bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case Study of Asset Integrity and Risk Assessment for Subsea Facilities and Equipment Life Extension
Authors: Carvalho Eduardo , Tang Fei , Allen Eric , Sharma Partha
Published: April 2015

The ever increasing oil and gas exploration and production cost requires highly efficient and safe operation of the existing offshore and subsea equipment and facilities. At the same time, a large number of facilities and parts of the existing infrastructure are quickly approaching or have exceeded their originally designed service life. Many fields, however, still have large amount of remaining recoverable oil and gas reserve which can be profitable if current production equipment's service life can be extended beyond their nominal design, otherwise economic penalty of stopping production or installing new equipment will be too high.

On the other hand, once existing equipment have been operating beyond their design life, unforeseen failure and integrity problems can occur that site personnel may have not previously encountered. In many cases this can cause production to cease unexpectedly, and result in costly emergency repairs to get the asset back online.

To extend asset life and push the design envelop, operators must prove to themselves and often their regulators that the assets are safe to operate with limited and controlled risks. In a scenario like this, the subsea integrity management of ageing assets has become a key issue for the oil and gas industry.

This paper provides an actual case study for asset integrity assessment of subsea facilities life extension, performed by DNV GL and the O&G asset operator team. The study includes the asset integrity condition assessment based on equipment design documentation, operations data, maintenance and inspection analysis data, risk assessment and recommended mitigation of identified threats, engineering critical analysis of high risk equipment, and proposed destructive lab testing of parts retrieved from subsea.
Electrical Power Transmission to Offshore Facilities: A Case Study
Authors: Bari S. J.
Published: April 2015

As the world continues its search for energy, many new advanced technologies are being developed. As a result, there is a surge in the amount of electrical power demanded for operations in the oil and gas industry. Satisfying the power demanded by loads in offshore remote locations is an elaborate process. The technical and economic aspects of the alternatives of HVAC and HVDC power transmission have to be scrutinized, before the complex operation of implementing an offshore power supply infrastructure can be executed. After carefully identifying the requirements of a case, the optimum power supply network through appropriate submarine cables can be determined.
North Sea and GoM Initiatives to Enhance Process Safety
Authors: Pitblado R.
Published: April 2015

The onshore and offshore O&G industry has achieved an outstanding improvement in occupational safety over the past 20 years, however major accident performance has improved much less. The North Sea appears to have a better performance record on major accidents. Process safety initiatives in the North Sea and the Gulf of Mexico are compared and key differences identified in two timeframes - since Piper Alpha and since Macondo. The North Sea since Piper Alpha has been driven by performance style regulations that require detailed risk assessment and definition of critical safety barriers and this is combined with safety management and culture programs, and the idea of a safety case. The USA was more prescriptive until Macondo, but since then some performance style regulations have been adopted - such as SEMS. The industry through API, IADC and COS have supported these initiatives. While SEMS is a valuable initiative, further initiatives such as those demonstrated in the North Sea would enhance process safety further in GoM.
MoC-Based Modeling and Simulation of Foam EOR Processes in Multi-Layered System
Authors: Lee Seungjun , Kam Seung Ihl
Published: April 2015

Foam injection is a promising means to improve field-scale displacement efficiency, especially when a reservoir consists of multiple geological layers, the connectivity of which is minimal or absent due to the shale layers embedded in between. This study is devoted to investigating how foam EOR processes work in such heterogeneous and layered reservoir systems overcoming subsurface heterogeneity by using fractional flow analysis.

This study first shows how to interpret theoretically the injection of surfactant preflush and following foams into a single-layer system at pre-specified rock and fluid properties, and then extends the knowledge gained into multi-layer systems where the properties vary in different layers. The results in general show that the mechanisms of foam displacement strongly depends on foam properties such as gas-phase mobility reduction factors (MRF), limiting water saturation (Sw*), and critical oil saturation (So*) as well as petrophysical properties of individual layers such as porosity (f), permeability (k), relative permeability, capillary pressure (Pc) and so on. The overall sweep efficiency in a multi-layer system is very difficult to predict because of the complexity, but the mathematical framework presented in this study is shown to handle the problem successfully and reliably. A 1D foam simulator developed in this study is used for verification purpose.
Hydro-Test Risk Minimization Through Design and Processing for Subsea HP/HT Well Equipment
Authors: Lindley Roy , Fraser Dan , Aiken Bill , Bailey Greg , Patrick David
Published: April 2015

In the realm of high pressure (15,000 psia or greater), high temperature (350 F or greater), or a combination of both, today's manufacturing hydro-testing practices may be detrimental to components intended for deepwater use such as in the Gulf of Mexico. The purpose of this paper is to revisit this practice in terms of designing and developing high pressure/high temperature (HP/HT) equipment while continuing to assure "fitness for service" with adequate safety margins.

The process considers hydro-testing history including recent trends and current requirements in key standards. Risks surrounding environmental cracking processes under stress are also considered. These can lead to rapid component failure and warrant special consideration because of the H2S environment often found in HP/HT wells in the Gulf of Mexico. Finally, practical materials limits and the underlying basis for key codes and standards are examined relative to applicability to HP/HT service in such an environment. This includes recognition for how criteria were established, related limitations, and how this information is used in the design, development, and manufacturing process. At one time, the hydro-test at the end of component manufacturing was a key indicator of safety margin (or even a proof test) and, depending on the era and circumstances, test pressure was several times the rated working pressure (RWP) of a component or vessel. Today a typical hydro-test pressure factor recommended by API is 1.5*RWP. However in the (HP/HT) application a 1.5 pressure test factor can cause plastic deformation of metallic components and may compromise "fitness for service."

For anticipated HP/HT conditions (H2S presence) in the Gulf of Mexico, this paper proposes a reasoned approach concerning the basis for a hydrostatic test. This proposed approach is coupled with an integrated methodology for manufacturing HP/HT equipment that includes design, design verification, materials evaluation and quality systems.

The approach attempts to preserve a traditional hydro-testing comfort level while minimizing pre-service stress and risks of H2S susceptibility on NACE MR0175/ISO 15156 Part 2 materials (carbon and low alloy steels). While more detailed studies and physical tests are certainly needed for these material types, the proposed approach offers a roadmap to reduce hydro-testing induced strain related consequences and risks in HP/HT equipment.

This paper is intended as a fundamental re-examination of the role and value of hydro-testing apart from merely accepting or slightly modifying historical practices.
Distillation of Seismic Attributes to Geologic Significance
Authors: Roden Rocky
Published: April 2015

The generation of seismic attributes has enabled geoscientists to better understand certain geologic features in their seismic data. Seismic attributes are a measureable property of seismic data, such as amplitude, dip, frequency, phase and polarity. Attributes can be measured at one instant in time/depth or over a time/depth window, and may be measured on a single trace, on a set of traces, or on a surface interpreted from the seismic data. Commonly employed categories of seismic attributes include instantaneous, AVO, spectral decomposition, inversion, geometric and amplitude accentuating. However, the industry abounds with dozens, if not hundreds, of seismic attributes that at times are difficult to understand and not all have interpretive significance. Over the last few years there have been efforts to distill these numerous seismic attributes into volumes that can be easily evaluated to determine their geologic significance and improve seismic interpretations. With increased computer power and research that has determined appropriate parameters, self-organizing maps (SOM), a form of unsupervised neural networks, has proven to be an excellent method to take many of these seismic attributes and produce meaningful and easily interpretable results. SOM analysis reveals the natural clustering and patterns in the data and has been beneficial in defining stratigraphy, seismic facies (pressure), DHI features, and sweet spots for shale plays. Recent work utilizing SOM, along with principal component analysis (PCA), has revealed geologic features not identified or easily interpreted previously from the data. The ultimate goal in this multi-attribute analysis is to enable the geoscientist to produce a more accurate interpretation and reduce exploration and development risk.
Offshore Gas Program Acceleration (Karan Gas Program)
Authors: Alotaibi Abdulwahed Z. , Alyahya Abdullah M.
Published: April 2015

The Karan Gas Program successfully completed Saudi Aramco's first offshore nonassociated gas development with a capital budget of US$ multibillion, and achieved record early gas in 2 years and 3 months with full production in 3 years and 4 months. The Karan gas field is located approximately 110 km offshore in Saudi Arabian Gulf territorial waters. It was discovered in 2007 and has a production capacity of 1,800 million standard cubic feet per day (MMscfd) of natural gas.

The Karan field development schedule was accelerated to meet the increased demand from the energy sector for Saudi Arabian gas. The proposed OTC 2015 paper will focus on the project management aspects of the program and include a full field development case study of the field expansion to increase capacity and sustain production. The paper and presentation will elaborate on accelerated offshore gas program development methodologies that resulted in gas production from wells to the domestic consumers in a record timeframe.

The program was executed under four subprojects that were developed concurrently as follows: Karan Gas Facilities: Responsible for providing the primary gas processing facilities.Karan Offshore Facilities: Responsible for fabricating and installing production and tie-in platforms.Karan Gas Pipelines: Responsible for linking the offshore and onshore elements. The project fabricated and installed flowlines from each production well to the tie-in well and 110 kilometers of 38 in. pipe to the onshore producing facility.Manifa Gas Facilities: Responsible for installing processing facilities for associated sour gas and hydrocarbon condensate from the Manifa offshore oil field.
Multiphase Flow Modeling for Gas Hydrates in Flow Assurance
Authors: Hegde Govind A. , Sum Amadeu K. , Danielson Thomas J.
Published: April 2015

Multiphase flow is a central component in all flow assurance strategies in oil and gas production. The risk of plugging of flowlines due to hydrate formation is also one of the most prevailing flow assurance problems in subsea deepwater oil and gas operations. Hence, it is critical to develop a model to account for the inter-coupling of hydrates and multiphase flow. We present a new framework to model the effect of multiphase flow on hydrates and vice-versa. In the current work, we use a two-phase (gas/liquid) hydrodynamic slug flow model and explicitly incorporate hydrates as a third phase. The model is based on fundamental multiphase flow concepts and has the capability of predicting hydrodynamic slug formation and propagation in three-phase flow. The utility of this tool is demonstrated in the modeling of hydrate formation in gas-water and gas-oil-emulsified water systems by comparing the multiphase flow behavior in terms of flow regime, slug length distribution, number of slugs, and slug frequency. For the gas/oil system with emulsified water, we perform a systematic study on the aggregation of hydrate particles and the subsequent viscosification of the slurry, and its impact on the multiphase flow behavior of the system. The results reveal that hydrate formation has a significant effect on the slugging exhibited by the system, suggesting that one may be able to infer hydrate formation from the changes in the flow characteristics. As part of the validation of this model, we have performed an extensive comparison of the two-phase flow regime predictions of our model with available experimental data, as well as with a number of models available in literature. The results show that our model predictions are in good agreement with literature and the prediction accuracy of our model is higher than all the models compared. This establishes our model as a viable multiphase flow modeling tool to predict the flow behavior in oil and gas pipelines. Hence, in this work, we demonstrate the capabilities of the model to perform transient simulations of two-phase and three-phase flow. This is the first step in the development of the model, with the ultimate goal being completely understanding the interdependence of hydrates and multiphase flow, hence enabling flow assurance engineers to develop better hydrate management strategies.
Guidance for the Development and Implementation of an Effective Well Integrity Management System
Authors: Wilson Valerie
Published: April 2015

The NORSOK D-010 standard established a definition of Well Integrity: “The application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids and well fluids throughout the life cycle of a well.” If that is the ultimate goal, how do we get there?

This document was created with the goal to provide references, a basis of information, and guidance for best practices to operators for developing and implementing a Well Integrity Management System (WIMS).

This paper will review the industry documents that address Well Integrity and outline their requirements or recommendations of a Well Integrity Management System (WIMS). This paper will address what elements should be covered in a WIMS. It will also expand on each of these elements in order to provide information and guidance for an operator to build a WIMS. This paper will cover the topic of best practices for successful implementation of a WIMS, from training, personnel buy-in, and auditing/tracking to verify the effectiveness of the program.
All Subsea: A Vision for the Future of Subsea Processing
Authors: Ruud T. , Idrac A. , McKenzie L. J. , Høy S. H.
Published: April 2015

Over the past 10 to 15 years subsea processing has been globally established as a market segment within the subsea development arena. Subsea processing is expected to be a growth platform for operators and for the service companies that are developing equipment and solutions for well processing and treatment at or below the seabed. The ultimate result of the All Subsea vision is the production of hydrocarbons from reservoir directly to market. Operators and service companies have high expectations for the profitability this business offers and share the All Subsea vision of future topside-less developments.

This paper examines the realism of this All Subsea vision and discusses how the vision can be implemented, based on an analysis of the current state-of-the-art technology and the gaps and barriers that may jeopardize the realization of true subsea- to-market solutions.

Developing products and systems with high development costs for a limited market requires a close cooperation between the suppliers and oil companies.

The paper also reflects on the history of subsea processing, the market trends, and the way subsea processing technologies are adopted by the industry, seen from the authors' perspective and with their extensive experience in developing and delivering subsea processing solutions worldwide.
Prospect of Production Optimization Challenges of Gas Wells with Liquid Loading Problem Using New Surfactant and Nanotechnology
Authors: Wu Junwen , Lei Qun , Xiong Chunming , Zhang Jianjun , Li Jun , Cao Guangqiang , Wang Yun , Jia Min , Li Nan , Liu Yan , He Chunyan
Published: April 2015

Decrease of gas production is an indicator that liquid column is probably building up in the well and an additional energy is required to lift the liquid out should be applied to control this situation.

Foaming agents provide a means to reduce the density of the liquid so that it can be removed from the well with the gas flow, unloading the accumulated liquid in gas and gas condensate wells. The main constituents of foaming agents are surface active agents. Foam stabilizers are added to increase foam stability. Foaming agent should be selected to form a stable foam under given condition, which means in the presence of salt or sweet water, hydrocarbon phase, at given temperature and pressure.

Currently, there are lots of different types of foaming agents. Previous studies mainly focused on the complex between anionic surfactant and anionic surfactant, anionic surfactant and amphoteric ion surfactant, however, the stability of the foam formed by such foaming agents is poor. Therefore, it is necessary to develop a robust foaming agent to cope with the harsh conditions. Traditional research neglect the study of complex between anionic surfactant and cationic surfactant, nevertheless the synergies between them through appropriate method can greatly improve the foam stability compared to one-component system. The strong electrostatic interaction between the opposite charge ionic head groups and the hydrophobic interaction between the hydrocarbon groups made the solution exhibit a complex phase behavior and microstructure which has a high surface activity and foam stability. Gemini surfactant contains a spacer and thus made the packing of molecules tighter and increased the cohesion of surfactant within the monolayer and enhanced the foam stability. Single molecule film formed by surfactant has certain dynamic characteristics, the gas can easily diffuse through the liquid film, so that the bubble burst. However, particles can be adsorbed in the gas/water interface to form a solid film which will reduce the drainage speed of the bubble to enhance the foam stability.

In summary, we proposed to develop a robust foaming agent using anionic-nonionic surfactant mixed with gemini cationic surfactant, stabilized by nanoparticles with certain hydrophilicity and size.
The CLOV Hybrid Riser Towers
Authors: Proust Julien , Lynch Mattias , Seguin Blaise
Published: April 2015

The CLOV development is located offshore Angola in a water depth of 1,300m and includes two Hybrid Riser Towers. The first oil was successfully achieved on June, 12 2014 as initially scheduled at project award in July 2010. This paper provides an overview of the engineering scope through all phases of the Hybrid Riser Towers delivery and how such input was used to determine some key aspects of the execution plan.

The paper starts with a description of the design of the Hybrid Riser Towers developed for the CLOV project. Moving through the various phases of the package (from design engineering to procurement, fabrication and offshore installation), the paper details the associated fabrication and installation methods and focuses on the engineering analyses developed to drive the design and the associated installation methodologies. A number of examples are also highlighted in which the input from the engineering analyses was used to introduce key changes to the fabrication and installation philosophies developed for past similar projects (Girassol and Greater Plutonio).

The example of the Hybrid Riser Towers development on the CLOV project provides a perfect field to investigate the extent of the engineering scope of similar riser packages and how to optimize the benefit from such analyses. The Riser Tower design selected for CLOV project benefits from past experience gained on Girassol and Greater Plutonio Riser Towers (Ref. [1], [2], [5] and [7]) and consequent improvements. Significant updates to the Hybrid Riser Towers design and installation methodologies driven by the analyses from CLOV project are presented with details on the way they helped reduce technical risks and secure the delivery schedule. Based on this experience, recommendations are provided on how to best approach the engineering scope covering all phases of large and technically complex projects with tight schedule constraints.

This paper provides the latest updates on state of the art engineering analyses covering design, fabrication and installation of Hybrid Riser Towers and associated installation methodologies for deepwater developments.
Offshore Development: Unique Technical Solutions for Complex Gas Development Projects
Authors: Al-Tunisi Nabilah , Al-Sharif Safwan , Raja Abid
Published: April 2015

In order to meet the growing domestic and global demand for natural gas and its diversified targets, Saudi Aramco elected to increase production in undeveloped offshore natural gas fields. Since 2008, Saudi Aramco has planned and developed three offshore non-associated gas fields at Arabiyah, Hasbah and Karan.

Saudi Aramco's offshore gas fields are unique. The presence of elemental sulfur, risk of hydrate formation, large slug volume and the reservoir's excessive pressure and temperature are key factors that made Arabiyah-Hasbah fields different from other gas fields around the world. Few gas processing facilities in the world have experienced such extreme parameters, including impurities and corrosiveness, all at the same time.

The distinctive nature of the fields has introduced complex and sensitive systems and new technologies to Saudi Aramco. In order to ensure safe and reliable operation of the fields and the offshore gas processing facilities, all newly introduced technologies and complex systems were mandated to be manufactured, tested and accepted according to Saudi Aramco's specifications and requirements.

This paper will detail the challenges, faced by the project team, involved in the development of the offshore gas fields, specifically Arabiyah and Hasbah, and the solutions implemented to achieve the gas production targets.
Fiber Optic Sensor Based Monitoring System for Blowout Preventer
Authors: Turner Alan , Loustau Philippe
Published: April 2015

Ultra-deep water BOP (Blowout Preventer) operation poses numerous challenges in obtaining accurate knowledge of current system integrity and component condition- a salient example is the difficulty of verifying closure of the pipe and shearing rams during and after well control events. Ascertaining the integrity of these functions is currently based on a manual volume measurement performed with a stop watch. Advances in sensor technology now permit more accurate methods of BOP condition monitoring. Fiber optic sensing technology and particularly fiber optic strain gauges have evolved to a point where we can derive a good representation of what is happening inside a BOP by installing sensors on the outside shell. Function signatures can be baselined to establish thresholds that indicate successful function activation. Based on this knowledge base, signal variation over time can then be utilized to assess degradation of these functions and subsequent failure to function. Monitoring the BOP from the outside has the advantage of gathering data through a system that can be interfaced with risk based integrity management software and/or a smart monitoring system that analyzes BOP control redundancies without the requirement of interfacing with OEM control systems. The paper will present the results of ongoing work on a fully instrumented 13-½" 10,000 psi pipe ram. Instrumentation includes commonly used pressure transducers, accelerometers, flow meters, and optical strain gauges. Correlation will be presented between flow, pressure, acceleration signatures and the fiber optic strain gauge's response as it relates to functional verification and component level degradation trending.
Novel Deliverability Test Method for HPHT Sour Gas Wells
Authors: Wei Pang , Tongyi Zhang , Juan Du , Chunfei Fang
Published: April 2015

Sour gas reservoirs with H2S and/or CO2are widely spread in the whole world, especially in France, Canada, America and China. Most of sour gas reservoirs in China are HPHT tight gas reservoirs which require long testing duration to reach steady state when conducting deliverability test while long testing time leads to huge operation risk because testing tools are used close to critical temperature and pressure condition.

In order to resolve the contradiction among testing duration, operation risk and interpretation results' accuracy, a new deliverability test method is proposed by using pressure buildup transient data. The deliverability calculation model is built by integrating wellbore fluid flow and formation seepage considering fluid flow from formation to wellbore after well shut-in. The formation parameters are interpreted by one pressure buildup transient data, based on which, four daily production rates are designed to simulate the wellbore flow pressure until the well reaches steady state flow, and then the deliverability equation can be derived from the pressure & daily rate points under steady state flow.

Filed case comparison is made between interpretation of actual test data and data from the new method. Results show that the new deliverability test method can get more accurate deliverability equation and AOF by only 1 time pressure buildup and greatly reduces the duration for testing, so it is very practicable because it can greatly decrease the operation risk and increase interpretation accuracy for HPHT sour gas reserviors.

This new deliverability test method has wide application prospect in HPHT sour gas reservoirs and can be extended to other oil/gas reservoirs' application for quick AOF determination, rate allocation, and economic evaluation.
Development of a New Synthetic Hurricane Model for Deriving MetOcean Design Criteria for the Gulf of Mexico
Authors: Mudd L. , Vickery P. , Sarathi P.
Published: April 2015

The objective of this work was to develop a robust methodology for deriving hurricane wind, wave, and storm surge design criteria for offshore structures in the Gulf of Mexico. The hurricane simulation model takes advantage of detailed historical database of Gulf of Mexico hurricanes, which includes detailed information on the characteristics of the wind field model not found in the HURDAT database. Using this new database, new statistical models were developed to describe the temporal changes in the storm size, the pressure–wind relationship and the correlation between storm size and intensity. The model includes features that enable the modeling of storm weakening and expansion of the wind field as a storm approaches the Gulf of Mexico coastline. A 1–dimensional ocean mixing model is coupled with an eddy model to enable the modeling of the interation between the simulated hurricanes and the warm eddies that break off from the loop current. A 100,000 year hurricane simulation was performed, the results of which can be used to form the basis for the development of the wind–wave–surge design criteria.

The synthetic hurricane model reproduces the Gulf of Mexico hurricane climate to a good degree, in terms of the distributions of storm size, intensity, and translation speed observed over the previous 50–100 years. In addition, the model provides more plausible values of rare (1,000 – year to 10,000 – year return period) winds as compared to extrapolations from the limited database of hindcast historical storms. This effort presents a step–change in the way hurricane criteria have traditionally been developed by industry. In moving to an extended hurricane database, derived from a synthetic model founded on the best modern hurricane data available, industry will benefit from more stable design criteria, and better estimates of rare return period site conditons.
Deep Offshore Gas Fields: A New Challenge for the Industry
Authors: Gyllenhammar E. , Boireau C. , Riviere L. , Ulvestad A.
Published: April 2015

A large number of gas fields have recently been discovered offshore in depths of up to 3000 m, far away from the nearest coast and in countries with little or no oil and gas infrastructure. In addition to the field development strategies including large surface facilities for processing and export to shore, or floating LNG plants, the industry may in the future be seeing more subsea-to-shore developments for these fields.

Total and Aker Solutions have completed a study for a challenging notional gas field development located at 2500m water depth, 300 km from shore, that is to be developed using only subsea technology. The vision is a fully autonomous subsea production system with tie-back to shore.

This paper describes the flow assurance challenges with long-distance subsea tie-backs to shore, from deep offshore fields, and the work done to identify the wide range of subsea processing schemes that may improve the gas transport. Two of these schemes were selected and studied in detail: one consisting of pushing the envelope of multiphase transport to shore with the aid of a subsea compression system, and the other of developing a system for subsea gas dehydration to avoid the use of Mono Ethylene Glycol (MEG) for hydrate inhibition. The main challenges of using these technologies are presented and discussed.
Subsea Sampling and Sensor Insertion Systems for Improved Accuracy of Production Measurement
Authors: Kelner E. , Toskey E.D. , Crider J.
Published: April 2015

The increase in deepwater field development in the Gulf of Mexico and other locations has brought an increase in the use of subsea multiphase flow meters (MPFMs) for individual well flow rate monitoring at or near the wellhead. Their justification usually is to obtain improved well and reservoir management, or a more verifiable allocation of production between wells, such as where the ownership or royalty rate differs amongst the wells producing to the same platform. The two most common inadequacies of subsea MPFM installations has been the insufficiency with which one can characterize the produced fluids – for measurement accuracy, and the unavailability of any supplemental measurements, even if only temporary – for measurement verification. Without these, MPFM measurements can be inaccurate, and there may be no means to verify them. Unverifiable and questionable measurements will likely go unused, and the value originally sought with the installation of the MPFM goes out of reach.

Although experience with MPFMs on land and topsides, where they are accessible, has demonstrated the importance of characterizing the fluid properties from analyzed fluid samples, and having alternative means to measure flow to validate the MPFMs, subsea multiphase meter installations rarely have any facility for fluid sampling or supplemental measurement. Until recently, the development of sampling techniques has been limited and there have been no systems developed which could deploy a variety of other sensors near the MPFM for the purposes of verification. For subsea MPFMs to fulfill their original purpose of providing long-term reliable subsea wellhead measurement, MPFM installations need to have the facilities for subsea fluid sampling and subsea sensor insertion/removal, which would provide timely and accurate fluid properties at meter conditions, and a means to verify MPFM performance. Topside well tests and samples of commingled well streams cannot meet these needs.

This paper describes two technology developments which address these issues: 1) a remotely operated underwater vehicle (ROV) deployed subsea sampling system, which provides a means to capture fluid samples for the purposes of fluid property determination at the multiphase meter or other locations at any time in the life of the well, and 2) an ROV-operated subsea sensor installation/removal system that enables the placement of a variety of sensors in direct contact with process fluids, and extends the flexibility and range of subsea wellhead and subsea process measurement.
Fatigue Damage to Circumferential Weldments and Mitigation Techniques
Authors: D.A. Nowak , G. Slater
Published: April 2015

The paper focuses on the results of full size conductor connector-to-pipe fatigue testing of circumferential weldments, and mitigation techniques to inhibit fatigue failure and to evaluate the level of component life extension. This study utilized a standard conductor connector welded to 559 mm (22 inch) diameter by 25 mm (1 inch) wall thickness X56 line pipe. Resonance fatigue testing was carried out at TWI Limited in Cambridge, England. Standard manufacturing tolerances for pipe ovality, weld joint mismatch, and ‘flush’ blending of the weld profiles on both the internal and external surfaces were used for each of the fabricated fatigue specimens. All tests specimens were Phased-Array Ultrasonically Tested (PAUT) both before and after fatigue testing, and were run with a relatively low axial mean stress of 10 MPa (1.45 ksi) created by internal water pressure. Results showed at the lower cyclic stress range, 100 MPa (14.5 ksi), that most of the fatigue failures were outside of the connectors, while all of the higher cyclic stress range tests, 150 MPa (21.75 ksi), failed in the conductor connector. A second phase of testing eliminated the stress concentrations from the conductor connector design and welded the connector profile halves together. All phase 2 tests were performed at the higher cyclic stress range, and failed in the X56 piping. Three of the phase 2 tests incorporated mechanical shot peening over the blended internal and external weld surfaces to improve fatigue resistance. All three of these tests also failed in the X56 line pipe material, well outside of the weld area.
A New Process for the Management and Delivery of IMMR and Geoscience Data Which Enables Management, Interpretation and Delivery of Extremely High Resolution Data on Any Computer
Authors: Sean Halpin , Taylor Brown
Published: April 2015

Significant advances have been made in the past decades in spatial data management by GIS defense contractors that allow clients to rapidly process, store, and recall large swaths of sub-decimeter resolution imagery generated by satellites, manned aerial surveys, and drones. In onshore oil and gas, similar GIS technology is being adopted to manage assets, logistics, and UAV-surveyed pipeline inspection data, including 3D mapping, change detection, and leak detection data. Adoption of such enterprise grade GIS solutions for survey data along the life of a pipeline, however, has been much slower offshore.

Through adopting this defense-grade technology, the full capacity of using GIS as the complete IMMR tool is realized. Pre-lay, as-built, and inspection survey data are able to be managed and rapidly recalled at full, as-surveyed centimeter resolution in a GIS environment. In this manuscript we present a comparison of conventional technology and a new novel custom software package during analysis of a 11,294 km fictitious pipeline originating in Houston, TX and terminating in Alaska. Data refresh rates are dramatically better (on average 7 times better) when working with the data and the data may be served to a variety of applications including a common web browser and many common platforms outside of the Oil and Gas industry. This software allows contractors to generate data products at the resolution of the sensor and allows Oil and Gas clients to move their data from the box in the corner to live and recallable platforms.
Local content, the driving force on the CLOV Project
Authors: François Bichon , Antonio Cardoso
Published: April 2015

Local content was fundamental to Total E&P Angola's development philosophy for the CLOV mega-project, offshore Angola. The aim - to allow CLOV to provide with a lasting legacy in terms of human and facilities resources - was to achieve 10 million man-hours of local activity in Angola at first oil - a tenfold increase from Total's first deepwater development at Girassol - and the fabrication of 64,000 tonnes of structures in five domestic construction yards.

Based on Total E&P Angola's policy of sustainable development, a plan was devised and executed that included specific health, safety, environmental and quality requirements and ethical standards, all in accordance with Angola's socio-economic and cultural characteristics.

Local content challenges were identified at early stage of the project. It allowed the development of a sound strategy based on selection, management and execution. This resulted in the upgrades of three of the five fabrication yards which were implemented in a cost-effective and timely fashion to meet overall project cost and schedules.

It was of paramount importance that if these yards were to perform essential work, they had to be manned with a skilled local workforce. Therefore, training was another key area of development for both the project team and contractors.
Technical Challenges and Impacts of Extending Spar and Semisubmersible Platform Capabilities to 4,500 m Water Depth
Authors: D'Souza R. B. , Aggarwal R. , Subramanian R.
Published: April 2015

Spar and semi-submersible platforms are proven deepwater production platforms. They have been used extensively in the Gulf of Mexico (GoM) to produce large deepwater developments. Spars have progressed from 600 m to 2,600 m water depth since 1995 and semi-submersibles from 450 m to 2,500 m since 1985. Topsides and hull sizes have grown to accommodate increasingly larger topside, riser, and mooring payloads. Extending these platforms to 4,500 m represents an almost 80% increase in water depth. The main technical challenges relate to the technical feasibility and installation of risers and mooring systems and their impact on the size and global performance of the hulls. Both aspects are examined in this paper for applications in the GoM.

The first aspect addresses technical challenges associated with designing production, injection, and export risers to handle the large hydrostatic pressure and limitations and/or gaps with regard to current lay vessel capabilities to install risers in 4,500 m water depths. The second aspect addresses the relative sensitivity of hull sizes and global performance of semi-subs and spars at these water depths for a common topsides and subsea architecture basis of design.

This paper presents the impact of extending design, fabrication, and installation of spar and semi-sub floating platforms to 4,500 m water depth. Field development scenarios, design basis and topside parameters (load, area, and height) are used to size hull, mooring, and risers to define the overall system. Proven, conventional hull designs and sub-systems technologies are used for both 2,500 m and 4,500 m water depths. Platform sizes and global responses in 2,500 m and 4,500 m water depths are compared. Technology gaps in meeting basis of design are identified. Trends, observations and relative sensitivities of the hull forms are captured. Enhancing and enabling technologies for risers and moorings are discussed. The 4,500 m hull sizes and key dimensions are compared with existing platforms to address availability of yards and vessels for construction and installation phases. Challenges related to fabrication, topside integration, mooring and risers installation in 4,500 m water depth for the two hull types are also addressed and contrasted.
VIM Study for Deep Draft Column Stabilized Floaters
Authors: Antony A. , Vinayan V. , Holmes S. , Spernjak D. , Kim S. J. , Halkyard J.
Published: April 2015

Dry-tree semisubmersible concepts have been studied under multiple RPSEA funded projects since 2009. As hull forms used for dry tree applications have a deeper draft, vortex induced motion (VIM) can be an area of concern that needs to be addressed during design stage. The VIM model testing that was conducted during prior RPSEA study phases indicated that VIM exists and can impact the platform mooring and riser integrity. The current RPSEA funded project is aimed at improving overall mooring system safety and riser system integrity by testing design parameters of deep draft column stabilized floaters (DDCSF) to determine the ones that have the most impact on VIM.

The study utilizes computational fluid dynamics (CFD) analysis and model testing to determine the sensitivity of VIM responses to DDCSF geometric parameters. The project studies both a four-column DDCSF and a multi-column DDCSF, specifically, the paired-column DDCSF developed by Houston Offshore Engineering (HOE). The CFD tools used are AcuSolve™ from Altair Engineering, Fluent™ from ANSYS and STAR-CCM+™ from CD-adapco. In this study existing VIM model test data is used to validate/verify the CFD tools, and the results are discussed in the paper. Some observations from the validation study are also discussed in the paper. More VIM model tests will be conducted during the later phase of the ongoing RPSEA project to correlate the CFD predictions with experimental data.

The study results are part of "Vortex Induced Motion Study for Deep Draft Column Stabilized Floaters", a study funded by Research Partnership to Secure Energy for America (RPSEA), under the project number 11121-5404-03.
Execution Challenges for a First of its Kind Project in Santos Basin Brazil
Authors: Camozzato Guilherme , Poirier Nicolas , Hiller Daniel , Acheritobehere Alain , Xavier Marcelo , Romeu Nelson Bittar , Seize Esio , Silva Alex Limeira
Published: April 2015

Sapinhoá-Lula NE project is a major subsea EPCI project where the successful introduction of innovative state-of-the-art technology was undertaken on a fast track schedule. The project execution included integrated supply chain and complex operations coordination with offshore campaigns performed in an extreme ultra-deep water environment where conditions are challenging. Awarded at the beginning of 2011, the Sapinhoá-Lula NE project was the first billion dollar subsea installation project ever in Brazil. The objective of this paper is to describe Sapinhoá-Lula NE project execution through its various phases and challenges from its award to its delivery.

The project had a number of technical challenges that were well understood and anticpated from the very start. Of significant importance was the need to design and fabricate four Buoy Supporting Risers (BSRs). Other technical considerations included component engineering, the mooring and monitoring of systems for the buoys and lay for the first lined pipe reeled under pressure.

Additionally, the Sapinhoá-Lula NE project team needed to have safety as its early focus on people, equipment and the environment. A commitment to innovation was of key importance with a significant number of new technologies, equipment and installation procedures needing to be developed, qualified, fabricated, tested and installed. The highest standards of quality and team collaboration at a global level were required in order to allow lessons learnt of each new operation to be promptly analyzed and implemented. Integrity at all levels and times, commitment to contract obligations and Client expectations were kept, regardless of the challenges faced.

As a result, within three years of contract award, Client had its first oil on the largest subsea EPIC signed to that date in Brazil. After four years of contract award, offshore execution was concluded delivering more than 30, 000 ton of state of the art equipment, installed in two fields, 300 km away from Brazilian southeast coast and producing 240, 000 bbl/day.
Design and Development of an HPHT Drillstem Testing Valve: A Case Study in HPHT Tool Design
Authors: Stolboushkin Eugene , Zuklic Steve , Fuxa Jason
Published: April 2015

The past several decades have shown a steady trend of work performed in increasing well temperatures and pressures; however, the industry has been slow to adopt new methods in the design of equipment to be used for these wells. As a result, certain types of equipment are now insufficient for operations in high-pressure, high-temperature (HPHT) wells. This hinders the development of HPHT fields and reduces the ultimate recovery from those fields; technologies that are successfully used in conventional wells are only very reluctantly used in HPHT wells.

Drillstem Testing (DST) valves are used for DST work, but also for tubing-conveyed-perforating (TCP) "shoot and pull" operations. These valves enable under- and over-balanced perforating, increasing the perforation quality and minimize the formation damage caused by kill fluids. However, these types of valves are frequently perceived as insufficiently reliable for TCP operations in HPHT wells, and frequently simpler perforation jobs are performed, sacrificing perforation performance for reliability.

A new DST Combined Test tool was designed with advanced analysis methods. These methods include not just stress and deflection analysis, but also an analysis of historic failure modes, including human factors, and the implementation of mechanical fail safes to prevent them in the new valve. The valve was tested to 30,000 psi hydrostatic with tubing pressure in excess of 40,000 psi, and at 400°F. Finally, the valve has been successfully deployed on field trials. This paper will present an overview of the valve development as a case study for the development of future HPHT tools.
Should Aluminum Conductors be Considered for my Subsea Power Cable Application?
Authors: Voight R.
Published: April 2015

Most baby-boomers have some familiarity with the classical stigma surrounding aluminum conductors in residential and commercial applications: fire hazard. Mention aluminum wiring in a building or residence and, not surprisingly, a lot of folks will react as if the structure in question should be condemned. How did aluminum get this reputation? Was it deserved? Is it still a valid assumption with today's modern aluminum alloys?

Many of the historical stigmas associated with aluminum can be attributed to technical design problems of the older alloys that have now been overcome by higher quality materials and/or addressed by aluminum specific design considerations. This paper addresses the aforementioned issues and investigates the current status of aluminum conductor technology as applied to subsea power cables with a specific emphasis on the following:

The Element Aluminum; Early History of Aluminum; Historical Stigmas; Technical Advances; Aluminum (Al) versus Copper (Cu); Aluminum Subsea Cable Experience.