described in the paper, as well as a preliminary design performed for a specific case provided by an operator.
The paper will also present the qualification work recently performed including heating performance lab tests using a small-scale submerged prototype operated under atmospheric conditions with multiphase fluid. The tests have confirmed the good electrical and thermal behaviour of the system.
The paper finally describes the last qualification phase the objective of which is to install a subsea pilot to be connected to a subsea production system on a field located in Brazil. The intention is to perform this work in the frame of a Joint Industry Project.
A Cloud-based Computational Framework To Perform Oil-field Development & Operation Using A Single Digital Twin Platform
Authors: Chowdhury Khairul , Arif Akhteruzzaman , Nur Md Nuruzzaman , Sharif Omar 
Published: April 2020

Abstract
Building a digital oil-field or digital twin, without involving multiple digital partners, and costly time-consuming digital endeavor is a significant challenge in Oil & Gas industry. In most cases, such systems are capable of data integration and visualization for only a part of an oil-field. Real-time analytics is missing to transform the digitalization into a smart and scalable system. The objective of this paper is to present a digital oil-field creator driven by a computational framework to perform key analytics for oil-field life cycles.
A computational framework, networked with decentralized analytics engines that are equipped with a predictive analytics computation system, and an automated design engineering system has been developed. The predictive analytics computation system performs engineering design using data, pipeline integrity, platform structures, and coupled systems integrity and equipment integrity. The automated design engineering engine performs conceptual and FEED for subsea elements such as pipelines. These computational engines are then integrated into a self-service 3D digital twin creator for the user to operate on the front end and to receive analytical insights.
3D digital twin creator is capable of creating oil-field architecture within a fraction of the time utilizing the traditional model. Additionally, the creator optimizes the subsea architecture based on a selected set of criteria including CAPEX or OPEX costs. The system then performs conceptual or FEED level engineering including finite element analysis (FEA) using automated engineering saving as much as 80% of engineering time. Finally, the digital model is able to conduct asset integrity predictive analytics using machine learning from the monitored data. A Gulf of Mexico (GOM) oil field concept architecture was created by the digital twin creator and the computational framework. The system performed an automated pipeline conceptual optimization, buckling and free span design, and finally conducted riser integrity and equipment integrity. The computational framework is flexible and scalable to incorporate any organization's existing engineering process.
The multidisciplinary complex analytics systems are networked in a way to maximize the integration of multiple oil-field systems from multiple companies and their asset's operational status in a 3D visual without a complex or expensive digital system. This digital system not only integrates multiple phases of the oil-field life cycle but also allows the reuse of all processes across different projects and time.
Pressure Losses Calibration in Managed Pressure Drilling
Authors: Ilin Andrew V. , Brana Jose D. , Ameen Rostami Sayamik N. , Koithan Thomas H. 
Published: April 2020

Abstract
Managed Pressure Drilling (MPD) usage is in increasing demand in both offshore and onshore market – especially for wells with narrow drilling pressure margins. Maintaining desired constant Bottom-Hole Pressure (BHP) within given range during MPD operation requires accurate hydraulic modeling for frictional pressure losses. Surface BackPressure (SBP) and StandPipe Pressure (SPP) data, measured in real-time, allows the calibration of frictional pressure losses and an estimation of BHP more accurately.
An estimation of SPP is calculated based on integration from the measured SBP back to the inlet in the hydraulics model. The pressure loss increment in the hydraulics model is calculated based on a difference between the measured and estimated SPP value. The system parameters are monitored during drilling and could be adjusted based on the hydraulics model corrected for the pressure loss. The frictional pressure loss due to the drilling pipe rotation could be calibrated by analyzing a difference between the measured and estimated SPP for two operations: without rotation and with rotation.
This work underscores the development and usage of advanced hydraulics modeling to accurately calculate BHP during MPD operations. In current hydraulics, mathematical models have been developed to account for various operating parameters, wellbore geometry and fluid properties. This is an enabler to estimate pressure, density, rheology, temperature, and cuttings distributions within the wellbore, drill string and surface equipment more precisely. The frictional pressure loss model includes rotational pressure losses, local pressure losses at special tools and tool joints. This model is based on empirical sub-models which require experimental verification for accuracy. The results of the BHP, calculated with a calibrated hydraulic model, are compared with corresponding results calculated with the uncalibrated model.
The use of the pressure calibration for the hydraulics model allows estimating BHP with less error. Recommendations are presented for the accurate mathematical modeling and their applicability and limitations for successful MPD operations.
Acceleration of 4IR Driven Digital Transformation Through Open Source: Methods and Parallel Industries Knowledge Reapplication in the Field
Authors: Haroon Sammy Sarblund , Viswanathan Aruna , Alyamkin Sergey , Shenoy Ramachandra 
Published: April 2020

Abstract
In the age of open source, oil and gas companies that invest in licensing proprietary platforms to build artificial intelligence (AI) solutions will have to closely guard against obsolescence. While the mathematics behind AI has existed for decades, its rapid adoption in virtually all sectors has been powered by open source, where a global community of academicians and data scientists are continuously developing and improving the mathematics behind the predictive and prescriptive solutions of the future.
We posit that the existence of AI software development, which we describe as data driven analytical solutions providing predictive and prescriptive answers to questions, is solely due to the academia's focus on research and its pedagogical goals driving the dissemination of the research to the open source community to move the research to development. Indeed, all data science coursework is steeped in training on open source platforms and tools. When models do not depend on platforms, organizations can deploy flexible and agile software that has the ability to leverage better methods that come out in the future. Borrowing ideas from other industries we can see that just as Wordpress and its open source community of designers and developers revolutionized how websites are created, software that can quickly deploy the best available technology (and be mobile) while maintaining the security of the data is poised for user adoption and success where legacy systems and traditional dashboards fail.
While the mathematics of physics does not change our confidence in its accuracy, in comparison, the mathematics of an AI algorithm is an approximation. This mathematics is being continuously improved though rarely achieving 100% accuracy. Algorithms are built upon open source AI libraries that are continuously improving. Similarly, the methods and techniques for developing the AI algorithms in oil and gas are continuously improving through two main sources, academia and adjacent industries reapplication of AI methods. We provide examples of open source technologies already part and parcel of all data scientists' repertoire of development, who are currently working in oil and gas. We further showcase reapplication of solutions from other industries, such as, medical image data analysis to seismic data processing and subsurface characterization.
Integrating Electrofacies and Well Logging Data Into Regression and Machine Learning Approaches for Improved Permeability Estimation in a Carbonate Reservoir In a Giant Southern Iraqi Oil Field
Authors: Al-Mudhafar Watheq J 
Published: April 2020

Abstract
Integrating discrete facies classification into the estimation of formation permeability is a crucial step to improve reservoir characterization and to preserve heterogeneity quantification. Therefore, it is essential to obtain the most accurate estimation of permeability in non-cored intervals in order to attain realistic reservoir characterization and modeling. In our most recent paper [OTC-30906-MS], the electrofacies classifications have been conduced for a well from a carbonate reservoir in a Giant Southern Iraqi oil field. The same predicted discrete electrofacies distribution was included in this paper along with well logging interpretations to model and predict the reservoir core permeability for all wells. The well logging interpretations that were included in permeability modelling are neutron porosity, shale volume, and water saturation as a function of depth. The regression and machine learning approaches adopted for permeability modelling are multiple linear regression (MLR), smooth generalized additive Modeling (SGAM) and Random Forest (RF) Algorithm. The classified electrofacies were considered as a discrete independent variable in the core permeability modelling to provide different model fits given each electrofacies type in order to capture the different permeability variances.
The matching visualization between the observed and predicted core permeability, the computed root mean square prediction error and adjusted squared R were considered as validation and accuracy tools to compare between the three modelling approaches. Since there are too many intervals with missing core permeability measurements, the modelling was first adopted on the intervals that have permeability readings (known subset). The prediction was then conducted given the same known permeability intervals in addition to the entire dataset (full dataset). The root mean square prediction error and adjusted squared R for the Random Forest were significantly better than in both MLR and SGAM for the known subset and full dataset. It can be concluded that combining the electrofacies in one permeability model has accurate, fast and an automation procedure of prediction for other wells. The two machine learning algorithms were implemented by R software, the most powerful statistical programming language.
Hydrate Management Controls In Saudi Aramco’s Largest Offshore Nonassociated Gas Fields
Authors: Soliman Sahweity Mohamed Ahmed 
Published: April 2020

ABSTRACT
Hydrate management is a major challenge for offshore oil and gas fields, and in subsea pipelines transporting gas from offshore platforms to the onshore processing facilities. This paper is intended to discuss the various hydrate control methods and strategies that have been evaluated and implemented during the project's design, startup, and operation stages to come up with the most efficient and economical solution for hydrate mitigation.
Methanol, MonoEthylene Glycol (MEG) and kinetic hydrate inhibitors (KHIs), as well as Twister Technology, were evaluated to act as hydrate prevention mechanisms. Based on the CAPEX, OPEX and unmanned operation philosophy, KHI was used for hydrate inhibition in the gas Field-A. This paper will discuss different innovative strategies to eliminate hydrates during steady-state and transient operations. It will also consider cold startup, maximum flow and minimum temperature, planned and unplanned shutdowns, depressurization, and purge and pilot gas scenarios.
The optimum hydrate management control for Field-A offshore platforms and subsea pipelines was a combination of different strategies. For the Field-A, KHI and MEG injection were utilized in combination or independently depending on the scenario.
The challenges experienced during the commissioning, startup and operation of the first Saudi Aramco offshore facilities resulted in many potential innovations and patents as follows: Development and installation of the PMS resulted in reducing the operating cost.Development of variable speed pipeline pig technology.
The challenges and lessons learned associated with hydrate management will be discussed in addition to the advantages and disadvantages of the used chemicals.
Multilateral Expandable Metal Anchoring Packer Design, Development, and Application in the North Sea
Authors: Kelsey Matthew , Stautzenberger Arthur , Einervoll Olav , Dietz Wesley , Lajesic Boris , Stokes Matthew 
Published: April 2020

Multilateral technology can provide a higher recovery factor of hydrocarbons by achieving a longer field life supported by the cumulative production of the multiple laterals, turning otherwise unviable reservoirs into economically sound targets while keeping construction costs down and minimizing risk.
Application of expandable liner hanger technology to junction creation in multilateral wells can improve completion efficiency and flexibility by offering increased tensile and torque ratings along with larger IDs over previous solutions.
This paper highlights the development, testing, and a successful case study of a new expandable anchor packer designed for a multilateral TAML Level 5 application in the North Sea.
Well construction has changed in recent years with more operators turning to multilateral technology due to slot-constrained pads and a desire to increase reserves by combining targets that are separately uneconomical or improving the efficiency by extending the life of mature fields. The foundation to constructing a multilateral well is a reliable main-bore anchor point, which provides a service tool landing point from which a casing exit window is milled, and a lateral leg drilled and completed.
Using an expandable anchor packer, based on an existing expandable liner hanger design widely accepted in the industry, provides a broader scope to position and orient the packer at the desired depth to begin lateral construction while providing increased completion flexibility through increases in tensile, torque, and ID capabilities. These improvements provide the capability to deploy screens directly below the anchor packer, eliminating the need for a separate trip with a liner deployment system (LDS). The larger packer ID makes the system compatible with a field-proven multibranch inflow control (MIC) junction.
This new approach to an anchor packer for a multilateral TAML Level 5 junction provides not only increased load, torque, and ID capability, but improved sealing reliability as well. Validation testing has confirmed that the high-performance, advanced metal-to-metal sealing technology of this new expandable anchor packer provides a compliant metal-to-metal seal with a fully bonded resilient elastomeric seal, which can compensate for imperfections in the parent casing and provide isolation to a potential gas cap in the main bore below the lateral window.
By employing field-proven expandable liner hanger technology with its superior load, geometry, and sealing capabilities to multilateral TAML Level 5 junction creation for a North Sea application, improved efficiency and flexibility in the completion can be achieved.