bluuebunny/crossref_metadata_2025_split huggingface dataset:
From On-Orbit to Offshore: Shared Challenges, Collaborative Solutions
Authors: Callini Gianluca 
Published: April 2015

Abstract
Space is an extremely harsh environment that does not naturally support life. The challenges faced by the Space Program since its inception in the 1960's span from extreme temperature ranges, to pressurized systems, low pressure environments requiring remote operations, and countless other obstacles, including training of personnel for dealing with these hazardous environments in a controlled and safe manner. This paper provides an overview of the shared challenges, gives an overview of NASA's collaboration and innovation initiatives, and presents technologies and solutions envisioned to be beneficial to offshore industry.
Broadband Seismic Well-tie And Data Conditioning For Quantitative Interpretation
Authors: Naeini Ehsan Zabihi 
Published: April 2015

Abstract
Broadband seismic data will only deliver its full reservoir value if a quantitative interpretation is possible; I discuss some challenges and solutions to achieve this goal. Enabling a quantitative Broadband well-tie is a vital and the fundamental part of quantitative interpretation workflow for broadband seismic data. Without it we simply cannot achieve the full value value because we cannot incorporate some or all of the low frequencies. Appropriate data processing, and if required reprocessing, and further seismic data conditioning are also a prerequisite to make sure the S/N is high over all the bandwidth.
An Alternative Approach to 50 Years Design Life
Authors: Hernæs Sigurd , Aas Torgrim 
Published: April 2015

Currently there have been seen requirements of a design lifetime far beyond the 20-25Y of today, a strong driver is that many fields have their lifetime extended due to they contain remaining resources that can be recovered with IOR measures. As a result, some operators consider extending their Design Lifetime requirement significantly.
This paper briefly discusses the reason for this requirement and its consequences from a Subsea Production System suppliers view. Further is given an alternative approach to a long set design lifetime, where the goal is an undefined lifetime based on monitoring and maintainability. The concept is outlined and consequences are discussed. The following issues are covered:
Inspection
Monitoring
Design for maintenance
Need for New Technology
The paper addresses Operator and Subsea Production System suppliers' technical decisions makers.

The paper is based on a Subsea Production System suppliers experience and challenges through Delivery projects, Lifetime and Front End studies.

The paper will conclude that a set Design Lifetime considerably longer than todays is not favorable and that the proposed new approach is a better choice. Further, is this approach also recommended as a result of experience with Lifetime Extensions studies, as the new approach will simplify this kind of work considerably. This is due to monitoring and documentation of status on a regular basis, is an inherent part of the approach proposed.

The paper brings into the debate a new approach to Design Lifetime.
Well Integrity as Performance Metrics in Deepwater Drilling
Authors: Samuel Robello , Das Bibek 
Published: April 2015

Abstract
As offshore conventional oil and gas sources are declining, we are drilling more in extremely high-pressure/high-temperature, ultra-deepwater environments. To ensure well integrity in this scenario demands not only the application of new technologies but also stricter safety procedures and dependable equipment and systems from bottomhole to the drilling rig. Industry standards, like NORSOK D-10 and API 65, and recommended practices, like API RP 96, have defined well integrity and given a high-level overview on its significance. However, the questions that still lie in front of us are (1) how to implement well-barrier engineering in the performance metrics to make real-time decisions, and (2) how to integrate various aspects of the formation, well condition, new drilling technologies, and technologically advanced drilling rigs to ensure well integrity.
Maintaining well integrity and preventing loss of containment throughout a well?s life is achieved through effective and efficient operation of both physical and operational barriers. Hence, the focus on well integrity should be established by defining the minimum functional and performance-oriented requirements for the barriers through well design, planning, construction, completion operations, and interventions during its producing life. Such performance-oriented requirements should also be integrated with rig operations, including drilling, support, and marine systems.
One of the key performance indicators of barrier effectiveness is reliability. The important fact to note is that the barrier resistance will change over the life of a well owing to loads induced by different operations and changing well conditions. Conventional reliability analysis does not take into consideration the engineering assumptions and calculations (mechanical, fluid, and thermal) in barrier design. It also does not account for different operations and the stresses they impose on the barriers that will speed the barrier degradation. This paper presents qualitative methods to identify such load-case scenarios affecting the reliability of the well barrier and quantitative methods to analyze the change in reliability with time. Such techniques help in establishing the leading indicators of failure. Monitoring those indicators will aid in improvements in both equipment and process reliability. This paper presents and discusses some results of reliability analysis with examples of casing failure and subsea equipment-failure analysis.
We have often seen the terms, well integrity and well reliability, being used interchangeably, which may not be technically correct and is discussed in the paper. The paper also covers some of the key topics, including definitions of well integrity, barrier reliability, and leading and lagging indicators of failures.
Subsea Solutions in the Pre-Salt Development Projects
Authors: Cezar A.S. Paulo , Pereira A. Rabello , Daniel L. Lima , Oazen E.V. , Trovoado L.C. , de Almeida M. Carpigiani 
Published: April 2015

Abstract
This paper presents the technical solutions adopted and implemented to develop the Brazilian pre-salt reservoirs, covering the main aspects of the subsea production systems already installed and in operation, that allowed overcome the challenges and turn the ultra deepwater pre-salt production into a reality that currently produces more than seven hundred thousand barrels per day.
The characteristics related to this particular ultra deepwater scenario are presented, highlighting the ones that demanded to push the envelope of the available technological solutions, considering the conditions are more severe than typical ones from the previous experience with Campos Basin development projects: presence of CO2 and H2S contaminants in the produced fluids; higher internal pressure; high CO2 content gas injection; deeper waters and more severe metocean conditions.
The aspects related to subsea trees, control systems, subsea manifolds, diverless connection systems, subsea flowlines, umbilicals and risers for the production systems are presented, as well as the flow assurance issues. The risers and pipelines for produced gas flow to shore are also covered.
Considering the large number of projects that would be required to develop the Brazilian pre-salt province, different riser system solutions were developed and applied, being now field proven and available for the industry. Several firsts and records were established and are presented.
The effort related to subsea equipment standardization, to cope with the large number of systems to be installed, is also part of this paper.
Similarly to the situation of Campos Basin in the 80's, playing the role of a big laboratory for technology development towards deep water production, Brazilian pre-salt scenario, and specially Santos Basin pre-salt province, is nowadays the site where technology development is taking place for ultra deepwater production of high GOR oil with variable CO2 content. Subsea systems are enabling such production and this technology enhancement will contribute for the future development of other areas with similar characteristics.
Deep Offshore - Needs for a Subsea / Topsides Integrated Approach
Authors: de Lacotte Luc Hême , Lopez Audrey , Rivière Luc , Anfray Jérôme 
Published: April 2015

Abstract
The subsea processing and advanced SURF (Subsea Umbilical Riser and Flowline) technologies are now being increasingly considered for challenging field architecture projects. This has been gaining experience and reliability for the past 10 years. Integrating subsea processing units in future field architectures will allow the Operators to address difficult flow assurance issues associated with increased water depth and step-out distances, to simplify the field lay-out and potentially to manage more difficult and complex reservoirs.
The implementation of subsea processing units largely affects the design of surface facilities and has therefore to be considered in the global process chain aimed at delivering hydrocarbons from subsea to shore. It is therefore essential to assess the potential benefits of subsea processing and advanced SURF technologies at a very early stage of a project by developing and optimizing a global design integrating all the production facilities, both on topsides and on seabed, as well as the flowlines, risers and umbilicals system.
In close collaboration with TOTAL, TECHNIP has completed a conceptual study for a challenging oil field development located between 2,500 and 3,000 m water depth. The study compares a conventional architecture based on proven and qualified technologies for the FPSO, subsea flowlines and risers with a novel architecture featuring new and pre-qualified subsea technologies as well as a rethought and simplified FPSO design. The present paper displays the outcomes of this comprehensive study performed by a multi-discipline team gathering all the TECHNIP Group EPCI capabilities and experience in Subsea and Offshore Segments, and the strong support of relevant TOTAL specialists.
The paper analyzes the interactions and interfaces between SURF, Subsea Processing and Offshore facilities "typical" EPCI packages, quantifies technology impacts on the global architecture and gives costs comparison elements.
Development of a Quantitative Approach to Risk Based Flow Assurance
Authors: Morgan J.E.P. , Zakarian E. 
Published: April 2015

Flow Assurance (FA) engineers usually produce a range of technically feasible solutions in response to a particular challenge. Often these solutions are cost neutral. In order for a development manager to select the optimum solution he/she examines the risk profiles associated with the options. To progress a marginal development, explicit understanding of financial risk is imperative, needing a step up from qualitative “gut feel” assessments to a more reasoned and auditable quantitative evaluation of FA risk.
As part of Woodside's Next Generation Flow Assurance Strategies initiative, Woodside embarked on a Joint Industry Project (JIP) called RiBFAT, standing for Risk Based Flow Assurance Toolkit. The main objective of this JIP is to develop quantitative risk profiles for FA solutions to the wide range of FA challenges. Phase 1 of the JIP produced a Proof of Concept for a risk based approach to hydrate management, one of the main FA challenges of cold ambient temperature field developments, typified by deepwater. Phase 2 was the conversion of the agreed methodology into fully functioning non-commercial software; completed by the end of 2014.
This paper discusses the methodology developed and illustrates how this can be applied to a field development concept in order to compare the risk profiles for alternative FA strategies for hydrate management. The risk profiles cover the life of the asset including additions / modifications to facilities as required to optimise the development of the reserves. Ongoing use of the methodology results in the production of a database of knowledge for each FA challenge, which may be interrogated for benchmarking or assurance purposes, allowing the user to develop greater confidence in a particular proposed strategy.
The methodology for addressing risk described in this paper will be extended in the next phase of the JIP to other FA challenges such as slugging, scale, wax and corrosion, building up to a comprehensive toolkit for FA risk assessment, including the database. Concurrently, we plan to document this methodology as the first ever global FA risk assessment recommended practice.
CLOV Project: Overview
Authors: Mouillerat Geneviève , Silva Francisca 
Published: April 2015

Abstract
This paper will describe the CLOV deepwater mega-project in Block 17, offshore Angola. This major development encompasses four separate oil and gas accumulations in waters up to 1,400 metres and aims to recover 505 million barrels of both light and heavier oil plus associated gas in sufficient quantities that will require an export solution to shore for inclusion in the Angola LNG project.
CLOV - which comprises the Cravo, Lirio, Orquidea and Violeta fields - is the fourth large-scale development in this block within the Angolan offshore sector executed by Total. Like the previous three, it is based around floating production storage and offloading (FPSO) vessel and an extensive subsea production system. The execution of CLOV benefited from lessons learned on the three earlier projects - Girassol, Dalia and Pazflor. This resulted in a successful project measured on technical and schedule parameters as well as cost control.
This project presents significant challenges in development including the drilling of 34 development wells requiring two drill ships and the equivalent of almost 2,500 drilling days.
The heavier oil reservoirs of Orquidea and Violeta need pressure and flow support and require the use of both a large water injection scheme (six subsea water injectors) making use of produced water from the FPSO and the installation of a seabed multiphase pumping system based on helico-axial pumps. The production wells have a range of completion designs and sand control methods.
The FPSO - a purpose-built unit of 305m by 61m with topside of 37,000 tonnes net dry weight - employs an all-electric power system with variable speed drives. It also makes use of the ‘wash tank’ technique for oil-water separation. Both are firsts on projects developed by Total.
The SURF (subsea umbilical, risers and flowlines) element of the project required three hybrid riser towers, nearly 100 kilometres of infield flowlines plus a 32km gas export line.
Lessons Learned From the Qualification Program and J-laying Campaign of 12-inch Steel Catenary Risers for the P55 Deepwater Project
Authors: Girault Etienne , Lirola François , Briand Erwan , Kerdilès Eric , Fatica Giulio , Mahn Denise , Schmidt Tanja 
Published: April 2015

This paper reports the Lessons Learned from an innovative linepipe solution that was successfully implemented on P55 Deepwater Project. The P55 field is located offshore Brazil, in the northern area of Campos Basin, in a water depth ranging from 1500m to 1900m. The scope of work consisted in engineering, procuring, fabricating and installing 16 rigid Steel Catenary Risers (SCRs), which are the first of their kind in this area. The corresponding 12-inch SCR qualification results are presented in the perspective to show the significant benefits of the technology used and its potential developments to High Pressure & High Temperature applications.
In order to meet tight Hi-Lo requirements together with high fatigue performances, innovative Pipe End Design and associated automatic welding procedures were developed and qualified. The paper describes the complete sequence of pipe manufacturing process, from hot-rolling to final machining, which resulted in a concentric and reproducible pipe end geometry, ideal for limiting Stress Concentration Factors.
An extensive qualification program of Full Scale Fatigue test was conducted on girth-welded strings and the associated results showed performance levels at least four times above the target curve. Moreover, Lessons Learned from the offshore campaign established that developed Pipe End Design led to significant improvements in welding times and subsequent J-laying rates. Details on how the technology effectively reduces critical times and lowers rejection rates are provided on the basis of the actual P55 offshore campaign.
In addition to the advantages detailed in the paper, the presented linepipe solution proves to be also applicable to High Temperature fields, since the enhanced fatigue behavior was found to compensate a temperature derating up to 270°C. In fact, the presented manufacturing and welding technologies have opened the perspective of ongoing Developments, which are believed to bring a reliable solution for combined High Pressure and High Temperature applications.
Wellbore Cementing: An Integral Part of Well Integrity
Authors: Bogaerts M. , Azwar C. , Bellabarba M. , Dooply M. , Salehpour A. 
Published: April 2015

Abstract
Well barriers are an important factor during the life of a well. As cementing is involved in many of those well barriers, there is considerable focus in the oil field on the design, execution, and validation of the cement as a well barrier.
It is important that the cement job design begins at the same time as the basic well design, especially in deepwater operations. Decisions made early in the well design can have a tremendous effect on the cement job execution. Early in the well design, the cement job objectives are set, and through simulations, the cement job placement, slurry design, and, in some cases, well design, are optimized to overcome any identified challenges and minimize risks during cement placement.
Cement equipment is becoming increasingly more sophisticated and cement job designs more critical; additional attention needs to be placed on the cementing job preparation on location prior to the actual cement job. By using the latest advances in communications, it is easier for the offshore cementing specialists to stay in contact with the shore-based staff; not only with the design engineer, but also the maintenance manager or operation support staff.
Improved monitoring and automation during the job execution enhances the process control. Advances in real-time capabilities enable the onshore experts to monitor the offshore operations and provide advice during the execution of the cement job itself.
The final step of a cement job is the evaluation phase. A cement job evaluation is more than just a pressure leak-off test or running a cement evaluation log. The evaluation procedure of a cement job ties together all the parameters of the job, including the job objectives, drilling parameters, job execution, and post-job test results. Looking at one parameter only will often not provide a complete analysis and evaluation.
Because cementing provides critically needed well barriers, it becomes a very important aspect in well integrity management during the life of the well.
Increasing the local workforce through innovative operator training on the CLOV project
Authors: Meyer Michaël 
Published: April 2015

Abstract
At early stage of the project, the CLOV project developed an innovative training with the target to certify new junior operators with a diploma (level 2 French Diploma) and hire them as operators for Total E&P Angola.
For the first time in an affiliate, CLOV conducted an 18-month training program in Angola divided in 3 steps: an intensive English course (3 months), a scientific refresher course (2 months) and the upstream operators certification (13 months) in cooperation with Institut Français du Petrole (IFP). This part-time training was divided into 22 weeks of scientific and technical courses and 18 weeks of "on the job training" meaning offshore training onboard FPSO. During all the period, numerous dedicated trainers from IFP and from Total E&P Angola were involved to supervise the trainees and interact with them.
At the end of this program, trainees were selected and certified as upstream operators and hired by Total E&P Angola.
Then they attended a "specific training" for CLOV. This new phase lasted 5 weeks during which the new operators had theoretical courses on CLOV facilities and hands-on exercises with a 3D tool, the Immersive Training Simulator (ITS). This ITS allowed them to familiarise with CLOV FPSO facilities and process, not yet achieved at that date.
Then, the new operators were sent in Korea to participate in the commissioning activities before the FPSO sail away. They continued their training onboard Block 17 FPSOs in Angola during the FPSO tow and came back onboard at the arrival of CLOV FPSO in Angola to prepare the first oil. They are now professional operators for CLOV.
This complete training program currently being deployed in Total affiliates will allow graduate operators with a 2 years diploma, to strengthen skills of local workforce and to build a win-win partnership with the country.
Exploration of HPHT Tight Gas Formation: First Application of Propped Fracturing in the Offshore Gulf
Authors: F. Al Ameri , F. Al Awadhi , J. Abbott , A. Akbari , J.L. Daniels 
Published: April 2015

Abstract
Exploration of the Palaezoic tight gas sands has been ongoing in Abu Dhabi since the early 1980s. The first discovery of gas in this formation dates back to this period; however commercial rates were not proven due to mechanical issues and the overall tight nature of the Pre-Khuff clastics. This formation is not only of interest as a source of gas, but also because gas shows and production from this formation have shown to be free of hydrogen sulphide.
Many wells in the Abu Dhabi Pre-Khuff have resulted in good gas shows while drilling, but did not produce. The poor production test results are not surprising if we consider formation damage the low permeability of the reservoir as regional experience has shown that commercial production rates are only achievable through the application of hydraulic fracturing.
Hydraulic fracturing in the Abu Dhabi Pre-Khuff formation is not without its challenges. The depth of this target creates a high pressure and high temperature environment which requires special equipment and technologies. The geomechanical properties and behavior of this formation are largely unknown in the Abu Dhabi region. In other parts of the Arabian Plate, this formation is known to be a complex geological environment with high fracture gradients, the poor consolidation and a high risk of poroelasticity. The aforementioned attributes make the Pre-Khuff formation a challenge to successfully fracture stimulate.
In a recent Pre-Khuff exploration well, hydraulic fracture stimulation was successfully implemented as part of the completion strategy. This new technique resulted in the successful production test of a Pre-Khuff target at commercial gas rates. In this paper we will show how the integration of petrophysical data, core data, geomechanical interpretations, lab/fluid testing and fracture diagnostics were used to design and optimize the hydraulic fracturing treatment. We highlight key technical risks and challenges encountered during the preparation, design, execution and evaluation phases of this operation and demonstrate how these risks were mitigated and the challenges overcome.. Finally, we will discuss how these methods and workflows can be applied for the improvement and optimization of future Pre-Khuff wells.