bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Enhanced Safety Case Approach for Incorporating Environmental Impact
Authors: Kuo Chengi 
Published: September 2011

Abstract
The paper is concerned with integrating the effects of environmental impact into the methodology of safety management based on the fresh concept of an enhanced safety case (ESC). There are two key reasons for this approach. Firstly, it would enable both safety and environmental effects to be addressed by the same management system instead of treating them by different approaches. Secondly, preparing safety cases is familiar to the offshore oil/gas industry and there is no need to learn an alternative methodology. However, ESC is formulated by starting with a generic management system circuit linked to safety and environmental impact (EI) schemes. The main conclusion is that ESC is a versatile and practicable method and further research studies are in progress to explore its additional usage.
Statoil North Sea – Successful World Record MLT Installation
Authors: Eck-Olsen Johan , Solheim Ove Andre , Falnes Morten 
Published: September 2011

Abstract
In October 2010 the deepest set sealed multilateral junction in the industry was installed at 6900 m MD in Oseberg South well 30/9-F-9 AY1/Y2.
The differential pressure across the junction in the well is expected to be in the range of 250 bars. To meet this pressure requirement, a multilateral (ML) junction rated to 370 bars was identified. The high pressure junction components and entire multilateral system has undergone an extensive testing and qualification program, including several component tests and a full scale system interface and integration test.
A 10 ¾″ pre-cut window with an outer aluminium tube was installed as an integral part of the 10 ¾″ liner. The plan was to perform the milling operation through this window. A stuck string incident during the 10 ¾″ liner installations accidentally caused the liner to drop in hole. The liner ended up at the wrong orientation, and the window could consequently not be used.
The mainbore was drilled to TD at 8583 m MD and the 7″ liner was run and cemented. After the liner perforation the MLT operations started with the installation of a multilateral anchor packer to allow for installation of a latch interface assembly (LIA) and milling system. The LIA was installed and locked into the multilateral packer on a separate run.
The milling operation was done in a two step operation with milling of a 1st pass window using a 10 ¾″ milling machine prior to installation of whipstock and performing the 2nd pass milling operation.
The lateral branch was drilled to TD at 8258 m MD and a 5 ½″ screen completion was run and dropped off into the 8 ½″ open hole. The drilling whipstock was retrieved from the well and a completion deflector was installed. The junction was finally stung into the deflector, simultaneously as an open hole seal stinger entered top of the screen liner in open hole, tying the branches together.
A 6900 m long upper completion string with inflow control valves was finally installed to allow for surface control of the two branches.
The Autonomous RCP Valve - New Technology for Inflow Control In Horizontal Wells
Authors: Mathiesen Vidar , Aakre Haavard , Werswick Bjørnar , Elseth Geir 
Published: September 2011

Abstract
Horizontal wells with one or more branches have been used to maximize reservoir contact by Statoil and other oil companies for more than a decade. Frictional pressure drop and variation in permeability and mobility will naturally lead to non-uniform inflow profile along a well. Eventually, this will result in gas and/or water breakthrough, which may reduce the well performance and recovery significantly. The breakthrough typically occurs in the heal region of the well and in regions with high reservoir permeability. Inflow Control devices (ICDs) are flow resistance elements installed along the producing zone of a well to counteract the non-uniform inflow, hence improving the well performance. The technology is regarded as standard technology by the industry and classified as passive inflow control, since the geometry of the devices is fixed or preset prior to installation. Passive inflow control is applied to delay the unwanted gas/water breakthrough. However, once occurred, conventional inflow control will not reduce or stop the breakthrough. Statoil's new autonomous inflow control device (AICD) is an active flow resistance element distributed along the well, similar to conventional passive ICDs. Statoil's AICD will, in addition to delay the breakthrough, reduce the proportions of the breakthrough. The AICD will impose a relatively strong choking for low-viscous fluids and only minor choking for viscous oil. This is due to autonomous changes in the flow area internally in the AICD. With this technology the well performance and production can be higher after a breakthrough compared to conventional inflow control.
Statoil's AICD technology is piloted in two wells at two different fields in the North Sea. Each well is completed with 1-4 AICDs per screen joint, typically 200-400 per well. The AICD operates without need for human interventions and electric or hydraulic power. Well tests have shown that Statoil's AICD technology reduces the inflow of gas into the well from a reservoir containing light oil. Due to the restriction of the gas inflow, the drawdown can be kept high after breakthrough to allow significant oil production from the remaining oil zones in the well.
Likewise, in a pilot well in a reservoir containing heavy oil, well tests have shown that Statoil's AICD technology reduces the inflow of gas into the well and preliminary evaluations indicate that even water inflow is reduced. Thus the drawdown can be kept high allowing high production from the remaining oil zones.
The Activities and Recommendations of the UKCS OSPRAG Technical Review Group Following the Deepwater Horizon, Macondo Incident
Authors: Kinkead Brian 
Published: September 2011

Abstract
Following the Deepwater Horizon incident the UK Upstream Oil and Gas industry formed Oil Spill Prevention and Response Advisory Group (OSPRAG) in May 2010. The Technical Review Group (TRG) within OSPRAG was tasked with reviewing relevant aspects of well design, examination, primary and secondary well control and to consider a UK capping contingency in the event of a loss of well control.
This paper will examine the formation of the TRG and its approach to assessing whether the UKCS industry was performing in accordance with the regulatory requirements. It will examine the core TRG recommendations and assess how they are being implemented largely through the formation and work of Oil & Gas UK's Well Life Cycle Practices Forum (WLCPF). This includes the importance and relevance of assessing the future recommendations from the Macondo incident.
Finally, the experiences and effectiveness of working within a cross industry team with members drawn from across industry including regulators, operators, contractors and trade unions will be discussed.
Qualification of the Deepwater Subsea Well Intervention System "AX-S" for 10,000 ft Operations
Authors: Svensen Matthew , Williamson Robbie , Law Matthew 
Published: September 2011

Abstract
This paper presents a detailed description of the technology qualification for the novel deepwater subsea well intervention equipment, the "AX-S™ system" developed by Expro AX-S Technology Ltd, and how the statement of feasibility of the project was developed and successfully achieved. Using the framework for technology qualification - Det Norske Veritas’ recommended practice "RP-A203: Qualification Procedures for New Technology", DNV and Expro AX-S overcame a series of challenges to deliver the first project milestone (statement of feasibility) while ensuring that the project timeframe was not impeded. The Expro AX-S subsea well intervention system can operate in depths of up to 10,000 feet and negates the need for a drilling rig and riser systems, instead using remote intervention from a dedicated monohull vessel.
Ensuring the Integrity of Subsea Hot Tap Welded Joints in Lieu of Hydro Testing
Authors: Smith Alan , Williamson Robbie , Low Andrew 
Published: September 2011

Abstract
Hot tapping of subsea pipelines is a cost effective method of transporting production fluids from satellite wells into existing pipelines. The process involves welding a branch connection onto a flowing operational pipeline and trepanning a coupon from the outside of the mother pipe. The technique is now well established and can minimise production down time. In most cases, the integrity of the branch weld is proven via subsequent pressure testing to prescribed limits based upon a multiple of the anticipated design pressure. However, in exceptional cases, such strength testing may not be possible. If this is the case it may be necessary to ensure the integrity of the welded joint by non destructive testing. This paper examines the use of non destructive testing and specifies the issues which need to be considered and the process involved in qualifying a Hot-tap weld. The use of NDT is justified by reference to the fracture toughness of the weld and associated microstructure and is based on a fracture mechanics argument. The paper draws on experience gained in the practical application of this methodology offshore.
Qualifying an External Turret and Mooring System for the Offshore Industry
Authors: Ogosi Eugene , Williamson Robbie , Galbraith David , Donovan John 
Published: September 2011

Abstract
This paper presents the procedure used in and benefits of applying a cost-effective method for qualification of an innovative external turret and mooring system. The system has been developed by Sigma Offshore Limited for application in the offshore industry. Qualification of technology is a major challenge to the offshore industry particularly in the oil and gas sector, where it is essential to demonstrate the applicability and operational reliability of new technology before it is applied. Technology qualification in this case essentially increases the operators’ confidence in the technology. It assists the contractor to improve on the design of the proposed technology in order to comply with strict safety standards and meet the technological challenges of the industry.
The Sigma Offshore Smart Mooring System (SMS) is an external turret and has been designed to provide an FSO/FPSO mooring and fluid transfer solution which is intended to minimise hull invasion, provide a cost-effective on-site installation option and allow unlimited weathervaning of the vessel. The Sigma SMS can be installed on the vessel without the need to dry-dock allowing for significant installation cost savings. The SMS contains a unique Gimbals system which comprises bearings acting around 3 perpendicular axes, together with the steelwork to connect them and carry the forces between a canister attached to the risers and mooring lines and the cantilever attached to the FSO/FPSO.
The method which has been applied in the qualification of this technology is based upon the existing framework for the technology qualification - ‘Det Norske Veritas’ recommended practice "RP-A203: Qualification Procedures for New Technology’’. This recommended practice (RP) describes a systematic and generic work process that is ideal to qualify such new technology. The benefits of the qualification method were demonstrated by applying it to the SMS with the resultant identification of key improvement in the design consideration, system reliability and reduction of risks before first implementation.
High-Density OBC—A Step Change in Reservoir Imaging—A BP North Sea View
Authors: Davies Daniel , Mannaerts Herlinde , McGarrity John , Ibram Mark , McKenzie Colin , Campbell Steve , Alexander Gino , Lozano Angeles , Kommedal Jan , Barkved Olav , Van Gestel Jean-Paul 
Published: September 2011

Summary
BP is committed to a long term future in the North Sea Region. Delivering this promise will rely on continued exploration and appraisal success within the basin as well as efficient and cost effective resource progression through infill drilling and enhanced hydrocarbon recovery schemes in generally mature fields. To maintain track record, drive higher field recovery and progress infill drilling, it was realised that availability of current, fit-for-purpose seismic data is a key enabling technology.
This paper looks back on BP North Sea experience of using Ocean Bottom Cable (OBC) seismic data. Since 2002, BP has acquired at least two OBC surveys per year in the North Sea to support the appraisal and development of fields, with significantly more fields covered. Since 2009, this has been increased and we are averaging nearly 5 surveys per year.
Unlocking the Future for a Mature Field: Surveillance and Complex Wellwork Combine to Extend Field Life
Authors: Dunning Matthew , Stripe John , Keatinge Patrick , Newton Peter , Davies Ann , Waugh George 
Published: September 2011

Abstract
Ravenspurn North is a mature gas field forming part of BP’s UKCS portfolio. The field commenced production in 1990 through 42 wells and 3 platforms but by 2006 half of the wells had ceased to flow. Surface pressures suggested limited remaining gas and, with declining production, the field was at risk of abandonment.
A surveillance campaign carried out in 2006 suggested a common failure mode for many wells, which postulated that large amounts of proppant had accumulated in the wellbore. Pressures measured downhole above the proppant fill supported a significant increase of the remaining gas potential.
A project to rejuvenate this field was initiated in 2007. The key to this project was cleaning out and reinstating non-flowing wells across the field. This would require pushing the boundaries of cleanout techniques and delivering a number of industry firsts, all on normally unmanned installations with complex logistical challenges. Additionally, each individual well intervention would be economically marginal on a standalone basis - the project had to place these interventions into a wider business context before building the case to justify the investment needed to resolve the many challenges presented.
This paper details the journey to maximise the potential of the mature Ravenspurn North field. It starts with the acquisition of surveillance in 2006 and covers how the business case was built to justify one of BP’s most complex well intervention programmes in the North Sea (concentric coiled tubing vacuum technology on a small unmanned platform). It culminates in the successful execution of the first phase of wells in 2010.
With the first phase of the Ravenspurn North rejuvenation complete, this paper reflects on the lessons learned along the way and identifies the key activities which have contributed to delivering a longer, brighter future for this field.
Innovative Web Portal Reservoir Knowledge Base Integrates Engineering, Production, Geosciences and Economic Data Sets
Authors: Rees D. , Reichardt J. , O’Carroll A. 
Published: September 2011

Abstract
This paper describes a novel web portal, which has been created for the North Sea area to meet the need for a knowledge base of reservoir and engineering data targeted towards exploration and production professionals to assist them in evaluating prospects and projects, assessing development risks, and measuring prospects against other opportunities in their company portfolios. Operators in the deepwater Gulf of Mexico have found a similar service an invaluable resource when researching analog fields, as reservoir assessment and benchmarking are at the heart of good appraisal, sanction and development decisions. Through utilizing analogous data, decision makers can evaluate assumed data based on its statistical place in similar fields and geological regions. When analytics are performed in this manner, uncertainty risk can be reduced.
The North Sea knowledge base features innovative applications, including a GIS interface and a set of analytical tools, and is maintained and supported by a team of engineers and geologists who provide analysis, case studies, and statistics on key data and fields.
Directed towards exploration, appraisal and development teams in the North Sea area, the knowledge base contains coverage of all productive sands discovered, reservoirs either currently in production or sanctioned for development. The service provides regularly updated reservoir metrics and analogs, and offers a unique combination of reservoir engineering, geological, production, facilities and economic data analysis, together with regional knowledge.
Users may also leverage the public domain information and analysis in the knowledge base by deploying secure servers in-house to store, manage, and compare proprietary data with the data and data analysis stream provided. This model leverages internal security systems to keep client data safe, while providing their engineering, geologic, and other subsurface technical staff with a single stop for current asset status, up-to date analogs, play and regional data, and both internal and external best practices, case studies, and literature, etc. With an extendable data model to manage structured and unstructured data, this solution provides a framework to ensure that exploration and asset teams can access all data of immediate interest, and also highlights other key knowledge related to specific prospect, appraisal and or development evaluation needs.
Application of Particle Swarm Optimization for Parameter Estimation Integrating Production and Time Lapse Seismic Data
Authors: Rwechungura Richard , Dadashpour Mohsen , Kleppe Jon 
Published: September 2011

Abstract
The purpose of reservoir modeling is not only to build a model that is consistent with currently available data, but also to build one that gives a good prediction of its future behaviour. Updating a reservoir model to behave as closely as possible to the real reservoir is called history matching, and the estimation of reservoir properties using this method is known as parameter estimation and it is an inversion process.
Here we apply one of the evolutionary algorithms (Particle Swarm Optimization – PSO) to estimate porosity and permeability using both production and 4D seismic data. PSO is a population-based stochastic optimization algorithm. It is known as a swarm intelligence algorithm because it was originally inspired by simulations of the social behaviour of a flock of birds. The method combines simplicity in implementation and high capability for distributed (parallel) computing.
The results obtained on a 2D section of the Norne Field in the Norwegian Sea, demonstrate that this parameter estimation approach combines moderate computational requirements and better objective function values and exhibits good ability to handle history matching problems without exhaustive sampling of parameter space.
CO2 Monitoring: Taking the Pulse of CO2 Storage Reservoirs
Authors: Clyne Hazel , Phillips Ian , James Alan 
Published: September 2011

Abstract
This paper provides an overview of the current legislation regulating the deployment of carbon capture and storage (CCS) in the European Union, and examines how this regulation dictates the selection, implementation and long term use of monitoring technologies at CO2 storage sites onshore and offshore.
We consider the wide range of purposes and objective that a CCS Monitoring Plan has to meet, and the resulting wide range of parameters that it is necessary to monitor. We also assess some of the practical considerations that may render a particular technology viable in one reservoir, and completely inappropriate in another reservoir.
The authors conclude that the monitoring plan will be highly site dependent. We also note that there exist a wide range of cost-effective and readily deployable wellbore logging and monitoring tools developed for the oil and gas industry, which have direct applicability to the monitoring of a CCS storage site and complex. However, the unique attributes of CO2, and the significant difference in the monitoring objectives when compared with oil and gas activity means that there is significant potential for new technologies to improve CO2detection in the subsurface and to reduce costs.
BP North Sea: Introduction and Compliance with BP's Aviation Group Defined Practice: Group Defined Practice 3.7 - Aviation
Authors: Combe Alan , Parker John , MacLean David 
Published: September 2011

Abstract
The requirements for the Management of Aviation Risks is set out in BP Group Defined Practice (GDP) GDP 3.7-0001 Aviation, covering all aspects of the operators contracted services and the management of these services, to include safety management systems, operations, flight crew and engineering training and experience, passengers and freight, aircraft equipment standards and Emergency response planning.
GDP 3.7 was issued in October 2009 with a requirement for all new or extended contracts for Aviation services to be conforming at either the contract renewal date or by 31st December 2010 for existing contracts. A tight timescale given the need to change contracts, add equipment, change aircraft in some cases and gain agreement with our operators in order to meet the additional requirements.
BP North Sea declared full conformance with GDP 3.7 for all our Aviation crew change and Search and Rescue contracted operations ahead of the required conformance date of 31st December 2010.
To declare full conformance, a gap analysis was completed over a number of months supported by each of our contracted operators with contracts updated to meet all GDP requirements. The BP Group Defined Practice used the Aircraft Management Guidelines – the industry best practice - published by the International Association of Oil and Gas Producers as the basis for GDP 3.7. We have reinforced the content of the original document by mandating many elements to standardize the way in which BP approaches Aviation Safety and operations globally. We have added content from our own lessons learned to drive continuous improvement throughout our business.
Conformance with GDP provides enhanced safety by adopting the most recent technical advances in aircraft equipment by mandating systems such as Traffic Collision Avoidance, Ground proximity warning, Automatic Float Deployment, External life rafts and Operator Satellite flight tracking for all BP Aviation operations.
Workflows and Considerations for CO2 Injection in a Highly Depleted Gas Field in the Southern North Sea
Authors: Webster C. McK. , Zhang Y. , Park D. , Gibbons K. A. 
Published: September 2011

Abstract
Issues and associated mitigation measures for Carbon Capture and Storage (CCS) relating to capacity, injectivity and integrity of the storage site are not trivial. Modeling of CO2 injection along wellbores is still in its infancy compared with traditional hydrocarbon modeling. While a significant amount of work has been done with respect to modeling discrete components of the storage site and associated infrastructure, validation of our modeling tools and the results still remains uncertain, particularly with respect to two phase flow in the wellbore.
This paper presents a workflow for injection of CO2 into highly depleted gas fields, addressing the issues around injection modeling and the impact on surface facilities, well design and the near wellbore interface. These include: obtaining accurate predictions of phase behavior, density, and viscosity, determining the impact of delivery pressure and temperature versus reservoir conditions. Wellbore design issues such as sizing and load resistance of tubulars and metallurgy selection in order to ensure both injection performance and integrity must also be considered. Modeling CO2 in the reservoir is also discussed considering the near wellbore effects (cooling and potential ice / hydrate formation). Finally, short and long term monitoring issues are identified and the benefits and limitations of the various monitoring options are discussed.