bluuebunny/crossref_metadata_2025 huggingface dataset:
Pipeline Repair Using Epoxy Technology
Authors: Bryson Kenneth , Fowkes Mick , Booth Paul , Mock Christopher
Published: April 2015

"Pipeline Repair with Epoxy Technology"; an economic permanent solution

Mechanical connectors have long been the accepted methodology for subsea pipeline repairs in benign waters accessible by divers. However, as the requirement to undertake repairs in increasingly deep and challenging environments has increased and infrastructures become ever more mature, the need for an economic deep water repair solution has become critical.

The current mechanical connector technology present issues such as size, weight and the requirement for fine alignment. These become critical parameters in the design of a repair system, especially on larger diameter lines. These fundamental issues can also have a detrimental effect on the choice of installation vessels and suitable weather window to perform the repair.

A new pipeline repair approach using Epoxy technology developed by Subsea7 addresses all of these issues. A specially formulated epoxy, injected into the annulus formed between the pipeline outer diameter and the repair connector provides both the axil and hoop strength necessary to provide a long term repair. Repair connectors no longer require highly technical sealing arrangements that rely upon tight diametrical control and precise ovality checks, consequently they are much smaller, lighter and far easier to install than conventional mechanical connectors.

This paper will illustrate the Epoxy technology itself, the qualification process and the many types of applications it is suited for. Critically, it will demonstrate the technical, schedule and installation advantages of Epoxy technology over conventional mechanical connector pipeline repair solutions.
Mooring System Integrity Challenges and Repair Experience of South China Sea Floating Production Units
Authors: Yiyong Liu , Jiayou Mao
Published: April 2015

This paper is written to provide working experience for mooring integrity works done in South China Sea. The relevant statistical data and repair methods of floater permanent mooring systems are to provide the industry with more references and insides.

There are total 10 floating units operating in South China Sea (9 FPSOs and 1 FPS). Half of them were initially installed in mid to late 90's. The rest were put in production after year 2000. All FPSO moorings are permanent internal turret type. During the operation period, there have been various mooring system integrity issues. In the past 20 years, there have been 3 major mooring system incidents and other 5 with various integrity issues. For the total 8 cases, various mooing system remediation actions have been taken to bring them back to standard. Considerations for mooring system design, installation and inspection have been put in place for existing system continuous safe operation or new systems to be installed in this area. A mooring system integrity management system is also under development by CNOOC. This article tries to review all the mooring integrity issues we have faced in the past 20 years at South China Sea. The repair solutions for each case are briefed. Guide lines for improvements in design, installation and inspection for future systems are given.

Mooring system integrity issues in South China Sea oil fields are related to areas of design, maintenance and inspection etc. The findings provide good information for new designs and help for better management of existing installations. It will also provide some shared learning on mooring system integrity management to other operators.
In Situ Radiographic Inspection for Non-Destructive Examination of Subsea Flexible Risers
Authors: Lyons G. J. , Sood J. , Ferguson H.
Published: April 2015

One of the most significant subsea inspection issues has been the inability to date to obtain high resolution images of the internal layers of complex products such as flexible risers, in situ. This has significant implications for asset integrity, life, and resultant review of design. The radiographic technology, and riser integrity expertise, of CIT and BPP, have been combined with the subsea inspection design and development capabilities of Subsea 7 to develop a groundbreaking subsea NDE inspection service. This allows operators to detect a wide range of riser issues for the first time by providing high resolution images of all the various flexible riser layers (not just the outermost tensile armour). The technology being developed can unambiguously and practicably identify defects on in-service flexible risers and thereby assist resolution by intervention. This paper describes the radiographic technology used and how it is integrated into the subsea NDE tool.

Technical aspects discussed compare the technology as implemented with what has otherwise been available to date. It is now possible with the radiographic technology developed to readily measure breakage of metallic layers, corrosion even when unflooded, as well as detecting loss of interlock. Fine control can also be applied to usefully view the non-metallic layers. Reference is made to Ultrasonic, Eddy Current, MAPS, and Acoustic Emission NDE techniques, and considers how these can most reasonably be used with existing and future assets.
The Agbami Digital Oilfield Solution and Reliability Assessment of Intelligent Well Completions
Authors: Ibeh Chijioke , Awotiku Oluwabiyi , Ledergerber Alan , Ugah Ibrahim , Awonuga Kunle
Published: April 2015

As at the time the Agbami field came on stream in July 2008, the Digital Oilfield (DOF) solution and indeed the Intelligent Well Completion (IWC) technology were still not widely accepted in the oil and gas industry as a cost-effective, reliable and sustainable method of completing and operating deepwater wells. Agbami development was indeed the first full-scale adoption of this technology for StarDeep Water Petroleum Limited (an affiliate of Chevron Corporation) and since then several other deepwater field developments have leveraged the best practices and lessons learned from the Agbami deployment.

Suffice to say that effective cost management is critical to the success of any business especially in the deepwater environment where rig rates and associated costs are high. Most operators tend to adopt a "lean" completions design and cost philosophy since drilling costs will typically not vary much especially in a "post-Macondo" world. One area of immediate completions cost savings is usually the elimination of jewelries like IWC equipment in the completions design. And if you try asking a good old company man, the most likely answer will be "just keep it simple". Though "keeping it simple" will minimize the installation risks and costs in the short term, this has to be balanced with long term surveillance requirements and non-intrusive well optimization and intervention opportunities.

This paper discusses the Agbami digital oilfield solution architecture with emphasis on the reliability of the IWC technology deployed. This reliability assessment focuses primarily on analyses of the downhole IWC equipment (sensors and control valves) installed in both producer and injector wells using statistical methods. With over 6 years after first oil, results confirm that most of the Agbami IWC equipment still have high reliability except for a few wells were we have observed failure of the metal-to-metal seal in the interval control valves. The full DOF solution implementation in Agbami has been a critical success factor in guaranteeing the reliability of the wells over the years thus minimizing intervention costs. The cross-functional collaboration within the Agbami team and ongoing engagements with the vendors to identify and implement equipment design improvement opportunities continues to deliver tremendous value.
Deriving Value from Integrating Engineering Design and Automation with Offshore Operations
Authors: Wiley Livia
Published: April 2015

Given the recent fluctuation in oil prices, companies are presented with a dichotomy—while they've cut 2015 capital expenditures (CAPEX) by 25-40%, production levels for existing operations are likely to remain at 2014 levels, or higher. The challenge now lies in improving operational efficiency and productivity, reducing costs, and mitigating risk to remain profitable in this tough oil market. It's a delicate balance of return on invested capital with operations excellence. This paper will present the value a single solution for simulating, operating, and optimizing operations offers the upstream oil and gas business. The outlined real-time performance-based solution for complete performance modeling provides operators a single continuous view of their assets, thus empowering them to plan, manage, and optimize current and future oil and gas production.
From On-Orbit to Offshore: Shared Challenges, Collaborative Solutions
Authors: Callini Gianluca
Published: April 2015

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

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

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

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

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

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

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

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

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.
The Evolution of DP Technical Support
Authors: Moen Lars Kristian
Published: April 2015

The first initiatives to maintain vessel position by means of electronic (not yet computerized) control of propulsion forces was in 1961. Through the Eureka and Cuss 1 projects in USA, innovative DP pioneers succeeded to perform automatic position and heading control of free-floating vessels. Station keeping uptime was approximately 25% and this was considered as significant improvement compared to known alternatives at the time. Since the early years of Dynamic Positioning, the total fleet of DP capable vessels has now grown to approximately 5000 vessels. In average, a new DP Control System is delivered every day and upgrades of systems with obsolete technology take place at increasing pace.

Development of DP related technology has enabled very advanced offshore operations under demanding environmental conditions. Computerized control systems have evolved and become more robust and with enhanced functionality. In parallel, we recognize new and innovative solutions within engine, power plant and propulsion systems. Instrumentation now includes a variety of position reference systems suitable for different operational conditions and applications. Improvements in vessel design and engineering has produced vessels that are better suited for their purpose. Traditional FMEA and simulator based test and verification of control systems have largely eliminated common mode failures. Traditional and simulator based operator and maintenance training and awareness has contributed to reduce human errors. Collaboration across the DP industry has resulted in significant improvement of overall regularity in DP operations.

The purpose of this paper is to offer insight in how support of DP Control System has changed since 1976 to meet continuously evolving needs. As the fleet of vessels has increased, support expectations have expanded in geography, operational awareness, several DP technology generations, communication technology and more. DP Support is required everywhere DP vessels operate. A long term trend is that the support gradually change from traditional on-call service and spare part logistics to operational support, system extensions related to new requirements and available technology as well as Service Lifecycle support to communicate and offer upgrades to products with limited or obsolete technology.
Batching Top Quartile Ultra Deepwater Wells
Authors: Jones Stephen , Klein Mark , Cook John , Angelidis Diogenes
Published: April 2015

The Phase 3 wells of the BC10 Parque Das Conchas field were drilled and completed in the Campos basin offshore Brazil in water depths between 1600-1900m. The wells were delivered as part of a batch campaign, 4 months ahead of schedule and approximately 40% under budget.

The development campaign consisted of 7 horizontal wells (plus a side-tracked appraisal section).

This paper will describe some key replication considerations at a planning, operational and organisational level that enabled the delivery of performance that benchmarks in the P5 range of the industry in both schedule and cost.

Essential catalysts for this performance included the immediate, repeat use of the 6th generation DP drillship MODU from the earlier Phase 2 campaign, standardisation of the well design and procedures, operating in ¨total batch mode¨, continuity of staff over the entire 4 year campaign lifetime and targeted contract incentivisation.

With these components fixed, focus could be applied to both actively reducing Invisible Lost Time using Deliver the Limit methodologies, and NPT by way of rigorous and monitored QAQC and maintenance programs, leading to this high quality performance result.
The New Technology Enablers Developed and Deployed on a Live Project
Authors: Cruz Ivan , Claro Cláudia , Gouveia João , Lemos Luiz , Câmara Marcelo , Pereira Leandro , Mair John A. , de Paula Marcus Tadeu R. , Escudero Carlos C.
Published: April 2015

Petrobras and partners (BG E&P Brasil and Repsol Sinopec Brasil, in Sapinhoá field, BG E&P Brasil and Petrogral Brasil, in Lula Field) selected the ‘Buoy Supporting Risers’ system as the most effective solution for their Sapinhoá and Lula Northeast fields in 2140m depth Santos Basin, offshore Brazil. For designing the system to fit its performance requirements, various novel technologies, both in equipment and processes, were required to be developed. The purpose of this paper is to provide an understanding of these major enabling innovations and to describe their roles and complementary relationships within the ‘Buoy Supporting Risers’ (BSR) system.
Subsea Wellhead System Verification Analysis Methodology for HPHT Applications per API TR 1PER15K-1 and API 17TR8
Authors: Perales Stephen A. , Kaculi Jim T.
Published: April 2015

As the oil and gas industry moves into drilling and production operations in deeper waters and harsher environments, there is a great demand to develop the next generation of tools and technology to meet these challenges. Subsea wellhead systems form a critical part of the drilling and production equipment, and a proper understanding of their behavior under complex loading conditions is crucial as they provide a critical barrier between the wellbore fluid and the environment.

High-pressure, high-temperature (HPHT) applications can require the use of heavy wall components with significant structural discontinuities and complex geometric features. These conditions result in nonlinear stress gradients across the wall sections and degraded material properties caused by high temperatures. For these applications, API TR 1PER15K-1 [1] suggests the use of elastic-plastic finite element analysis (FEA) in place of the standard linear elastic methodology of stress categorization. An elastic-plastic analysis of a subsea wellhead system with a standard 36 in. ×22 in. ×10¾ in. casing program in accordance with ASME BPVC Section VIII Div. 3 has been performed [2].

Following the recommendation of API TR 1PER15K-1 with regards to system approach evaluation, the full wellhead system was included in the model. To accurately account for the complex interactions and load transfer between system components contributing to the overall structural response, the model used in this analysis included all major components of the system and was sequenced and preloaded in a method analogous to real-world field installation. System preload, global external loads, pressures, and casing loads were applied to the model. The model extended 200 ft below the mudline, a depth considered sufficient for the wellhead system to be free of any boundary effects. The 3D model included non-linear springs to simulate soil resistance. Cements were also included where appropriate.

The wellhead system was required to demonstrate sufficient resistance to failure due to global collapse, local plastic damage, and buckling. Analysis results for each failure mode and a comparison of rated loads using the standard linear elastic and elastic-plastic methodologies is presented. Using more advanced analysis techniques based on industry best available and safest technology, FEA results have allowed for more insightful validation testing, better-informed design decisions, and an improved understanding of system performance in extreme field environments.
Development of a Post-Installed Deepwater Monitoring System
Authors: Seaman C. , Brower D.V. , Tang H. , Le S.
Published: April 2015

A monitoring system that can be deployed on already existing deepwater risers and flowlines has been developed. This paper describes the design concepts and testing that was performed in developing the monitoring system. A major challenge of a post-installed instrumentation system is to ensure adequate coupling is achieved between the instruments and the riser or flowline. This work investigates the sensor coupling for pipelines that are suspended in both the water column (from topside platform to the seabed) and for those that are located directly on the seabed. These different environments necessitate two sensor attachment methods: (1) sensor clamp design with subsea adhesive and (2) sensor clamp design with friction surface coating. This paper addresses the adhesive attachment method. The monitoring elements consist of fiber optic sensors that are encased in a polyurethane clamp. With a subsea adhesive, the clamp can be installed by divers in shallow depths or by use of an ROV for deeper applications. The NASA Johnson Space Center was initially involved in the selection and testing of subsea adhesives. It was determined that up to 75 percent of the bonding strength could be achieved with the adhesive from optimal dry bonding versus bonding in submerged sea water environments. The next phase of the study involved the design, fabrication, and testing of several prototype clamps that incorporated the fiber optic sensors. Several molds were produced by NASA using 3-D printing that allowed the fabrication of subscale test articles that would accommodate 4-inch and 8-inch diameter pipes. The clamps were installed with adhesive in a "wet" environment on the pipe test articles and evaluated in the NASA Structures Test Laboratory. The tension/compression and bending tests showed that the prototype sensor clamps achieved good coupling, and could provide high quality strain measurement for active monitoring.
The Buoy Supporting Risers (BSR) System: Engineering a Solution for Ultra-Deep Water Subsea Developments in Harsh Environments
Authors: Cruz Ivan , Hepner Gustavo , Karunakaran Daniel , Claro Claudia , Nicoletti Frederico , Fontaine Emmanuel , Hesar Majid , de Paula Marcus Tadeu R. , Trovoado Leandro C.
Published: April 2015

The Sapinhoá and Lula North-East fields were developed through pilot systems composed of satellite wells connected to spread moored FPSOs. Each of these developments needed to connect up to 45 lines coming from the wells to a single balcony at FPSO portside, not including gas export riser and its ESDV umbilical. It was expected variable levels of CO2 and H2S, posing the challenge to find a suitable solution that endure the 27 years life of the fields in 2140m water depth in the harsher Santos Basin. To cope with these challenges, Petrobras and partners (BG E&P Brazil and Repsol Sinopec Brazil, in Sapinhoá field, BG E&P Brazil and Petrogral Brazil, in Lula Field) decided to pursue a decoupled risers' system solution and launch a "design competition process" which ended up selecting the Buoy Supporting Risers (BSR) concept solution developed by Subsea 7. This paper describes the BSR System and the needed careful physical and numerical modelling and massive analysis of a largely complex new system, backed up by prototype tank testing, all of them tackled to capture the in-place behaviour to generate the design input envelopes for all system components.
Application of the Shear Band Propagation Method to Slope Stability Analysis of a Palaeo-Landslide in the Caspian Sea
Authors: Gray Thomas , Puzrin Alexander , Hill Andy
Published: April 2015

Geophysical observations of palaeolandslides in offshore settings include long and relatively thin failures that occur on very mild slopes. Back analysis of such failures using the limiting equilibrium approach and measured geotechnical soil properties is typically used to inform the likely causes of past failures. An assessment can then be made of the present day significance of causal factors (e.g. the presence of excess pore water pressure), with the limiting equilibrium approach used to assess factors of safety for present-day slopes and predict the potential size of any future failures. However, for long, thin slides, use of the limiting equilibrium approach can lead to the conclusion that either a significantly large seismic trigger or other, abnormal geological condition was required to initiate failure. A result has been the focusing of academic research into other failure causes and conditioning factors. Further, the stability of the present day seabed for offshore developments can be overestimated, given the rarity of large seismic events in many areas and geotechnical measurements that not always show abnormal soil conditions.

The shear band propagation approach offers an alternative view, where an initial small failure can grow into a larger failure at the point of initiation. A result is that an explanation of the conditions leading to failure can be attributed to many submarine landslides. Further, accounting for the potential propagation of a shear band in the future prediction of submarine landslides can result in greater predicted failure sizes and lower factors of safety than using limiting equilibrium only. The application of the shear band propagation approach to back analyse a palaeolandslide in the ACG Field, Caspian Sea, is used to demonstrate the methodology and compare with results using the limiting equilibrium approach. Results show that the shear band propagation approach successfully predicts observed failure geometries and suggests triggering conditions from a lower magnitude seismic event compared to that predicted using limiting equilibrium. The future application of shear band propagation theory to submarine landslide analysis is also discussed.
Implementing a CSEM Survey Around Existing Infrastructure - The Perdido Installation, Gulf of Mexico
Authors: Hite Damian A. , Hiner Mike , Solevåg Lars P.
Published: April 2015

It's been over a decade since the first CSEM acquisitions were done along 2D lines in relatively open water. Today's CSEM acquisitions cover hundreds of square kilometers in true 3D fashion using receivers and towing systems purpose-designed for ease of handling, accuracy of deployment and efficiency in towing. Making use of these advancements, EMGS has been able to acquire data closer than ever before to existing infrastructure in a safe and reliable manner.

This paper covers the acquisition of a portion of the multi-client survey Daybreak Phase III around the Perdido installation over the Great White field in the Alaminos Canyon protraction area of the U.S. Gulf of Mexico. The survey covers approximately 46 OCS Blocks in water depths from 1700-3000m. The survey was acquired by the vessel EM Leader during the month of June, 2014 and consisted of 130 receiver drops and 702 tow kms.

In order to acquire the survey, EMGS contacted Shell, the operator of Perdido, and requested permission to conduct operations around the facility. Shell agreed and provided the following stipulations which were to be complied with at all times: When the planned tow line crosses a pipeline location, the CSEM source must be raised from its nominal towing depth of 30m to 100m at a point 250m away from the pipelineNo gear or the survey vessel could come within 1.5 NM of the facility The survey area bathymetry and infrastructure are showin in .