bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Economic Dependencies of Infrastructure Assets in the UK Continental Shelf (UKCS)
Authors: Acheampong T. , Kemp A. G. , Phimister E. , Stephen L. 
Published: August 2015

Abstract
The United Kingdom Continental Shelf (UKCS) is a mature region with around 42 billion barrels of oil equivalent produced since the late 1960s. The majority of the remaining estimated 15 billion barrels of oil equivalent reserves lie in more technical and challenging areas. To produce these reserves, access to existing infrastructure through subsea tiebacks for new and incremental projects or as new standalone development projects remain key to the future of UKCS and slowing the recent production decline. Currently, about 60 percent of all new fields in the UKCS are subsea tiebacks to existing infrastructure and there is an increasing interdependence for both production facilities and transportation infrastructure1. Many recent discoveries have been comparatively small and are not large enough to support their own infrastructure.
This paper attempts to answer this critical question: how does the separation of infrastructure and field ownership affect economic recovery in a mature oil basin? We explore how possible different ownership structures and access arrangements might affect the economic viability of the remaining UKCS reserves by applying a mixed integer-programming model to field data from the Northern North Sea. Specifically, we consider the impact of a changing tax regime in a way that is relevant and consistent with unbundling infrastructure provision through cost sharing arrangements and how this affects the long-term economics of hubs and their user fields. The model is used to maximize the net present value of regional production (the maximum economic exploitation of the region) by determining the optimal set of new developments, tiebacks from fields to hubs, and timings of hub and field shutdowns. The effects of the separation of infrastructure and field ownership are captured by individual field and infrastructure viability conditions constraints.
Novel Approach for Predicting Multiple Fractured Horizontal Wells Performance in Tight Reservoirs
Authors: MoradiDowlatabad Mojtaba , Jamiolahmady Mahmoud 
Published: August 2015

Abstract
Multiple fractured horizontal wells (MFHWs) are considered as the most effective stimulation technique to improve recovery from low permeability reservoirs particularly tight and shale assets. The understanding of the complex flow behaviour and predicting Productivity Index (PI) of these wells are vital for exploitation of such reservoirs. These data also affect the optimum hydraulic fracture design and the long term well performance.
The, analytical or semi analytical, models previously proposed cannot accurately describe the flow behaviour around MFHWs due to lack of capturing the complexity of the flow especially the fracture-to-fracture interference effects. The fine grid three dimensional (3D) simulation approach is also costly and cumbersome. In this work, we followed a novel approach to develop a new equation that can predict MFHWs performance under pseudo-steady state flow conditions in tight reservoirs.
An in-house programming code, which automatically creates batch files, reads input data and stores relevant output data for each simulation, was coupled with a fine grid 3D reservoir model to generate the required large data bank. For these simulations, the pertinent parameters (matrix permeability, number of fractures and fracture permeability, spacing, width, length and conductivity) were varied over wide practical ranges based on the full factorial experimental design method.
The overall as well as the individual impacts of the parameters on PI, as the output variable, were evaluated by various statistical analyses techniques, including Spearman's rank correlation coefficient, under different prevailing conditions. It is shown, for instance, that increasing the fracture width and permeability does not result in a significant monotonic increase in PI while changing fracture length, spacing and numbers influences PI greatly.
Moreover, a new expression is proposed that relates MFHWs-PI to PI of the horizontal well with a single fracture and to number of fractures and dimensionless fracture spacing parameters by applying the symbolic regression technique. The cross validation results show that the proposed equation is general, reliable and simple for prediction purposes because it benefits from limited and appropriate dimensionless numbers with excellent values of fitting indices.
This study expands our understanding of flow behaviour in tight reservoirs and provides an invaluable engineering tool that can facilitate simulation of flow around MFHWs and quickly predict their well performance. The new IPR equation can also be used for optimising MFHWs design.
Spectral Noise Logging Integrated with High-Precision Temperature Logging for a Multi-Well Leak Detection Survey in South Alberta
Authors: Aslanyan Arthur , Aslanyan Irina , Karantharath Radhakrishnan , Minakhmetova Roza , Kohzadi Hassan , Ghanavati Mohsen 
Published: August 2015

Abstract
Gas or fluid ingress into the cement channel and then up to the surface through the surface casing annulus is called Surface Casing Vent Flow (SCVF), which causes Sustained Annulus Pressure (SAP) as a common occurrence in the petroleum industry. Gas may also migrate to the surface outside the outermost casing string, which is often referred to as external Gas Migration (GM) or seepage. In some countries with shallow coal reserves, gas migration sometimes occurs in association with coalbed gas (CBG) development. Dewatering the coal seams or lowered water levels in coal, whether induced by drought or by domestic aquifer pumping, can result in the release of methane and other natural gases in coal (NGC). Hydrocarbon gases released into the atmosphere is an environmental concern. More importantly, leaking fluids may contaminate subsurface fresh-water reservoirs, resulting in a major catastrophe for the environment and human population.
According to the latest statistics, 6% of almost 270 000 operating and idle wells analysed in Alberta were found to contain leaks, 5.5% of them having SCVF and 0.5% gas migration [2]. Operators are bound by the Alberta Energy Regulator (AER) to identify and eliminate leaks and perform remedial operations as outlined in AER's rules and directives.
Even if a well is to be abandoned, the operators must precisely identify the location of the leak and its source to perform a successful plug-and-abandonment (P&A) operation. P&A activities are non-revenue generating activities. The right diagnostic technology is critical for correct leak source identification to eliminate the costs associated with numerous unsuccessful attempts.
The technique of Spectral Noise Logging (SNL) coupled with High Precision Temperature (HPT) Logging have extensively benefited oil industry outside Canada in accurately identifying fluid flow behind multiple casing pipe barriers and in locating leaks and their sources [3–5]. This paper describes two case histories for eight wells in the Western Canadian Sedimentary Basin (WCSB) in South Alberta region for two clients, where application of these techniques enabled gas leak source identification in a series of wells suffering from minute leak rates and also helped to discover some regional lateral flows and cross-flows.
Pipelines Making Safe, Offshore Treatment of Large Volume Fluids
Authors: Hastie Paddy 
Published: August 2015

Abstract
The UKCS is set to decommission over 3,000km of pipeline by 2023. As Operators submit their plans to regulatory bodies they face spiraling costs in order to make safe the industry's complex subsea infrastructure, estimated to represent 7% of the overall cost of field decommissioning. In order to overcome these challenges, the industry must evaluate how best to plan and execute projects in order to make a step change in decommissioning cost reduction.
Mission Command Project Management
Authors: Richardson Mark 
Published: August 2015

Abstract
This paper reviews existing project management delivery performance in the North Sea oil and gas industry and explores a successful alternative approach through Mission Command Project Management.
Poor project delivery has in recent years been a hallmark of the North Sea oil and gas industry. Studies show that the downward trend of project performance continues. Newspaper headlines signalling project delays and cost over-runs back up the statistics.
This failure to deliver projects in a timely and cost effective manner has had, and continues to have, a direct impact on investment and the opportunity to maximise reserves on the United Kingdom Continental Shelf (UKCS). Unless a new approach is employed then the continued trend towards; more centralised control, process driven systems and bureaucratic delivery models, in tandem with substandard project implementation will be a major contributor to the premature demise of the basin.
In the mid-80's the North Atlantic Treaty Organisation (NATO) was forced to re-think its strategy and adopted Mission Command as an approach. Its successful implementation revolutionised NATO's performance and this philosophy is now embedded in its modern warfare fighting competence. Mission Command has leadership and empowerment at its core and not the management of processes to drive projects to completion. The key principles of Mission Command are:
Unity of effort (across the organisation). Decentralisation (formal delegation/empowerment). Trust (mutual, deep and enduring). Timely and effective decision-making. Freedom (and speed) of action. Employment of initiative.
Mission Command is now gaining traction in the civilian project management community in concert with other concepts such as lean and agile project management, where its application has seen significant benefits. One North Sea Operator has now been employing Mission Command on all its projects over the last 4 years to great effect; out stripping its peers in terms of; safety, cost, schedule and quality of delivery. Mission Command Project Management is transformational in the art of project delivery and if more widely implemented could bring a renaissance to the North Sea. This paper highlights the failings of the present project management methodology, outlines the Mission Command approach and details its successful implementation by a North Sea Operator, thereby allowing others to employ this most efficient and effect delivery model.
Efficient Mitigation of Work Over Hazards – Do We Target the Actual Risks?
Authors: Morgan Rhodri , Nergaard Berg Kristin , Fredbo Maren 
Published: August 2015

Abstract
Typical workover operations involve the switching of subsea well barriers from permanent equipment to temporarily installed barrier systems. During workover activities additional operational hazards are introduced such as drive/drift off and compensator lockup which can have severe consequences including injury to personnel. To account for these operational hazards a workover system will have additional barriers. These barriers consist of instrumented and non-instrumented protective layers. The instrumented protective layers consist of safety instrumented systems (SIS).
The safety instrumented systems fitted to a workover system can vary. Most workover systems consist of three common safety instrumented functions (SIF); Process Shutdown (PSD), Emergency Shutdown (ESD) and Emergency Quick Disconnect (EQD). The non-instrumented protective layers are made up from mechanical barrier elements for example the weak links.
DNV GL on behalf of Statoil performed an analysis to better understand workover hazards and the barriers required to mitigate these. The aim of the work was to assess the effectiveness and suitability of the current safety barriers and to identify what additional functional requirements might be needed. This paper details the results of that work. A generic workover system formed the basis for the study. Hazards were defined through a hazard identification (HAZID) workshop and the effectiveness of the measures was evaluated through a Level of Protection Analysis (LOPA).
This paper documents the results of a study to establish whether the current barriers used during workover operations adequately mitigate the risks. Despite having dissimilar operational modes, it is often expected that the workover system barriers shall be suitable for all operational modes. The results of this study show that some of the barriers in workover operations are not as efficient as perceived, in particular the riser weak link designs and manually initiated EQD functions.
Development of a Safe and Fast Bite Locking Cam for Oil & Gas Applications
Authors: McGowan D. , Martinchich D. , Loose-Mitchell W. , Steen T. , RajeshKumar G. 
Published: August 2015

Abstract

Objectives/Scope
As subsea oil & gas drilling and production continues to progress into deeper waters the demand for fast, safe, efficient, reliable, and cost effective equipment will continue to grow. Cam locking devices provide an innovative method to meet these requirements in a variety of applications within the oil & gas industry such as, but not limited to, anti-rotation of casing, tubing and riser connectors, and for locking of valves, cylinders, BOP rams, and rigging equipment.

Methods, Procedures, Process
During the development phase of the bite style cam device Finite Element Analysis (FEA) was utilized to perform design optimization in conjunction with a unique design of experiments approach. The results of this study have been used to optimize the high order of design variables that define the geometry of a bite style cam locking device.

Results, Observations, Conclusions
A novel bite style cam device has been developed and applied to threaded connections that employs hardened teeth rather than friction, as in typical cam functions, to provide a locking load capacity. In contrast to solutions currently utilized for connector anti-rotation, the innovative cam design requires no special tooling, hammers, or dangerous explosives to install, making it much safer than solutions on the market today. Installation requires only the use of a simple hex wrench, significantly increasing rig efficiency and drastically reducing installation time, a vital criterion for equipment offshore. Novel/Additive Information: Overall, the bite style cam device has proven itself an ideal solution for subsea and offshore applications. Easy and quick installation and reduced loose parts provide improved value and performance.
MPD Technology Used to Deliver Challenging HPHT Drilling Campaign
Authors: Graham Robert , Geddes Martin , Harris Tim , Flaherty Dominic , Shuttleworth Nigel , McEwan Bruce , Nordin Noor , Cadd Michael , O'Grady John , French Pete , Sandell Richard , Jeffries Stuart 
Published: August 2015

Abstract
The Shearwater field is a deep, high-pressure, high-temperature (HPHT) reservoir located in the UK Central Graben of the North Sea. The current drilling campaign represents the first round of well re-entries into the field following a campaign of slot recoveries to facilitate sidetrack development opportunities.
A high level of reservoir depletion (&gt; 8000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to successfully exploit the remaining reserves.
Managed Pressure Drilling (MPD) Technology was pursued as an enabling technology to navigate within some very narrow margins in the first well of the redevelopment campaign. MPD was implemented in conjunction with drill-in liner and wellbore strengthening technologies to successfully deliver this first well and prove the techniques required to prolong field life.
To promote successful implementation of MPD in the target zone, the technology was employed in the previous hole section to gain experience with the equipment and procedures where pressure control was less critical.
MPD was used to control bottom hole pressure to manage background gas and facilitate changes to equivalent mud weight. It was further used to minimise the effects of loss/gain mechanisms and enable drilling through a tight margin between pore and fracture pressure while reducing the risk of borehole instability and losses. The technology was also used to determine appropriate mud weights for tripping and provide trip margin to avoid swabbing while tripping. In addition, MPD was used to facilitate cementing in tight margins.
This paper will highlight the multiple uses of MPD throughout the start-up of this current drilling campaign and key learnings enabling successful implementation of a new technology on the rig.
Thinking Out of the…Subsea Xmas Tree!
Authors: Razzouk Adnan 
Published: August 2015

Abstract
In the current climate of low oil prices and reduced revenue, Oil & Gas operators across the industry are being motivated to drive their costs down, which means –for many operators- a reduction in CAPEX and OPEX spend. Whilst operators are keen to reduce cost, maintaining production levels is required in order to remain profitable. Understandably, this has its own challenges, particularly when it comes to dealing with inspection, repair and maintenance (IRM).
This paper demonstrates a project example of how embracing the innovative thinking in dealing with common matters could help reduce IRM costs, whilst maintaining safe and steady operation. It is based on an ongoing project activity to proactively repair a subsea Xmas tree defect at the flowbase, the defect is located within the flowbase connector downstream the choke insert.
The paper explains the option select processes followed by the project team, and the innovative options that were assessed initially as opposed to the costly traditional option (that is simply replacing the Xmas Tree). The paper will briefly explain each of these options (6 in total), the technical challenges and the relative costs involved with each one of them.
The paper then explains in details the selected repair methodology which makes use of an innovative technology, used to direct the hydrocarbon out of the Xmas tree structure (from the choke insert location) to the existing flowline, thus permanently bypassing the flowbase and the defect in its entirety. It will demonstrate the opportunities exploited to improve system maintainability, operability and reduce future OPEX.
The paper will be an example of how innovative thinking is required in this current market condition, and how the use of existing and proven technologies- though in an innovative manner- and pushing the boundaries could help reduce CAPEX and OPEX for operators.
Cost Reducing Pipeline Decommissioning Technology
Authors: MacKenzie Hugh , Jones Callum 
Published: August 2015

Abstract
This paper is designed to present the challenges and obstacles faced in the use of a new technology for the plugging and de oiling of sections of unpiggable flowlines prior to decommissioning.
Conventional methods of decommissioning subsea pipeline infrastructure are inherently very expensive with the mobilization and operation of DSV (Dive Support Vessel), equipment and personnel.
In this case the only other viable option was to mobilise a DSV to hot tap the flowlines and circulate fluid from the platform before filling the line with cement. This operation would have incurred considerable expenditure so the operator sought a more cost effective solution.
The solution deployed utilised an ultra lightweight, minaturised coiled tubing system which was deployable from the platform lower decks with minimal laydown area required. The system had the ability to traverse multiple bends (360° total), de-oil the line and deliver an expandable cement to plug the pipeline in a single operation. This paper will outline this new approach and will identify how this new technology can positively impact project economics as well as environmental and safety implications. It will also highlight the engineering problems encountered and resolved during this project.
The innovative, unconventional approach to this project in the North Sea provides an alternative solution for operators to consider when planning pipeline decommissiong. The result of the operation will be outlined as well as the future of this new technology within the decommissioning sector.
Cost reduction is an important topic in the current economic climate and this paper will conclude that this technology provided a suitable solution to the operator and at a reduced cost when compared to conventional solutions. It will also demonstrate how collaboration between companies within the industry has paid dividends to all involved during this project in line with Oil & Gas UK Economic Report 2014.
Exploring Alternative Solutions to Maintenance and Fabrication When Hot Work is not Desirable or Permissible
Authors: Flanagan Kyle , Maillard Jérémie 
Published: August 2015

Abstract
This paper, produced for SPE Offshore Europe 2015, looks at the options available to the offshore fabric maintenance engineer when it is not possible or preferable to weld and discusses viable solutions using bonding or cold welding technologies. With the continuous corrosive attack of the environment, maintaining asset integrity offshore is a key challenge for operators looking to upgrade equipment or extend operation beyond the original design life. A crucial part of this process is ensuring the asset complies with all safety regulations, often requiring repair of the existing structure and new equipment installations. When carrying out such work, alternatives to welding or hot work offer significant advantages to the operator, for example, from a cost and scheduling perspective and for this reason cold bonding using advanced composite adhesives can often be considered.
The paper aims to provide relevant information and data for reference by detailing case histories, from the initial design stage to installation and on-going inspection. Examples include safety critical equipment, such as handrails and accommodation modules as well as structural reinforcement to roofing and decks. In addition to the design of the bonded structures and joints, the paper also details other aspects to consider such as ongoing inspection and fire safety. By presenting appropriate test data demonstrating performance criteria the paper will explore the capabilities of modern composites to offer a variety of solutions for cold welding equipment. With the inclusion of case histories and physical test data, the paper endeavours to provide advice and guidance on the best practise when designing and installing equipment using composite technologies.