bluuebunny/crossref_metadata_2025_split huggingface dataset:
Workover/Well Intervention and Regulatory Challenges
Authors: Solli Tomas Elander 
Published: October 2011

Abstract
Historically classification of ships was introduced for the maritime industry. This was back in the 18th. Century when all ships had very similar tasks. The diversity today is something completely different and workover units are one of the latest add-ons to the wide variety of ships and offshore units. So how do the shelf states, flag states and classification societies address this situation?
The term workover is used to refer to any kind of oil well intervention involving invasive techniques, such as wireline, coiled tubing or snubbing. What are the accident scenarios following workover/well intervention? Many shelf state authorities consider any unit that connects to a live hydrocarbon well to be an offshore unit. Are the vessels involved in workover suited for the task? The current situation is very complex due to the fact that the different types of workover techniques and operations have a very different risk profile. Today there are very few international requirements associated with the vessels or equipment used during well intervention. With the Macondo disaster fresh in mind it is also prudent to ask if the systems and safeguards in use during well intervention and workover are sufficient. Also in this growing industry new operators are rapidly entering into this market; with or without relevant experience. Practically any offshore supply vessel can swiftly be converted into a well intervention unit without any assessment or approval of the modification of the vessel.
At the same time the number of subsea wells used in the offshore industry is rapidly increasing. Any subsea well in any deepwater development will need well intervention sooner or later to varying extent. And the vessels used can undertake heavy or light well intervention with minor modifications to the vessels.
To a big extent the well intervention industry is self regulating. In this paper DNV will present their view on the regulatory challenges in this booming industry and the risks involved in these activities.

Introduction
Before discussing the subject of this paper further I will need to clarify the subject. What is workover? And what is Well Intervention? There are different understandings amongst different parties in the oil industry what these terms really mean. There is no reason to argue whether one view is more correct than the other, but for the sake of this paper it is important to clarify what is being addressed In the Schlumberger Oilfield glossary Well Workover and Intervention is defined as follows:
" The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.??
Unique Salt Drilling Steerability Test: Advanced RSS Proved Outstanding Build-up Rate Capability in Brazil Mobile Salt Formations
Authors: Thomson Ian James , Krasuk Raul M. , Freesz Marcos Paulo 
Published: October 2011

Abstract
Salt drilling in offshore projects has become more frequent over the last 10 years in many parts of the world. In Brazil, important oil discoveries were made in carbonates reservoirs that lay below thick salt bodies. Drilling through salt can be challenging, especially where severe salt mobility is common. Salt mobility or creep rate is mainly a function of downhole temperature, geomechanical stresses around the salt body and salt mineralogy.
Today, many deepwater wells targeting hydrocarbons below the salt in Brazil are still considered exploratory or appraisal, and are drilled vertically through salt, with only a few projects in the development phase. Due to the gradual transition of deepwater projects into the development phase, the requirement for directional drilling through salt is rapidly increasing.
To achieve a better understanding of the salt drillability, in terms of steerability capabilities and directional assembly stability, a pioneer directional drilling test was conducted in a mobile onshore Brazil salt formation, using an advanced rotary steerable system (RSS) and a specialized downhole drilling optimization measurement-while-drilling (MWD) tool. This paper will show, in detail, the results and lessons learned from this unique salt drilling steerability test, along with the result of deepwater sections drilled directionally through salt formations offshore Brazil.

Introduction
Directional drilling through salt has been perceived by the drilling community to be a challenge due to the plastic nature of the evaporates and due to wellbore stability problems commonly experienced in the past. The ability to consistently perform directionally in salt and achieve the planned buildup rates (BURs) had been an issue in salt throughout the years. In general many aspects rule the BUR capability in salt: The evaporate rock being drilled, salt creep rate, and bottomhole assembly (BHA) and bit design, among others. The directional drilling technologies evolution over the last years, along with the experience gathered in salt drilling worldwide, had given more confidence for operators and service companies to venture in directionally drilling through salt intervals.
LNG Tandem Offloading - A Qualified Technology Now Ready for FLNG Project
Authors: Lavagna Damien , Le Touze Laurent , Fournier Jean Robert 
Published: October 2011

Abstract
LNG offloading operations are critical for the FLNG deployment on fields subject to medium or harsh environmental conditions. In the oil industry, tandem offloading operations are routinely performed using flexible marine hoses in various project specific configurations. The challenge of offshore LNG transfer lies in the combination of constraints from both the cryogenic operational requirements and the aggressive marine environment.
From 2006 onwards SBM Offshore has developed an EN1474-2 compliant flexible cryogenic marine hose for offshore transfer of LNG. In 2010, the hose design and fabrication received a Type Approval certification from both ABS and DNV. SBM then completed the qualification of both the cryogenic coupling and the LNG tandem transfer system.
The LNG transfer system is located on the stern of the FLNG and is connected to a dedicated bow manifold on the LNG carrier. The line configuration is suitable to handle the boil-off gas and transfers the vapour back to the FLNG boil-off gas management system. For the safety of operations and to increase the operability weather window, this system is designed to be operated without support vessels or tugboats. The line deployment and retrieval operations are carried out in a similar fashion to oil transfer systems and benefit from years of field expertise.
This paper describes the system and outlines the main operating procedures. It summarizes the qualification roadmap including concept review, design assessment and associated testing program. It also presents the design analyses that were carried out, concludes on the generic system performances and operations limitations, and highlights key integration issues.
Considerations for the Use of Carbon Dioxide Removal Membranes in an Offshore Environment
Authors: Tierling Shane , Jindal Sanjeev , Abascal Ricardo 
Published: October 2011

Abstract
Interest has been piqued in the use of membranes for the removal of bulk carbon dioxide from natural gas in an offshore environment because of the advantages that membranes present in weight, space efficiency and tolerance of motion. A number of practical considerations have to be considered when using membranes for CO2 removal offshore and these will be discussed in the context of recent KBR work.
Membranes have strengths and weaknesses compared to other carbon dioxide removal technologies in an offshore environment. These strengths and weakness lead to specific concerns and opportunities that should be addressed in the design stage and can have impacts on the full life cycle of the offshore facility if not fully addressed. We will discuss how to approach these issues to lead to successful construction, operation and maintenance of the carbon dioxide removal membrane system in an offshore environment.

Introduction
Gas is becoming an increasingly important part of the global energy equation constituting 18.5% of the energy mix in 1977 which further increased to 23.5% of the mix in 2005 per Wood (2007) [Fig. 1].
A Case Study: A High Throughput Mud-Gas Separator for Underbalanced Drilling
Authors: LeBlanc Chris Mark , Amorim Marco , Piacentini Roberto 
Published: October 2011

Abstract
Underbalanced drilling (UBD) is a drilling technique in which hydrodynamic pressure, exerted by the drilling mud and circulating fluids in the well bore, is below the pressure of the well formation. In UBD applications the surface pressure is lower than the well pressure, resulting in the flow of hydrocarbons to the surface at a controlled rate. This drilling technique requires specialized surface equipment for continuous separation of the drilling mud and hydrocarbon components for recirculation, sampling, storage, flaring, and disposal. Underbalanced Drilling technology provides significant technical and economical value and reduces damage to the well formation. This paper highlights how custom-off-the-shelf technology provided a cost-effective solution where Petrobras was able to reduce the time required to reach full production and eliminate or reduce, the fracturing required after a well is completed.
Global Offshore Operations Performance: Assessing Uptime Reliability
Authors: Kilchrist Joseph , Alba Juan Carlos 
Published: October 2011

Abstract
During the past dozen years, Ziff Energy has studied the Operating Costs and Uptime Reliability of Offshore Operations in the North Sea, Gulf of Mexico, West Africa, Asia Pacific and South America (i.e. Brazil). In all, Ziff Energy has detailed operations data for more than 900 offshore assets in 20 countries. These include Shelf and Deepwater assets, including older platforms, high productivity ‘LNG Feed' offshore gas fields, and all types of production systems (from fixed structures to subsea wells, spars, TLP's and FPSO's). Ziff Energy Group's Operating Efficiency/Reliability methodology provides a unique opportunity for offshore operators to compare their operations performance with other operators' similar operations. This presentation will include an overview of the metrics calculated and the lessons learned in measuring the uptime reliability performance of offshore operations, drawing on examples from our extensive experience. We will compare Offshore operations from around the world (e.g. by production system).

Application
The presentation will highlight uptime/production reliability performance issues associated with production losses in offshore operations. The presentation will present a sample of case studies (key findings) and will outline the role of performance assessment in guiding the continuous improvement of operations efficiency and reliability.

Results, Observations, and Conclusions
The presentation will provide production efficiency assessments from Ziff Energy's Offshore studies of oil and gas operations. Challenges in completing an assessment of Offshore Production Efficiency will be addressed, including differences between operators in their definitions of planned and unplanned losses. The presentation will include a look at the benefits of peer assessment of Offshore Operations.

Significance of Subject Matter
The presentation provides new performance management tools (metrics) by production systems:Uptime ReliabilityKey Performance Indicators - Metrics
These tools are useful for managing the operations performance of offshore fields, which help operations management extend the economic life of their fields.
Tools and Techniques for the Selection and Design of Safe Deepwater Riser Systems for Mobile Offshore Drilling Units
Authors: Whooley Alan , Deegan Jonathan , Goldsmith Riley G. , Botto Adriana 
Published: October 2011

Abstract
The deepwater drilling industry has been rocked by the tragic Deepwater Horizon event in the Gulf of Mexico. The incident identified a number of possible failings by operator, service contractors and the regulator which combined to lead to the ultimate results which were evident in mid 2010. This paper will assess the options available to the deepwater drilling industry in assessing the risk of various riser and BOP configurations for drilling and completing deepwater wells in moderate metocean environments. The paper will address two different systems:A classic subsea BOP stack configuration,A surface BOP stack with a subsea isolation device (SID).
Both of these configurations have merits depending upon a number of factors which include rig availability and schedule, project economics, riser integrity, BOP configuration, geological issues and, most importantly, the hazard and risks associated with each concept.
This paper will identify the various technical analyses and risk analysis techniques that must be undertaken to assure the operator of the system is comfortable with each system. These include riser analysis, rig mooring and station keeping analyses, system HAZIDs and HAZOPs, and more.
The idea of the paper is to provide the operator and drilling contractor with a ‘road map’ which will allow them to navigate their way through the various issues to be addressed. This road map will start with the concept stage (rig contracting early well planning) where issues such as project economics, rig availability and risk tolerance will provide input into the overall decision making process. The paper will next address the preliminary and detailed design stages where issues surrounding metocean criteria, rig characteristics and rig configuration and geological conditions will play a part in the overall input. The paper will describe how a project team would approach the issues. Finally as the project moves to the implementation stage the paper will describe the techniques for final assurance that the concept can be managed in the implementation stage.
Capturing the True Non-Linear Load-Elongation Properties (Including Permanent Elongation) of Polyester Rope in Mooring Analyses
Authors: Pasternak Jason , Garrity Robert , Leite Sergio 
Published: October 2011

Abstract
Polyester is the most widely used synthetic fiber in modern mooring systems. Though its use is widespread, very simplistic models of its nonlinear load-elongation behaviors are typically utilized in mooring analyses for predicting maximum line tensions and facility offsets. This oversimplified approach can lead to under/over conservative results affecting both mooring system and riser design. A more accurate approach is to separate the permanent elongation of the rope from its non-linear rope stiffness properties. Handling these variables (stiffness and permanent elongation) independently is key in accurately representing the mooring system's response. Different mooring scenarios (e.g. MODUs, FPSOs, SPARs) are affected in different ways by the use of an oversimplified load-elongation model of polyester behavior. This study will address these affects for both a Semi-submersible and an FPSO under metocean conditions typical of the Brazilian basins.
Through a detailed rope testing plan, rope non-linearities and length effects as a function of mean load and frequency of loading oscillations can be fully captured for use in mooring analyses, better predicting actual mooring system responses. One such rope testing plan will be discussed and shown how the data is analyzed and prepared for use in the mooring analysis.
By modeling the true non-linear stiffness and being able to capture the permanent non-recoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that re-tensioning operations will not significantly impact the facility's ability to operate. Such accurate vessel motions and offsets from this analysis method also aid greatly in the riser and other system designs that are integral parts of permanently moored facilities.

Hydrodynamic Model Overview
For the semi-submersible examined in this case study, a generic Mobile Offshore Drilling Unit (MODU) model was created with symmetry along each horizontal axis. This symmetry, in conjunction with an assumed flat seafloor, allowed for metocean conditions to be applied only on one quadrant of the model to determine the controlling environment direction. The chosen base model was a modified Aker H-3 Series semi-submersible. The approximate vessel dimensions are ~74m×63m with a operating draft displacement of ~28,000 mt. The following figure shows the hydrodynamic model of the semi-submersible that was created in AQWA and used to generate the RAOs and wave drift forces.
Dynamic Positioning Capability and Enhanced Reliability
Authors: Reilly George T. , Hensley Michael 
Published: October 2011

Abstract
The dynamic positioning (DP) classification notations (DPS-1 to DPS-3) reflect the equivalent International Maritime Organization (IMO) equipment classes which represent increasing levels of redundancy. The criteria given and the use of Failure Modes and Effects Analyses (FMEA) have formed the industry's basis for evaluating DP. However, other important measures, such as position keeping capability and reliability of the designs, are not reflected in these current notations.
This paper investigates the use of another well established risk tool - the fault tree which allows for the interaction of various components and their failures to be mapped from the vessel's design. The technique provides for the use of the tree design and failure data to be combined so as to give numerical values to the probabilities of (time between) failures of system components.
The values that come from the fault tree approach can then be used in the development of an Enhanced Reliability (ER) notation (e.g. DPS-2, ER-60, 40kn - indicating 60 days between failures that result in loss of redundancy in a 40 knot ‘environment’). This enhancement to DP criteria is expected to be the most significant since the IMO Guidance was originally published.

Application
The progression of offshore operations into deeper waters was inevitably accompanied by the increased adoption of DP systems as traditional mooring systems became less viable for small units or for short periods of operation.
Entities interested in using vessels with DP capabilities need a mechanism for comparing different units against their specific operational requirements. In addition, DP system vessel owners want their assets to be easily identified for the capabilities (and investments) they have to offer.

Results, Observations, and Conclusions
Procedures on the development and the requirements of the Enhanced Reliability for DP systems will be presented.

Significance of Subject Matter
Compliance with the Enhanced Reliability requirements would provide a means for owners and operators to have a consistent and quantitative measure of the capability relative to the reliability of the DP system.
Correlation of the Petroleum System from Santos and Namibian Offshore Basins
Authors: Mello Marcio Rocha , Bender Andre A. , Filho Nilo Chagas Azambuja , Barbanti Silvana , Franke Milton R. , Jesus C.L.C. 
Published: October 2011

ABSTRACT
The sedimentary basins of the South Atlantic have developed into one of the most active regions for petroleum exploration in the whole world. The increase of interest in the oil industry has resulted from the numerous recent giant to supergiant oil and gas discoveries along both the eastern and western continental margins of the South Atlantic in deep and ultradeep waters. The use of the petroleum system concept in the South Atlantic marginal basins provides an effective means of classifying and characterizing the diversity of the oil and gas systems, as well as, a means to aid in the selection of appropriate exploration analogs. The South Atlantic marginal basins also provide some of the best examples of how petroleum systems evolved through time with respect to both their levels of certainty and their areal and stratigraphic limits. An examination of the Orange and Santos basins, in Namibia and Brazil, respectively, provides examples of almost perfect analogs in terms of petroleum system. For example, lacustrine and marine source rocks, similar oil type, almost identical reservoir deposition environments, traps associated with basement highs and vertical migration pathways dominate in each of the basins, with normal faults networks providing the effective carrier. However, there are clear differences when Aptian salt layers are present in the Santos basin and absent in the Namibian basins. Also, differences are observed when thermal evolution is considered. Although no Aptian salt section is present in Namibian basins, and thermal maturity appears to be much higher in the Namibian coast, both basins share almost identical elements and processes of the petroleum system concept. In summary, the aim of this paper is to show how the petroleum system modeling, supported by geochemistry, allows a correlation between counterpart basins across the South Atlantic realm.

DISCUSSION
The evolution of the South Atlantic sedimentary basins provided the general conditions for the establishment of various petroleum systems. The formation of source rocks, reservoirs and traps are directly related and connected to the phases of the evolution of the passive continental margins (Figure 1): pre-rift, syn-rift, transitional and thermal sag (drift) sequences (Mello, 1988, Mello et al, 1991 and Katz and Mello, 2000).
Pre-Stack Full Waveform Inversion for Velocity Model Building
Authors: Kapoor S. Jerry , Vigh Denes , Bunting Timothy John 
Published: October 2011

Abstract
An accurate earth model is key to any successful depth imaging effort. Full waveform inversion is an advanced velocity model building process which uses the full two way wave equation. Existing methods use a ray tracing approach to distribute velocity errors within the model. In this presentation, we will show examples of seismic data processed with the latest technology, including earth model building with full waveform inversion.

Introduction
The industry has moved to using two-way wave equation migrations(commonly known as reverse time migration), especially in areas of complex geology such as the salt bodies in the Gulf of Mexico and offshore Brazil. The velocity model, including velocity anisotropy, is key to any depth migration effort. The natural next step is to use the two-way wave equation for velocity model building. One of the most advanced tools for velocity model building using the two-way wave equation is Full Waveform Inversion(FWI). Full-waveform inversion uses computer intensive forward modeling of the seismic measurement combined with residual wavefield back propagation to iterate to a final velocity model, which can provide greater detail than tomographic ray tracing approaches. Velocity inversion using full waveform inversion has been used on a number of projects around the world including the GOM, Brazil and the North Sea.