bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using RESQML for Shared Earth Model Data Exchanges between Commercial Modelling Applications and In-House Developments, Demonstrated on Actual Subsurface Data
Authors: Morandini Francis , Michel Bruno , Verney Philippe , Rainaud Jean-Francois , Deny Laurent , Dulac Jean-Claude , Fitzpatrick Tony , Eastick Rob , Towery Lisa 
Published: September 2011

Abstract
After intense collaboration among operators, service companies, and software vendors (all members of an Energistics Special Interest Group (SIG)) Version 1.0 of the RESQML data exchange standard has been released. Prototypes implemented by both vendors and operators have been tested and have proved the efficiency of the concepts.
RESQML has been designed to support: Interaction with real-time production and drilling domains;Transfer of giga-cell reservoir simulation models, which are currently in use in some areas of the world, and with static reservoir models, which may be significantly larger;Loss-less data transfer for complex grids, especially for non-standard connectivity;Retention of the geologic and geophysical meta-data associated with 3D grids;Data exchange for flexible and iterative multi-vendor subsurface workflowsacross geology, geophysics and engineering.
A demonstration will illustrate how different components of a shared earth model can be exchanged between major commercial applications. Additionally, based on the Alwyn North Field dataset, a typical validation loop involving operator in-house and vendor applications will be demonstrated. The objective is to transfer in-house interpretation results (e.g., horizons and faults) as RESQML features to diverse structural, stratigraphic, and reservoir vendor applications, then re-import the RESQML features (modelled horizon and faults, reservoir grid geometry) obtained by these applications into the in-house application to ensure, at each step, an overall consistency with the original interpretation.
Development of Heavy Oil Offshore Lake Maracaibo Field Using Slug Gas Lift: A Case History
Authors: Ortiz-Volcan Jose Luis 
Published: September 2011

Abstract
During the 80's a novel artificial lift method called slug gas lift was developed in-house in Lagoven (former affiliate of PDVSA), by a group of production engineers and it was applied to develop the first commercial phase of Urdaneta Offshore Lake Maracaibo Field between 1982 to 1984 that reached up to 50000 barrels per day with an average production per vertical well of 350 barrels per day of a 12°API heavy oil from depths between 6000 to 7000 feet.
Continuous gas lifting when applied to high productivity heavy oil reservoirs generate production problems caused by foam formation. Intermittent gas lifting on the other hand presents limitations for reservoirs such as Urdaneta-01 because a high productivity reservoir is capable of filling the production tubing with fluids and requires lifting from depths below 7000 feet. Slug gas lift was developed as alternative to continuous and intermittent gas lifting to deal with heavy oil reservoirs such as Urdaneta 01. This reservoir was discovered in 1946 and commercial exploitation started in 1982. Petroleum initially in place was estimated in 12 billion barrels with initial reservoir pressure of 3500 Psig and average depth of 8000 feet.
By applying slug gas lift the operator (Lagoven) was able to minimize foam formation by limiting the dynamic contact of gas and heavy oil liquid phases. The slug gas lift system is designed to prevent admission of liquids while gas is being injected at high pressure into the tubing, so condition for foam formation is eliminated.
Up until now there has not been any publication in SPE about this experience. The author was part of the production engineering group in charge of the Urdaneta field development project in 1982 and he also participated in the development and application of the slug gas lift model, This paper reviews the basis of slug gas lift, range of application and how it was applied in Urdaneta Field using the results from the first year of evaluation of a group of wells that constituted the first field pilot test.
It is likely that some heavy oil reservoirs located offshore worldwide could be potential candidates for application of slug gas lift.
i-field™ Programs Enable Operational Excellence in a Challenging Environment; Pushing the Limits of Large Data Transfer for Real Time Monitoring and Surveillance Operations in San Joaquin Valley
Authors: Popa Andrei , Barrett Mark , Cassidy Steve 
Published: September 2011

Abstract
Chevron's San Joaquin Valley (SJV) Business Unit (BU) is a mature, heavy oil, thermally enhanced asset consisting of large fields that have been producing for over a century. To ensure continuing technology transformation, in 2003 San Joaquin Valley started its own i-field program being among the first BUs to pursue Chevron's enterprise-wide effort in building the Digital Oil Field of the Future. From its initiation, the program has been focusing on creating solutions to manage and optimize operations and enhance recovery.
The paper showcases one of the most technologically advanced i-field heavy oil solutions implemented in San Joaquin Valley thermal assets, involving a high accuracy tiltmeter program implemented by a partner service company to advance the understanding of diatomite operations and monitor the surface ground movement
In 2008, Chevron's SJV i-field team partnered with its Information Technology (IT) department to develop a state-of-the-art application called Integrated Diatomite Operations Tool (i-DOT). The product incorporated current field workflows for mapping the grid deformation with business data (well locations and status, steam volumes and dates, etc.) in relevant time. This was accomplished by establishing a live connection between Chevron and partner service company servers whereby terabytes of grid data would flow seamlessly into Chevron's SJV servers. Data acquisition, data processing and storage efforts were accomplished through an integrated effort between IT, GIS and PetroWeb development teams. Workflows were built through close collaboration between i-field engineers, petroleum engineers, earth ecientists, IT professionals and the operations group.
The i-DOT solution has become the single point of operation monitoring and activity scheduling for multiple groups such as Operations, Asset Development and the Drilling team. The benefits of implementing i-DOT solutions are significant and transformed our decision making process in diatomite fields. The paper includes not only value creation but also lessons learned during development, deployment and end-user acceptance.
Implementing i-field™ Integrated Solutions for Reservoir Management: San Joaquin Valley Case Study
Authors: Popa Andrei , Horner Katie , Cassidy Steve , Opsal Steve 
Published: September 2011

Abstract
To achieve more efficient business processes by exploiting data and knowledge management, real-time systems and advanced analytical tools, most major integrated and service companies have developed, or are in the process of developing, intelligent programs also known as Digital Oil Field of the Future3. The i-field™ program represents Chevron's efforts to integrate people, processes, technology and information to achieve its vision of Upstream Transformation. Ultimately, this vision translates to higher-quality decision making and changes the way we operate our assets.
A new multiyear i-field™ program, Integrated Reservoir Management (i-RM), was initiated in the San Joaquin Valley to enable efficient reservoir management (RM) and quality decision making for heavy oil assests operating under steamflood EOR technologies.
The paper describes the journey undertaken by the project team to build a proprietary steamflood integrated reservoir management tool that answers the basic neverending engineering requirements: instant access to clean data, single source of information for everyone and seamless data-tools linkage. The ultimate benefit is not only increased time spent by engineers and earth scientists to analyze data but also consistent project design workflows and decision making processes across fields. In addition to above documented benefits, the manuscript includes operator's experience with project framing, development, deployment and user-acceptance.
Taking Vital Signs of Remote Monitoring Systems
Authors: Mikulis M. , Meldrum E. 
Published: September 2011

Abstract
An operator recently completed more than 20 intelligent well systems, with extensive permanent in-well monitoring throughout. As part of this program, a new capability is being included to monitor and provide early warning regarding the health of the data collection system. The objective of the health monitoring system is to give greater insight into the quality of the data being collected. By analogy, instead of getting a pulse from the system, the operator receives actual diagnostics about any urgent issues. The tool's dashboard displays a visual indication of the integrity and quality of all the down-hole equipment data being recorded in the historian and allows a technician to quickly drill down to the source of the anomaly.
The system provides the following benefits: Early detection of impending equipment failuresTechnical support staff are warned about alarming events and trendsTechnical support staff are provided a tool to quickly analyze equipment performance by summarizing the current status and recent quality of acquired dataFaster response by technical resources to events, and quicker resolution of down-hole equipment problemsEasy detection of misconfigured tags in the OSISoft PI historian that could mitigate future data management issues or missing critical dataPrevents periods when no data is recorded; the event alarms immediately notify the person responsible rather than relying on periodic system checks, e.g., once a month
Will Performance Based Safety Processes Prevent Future Oil Spill Disasters?
Authors: Miller Chuck 
Published: September 2011

Abstract
Now that the authorities have taken the infamous Deepwater Horizon BOP to the surface for inspection, the post mortem debate on the causes of the largest accidental marine oil spill in the history of the petroleum industry has begun. While a wide variety of experts are considering next steps to prevent this type of breakdown in the future, safety and reliability engineers are debating the basic premise; "Was the root cause of the Macondo incident a procedural problem or was this simply a series of failures that could not have been imagined prior to the incident?
Analysis revealed that the BOP "operated as designed" however some reports suggest that the incident may have avoided by considering the following:
What could have been done to predict this event? Would the employment of HAZOP principles have identified the potential failure? Was the Deepwater Horizon BOP properly sized, installed and tested? Would continuous on-line diagnostic testing of the BOP revealed a faulted state? Would the use of a performance based design specification provide a better safeguard design than the prescriptive API 16D?
Evaluation of Orientated Perforating in the Buzzard Field
Authors: Mobasheri Mohammad , Durham Craig , White Martin 
Published: September 2011

Abstract
Orientated perforating is used to orientate the perforation tunnel parallel to the highest in-situ stress plane in order to reduce and/or delay sand failure. The technique is most effective in high angle and horizontal wells, so early Buzzard wells were perforated with conventional 60° phasing. Orientated perforating was subsequently adopted on Buzzard after log derived sand strengths were generally weaker than prognosed. The following paper presents the results of a review of six months sand production data from 21 production wells, in an attempt to correlate sand production with perforation orientation.
Due to inherent inaccuracy in allocating sand production to individual wells, wells were categorized as high, medium or low sand producers and various parameters such as hole inclination, azimuth, and UCS rock strength were considered to establish correlations between perforation orientation and sand production, all of which were inconclusive other than a slight correlation showing increasing sand potential with hole inclination. As all wells are sub-horizontal and the sand strength is marginal for a passive sand control techniques, it is concluded that orientated perforation does not give any measurable reduction in sand production from Buzzard wells.
The effect of perforation orientation on liner erosion was reviewed using Computational Fluid Dynamic models of a nominal 100ft 5.1/2" liner section. This showed no significant difference between 10–350° and 60° phasing perforation, instead wellbore inclination, flow rate and sand particle size increase the potential erosion rate in some wells.
Forties Infill Drilling Eight Years on; Continued Success Through the Application of Thorough Development Geoscience Driven by 4D Seismic
Authors: Rose Philip , Barker Gregg , Koster Klaas , Pyle Jeff 
Published: September 2011

Abstract
In the eight years since Apache purchased the Forties Field from BP over 100 infield targets have been drilled with an overall success rate of 74%. As a result of this infill drilling campaign the field production rate has been held at a plateau rate of 60,000 bopd despite an average rate of 41,000 bopd in 2003, the year of purchase from BP. Indeed the success of this campaign has resulted in a shortage of sidetrack donor wells so there has been a return to surface drilling on all five platforms. Furthermore, to enable the full exploitation of the forward target portfolio Apache is installing a new 18 slot platform, the Forties Alpha Satellite Platform (FASP) in 2012.
Key to Apache's success on Forties has been a constant drive to push the boundaries of 4D seismic interpretation and lithology prediction from seismic and the ability to integrate this information with local production and well data. In this paper case histories are presented to illustrate our approach to target generation and the evolution of target generation over time is evaluated.
The above methodology has led to many convincing successes over the years. The acquisition of a new 4D seismic volume in 2010 has resulted in a significant boost to our drilling results, allowing us to have our most productive drilling 6 months to date, including one well with an initial production rate of 12,000 bopd, the highest initial rate recorded in the field since 1992.
Innovative Mono-Column Support Structure
Authors: MacLeod Donald , Mathie Tom , Dunlop Graham , Duvall Sean 
Published: September 2011

Abstract
To facilitate a new compression package on an already crowded offshore platform, a new 2,000 tonne module is to be installed on top of a unique mono-column support. Equivalent to the height of the London Eye, the 140 metre high, 4.5 metre diameter mono-column sits in 136 metres of water, a depth much great than any similar structure. Although a simple structure, this is the first of its kind in the North Sea and possibly unique worldwide.
The new mono-column is supported directly on the existing jacket pile at the sea bed and uses the platform's existing redundant pile capacity to economically extend the space available for the new compression facilities. A simple spigot interface between the mono-column and existing pile also negates the need for grouting, temporary fixings and any subsea intervention. Traditional approaches to increasing real estate on offshore platforms involve the installation of cantilevers or shoe horning equipment into inefficient spaces leading to extensive offshore hours and lengthy shutdowns. The critical design consideration for this structure is its ability to survive a ship impact scenario. To address this, the structure adopts technology developed for the transport of nuclear materials. Energy absorbing technology and analysis expertise have been utilised to create a ‘crumple zone’ to protect the new structure.
Due to its simplicity, this innovative concept has resulted in considerable commercial benefits which include:
Reduced shutdown duration. A conventional approach would require around a 3 week shutdown. At approximately £2 million per day deferred/lost revenue, this is a saving of £42 million for a major offshore production platform. Eliminated Flotel requirements. Conventional approaches would require approximately 60 days of Flotel hire at a total cost of £12 million. Against a mono-column installed cost of £8 million, a saving of £46 million has been achieved.
A Low Tech, Low Risk System for the Installation of Large Structures in Deep Water
Authors: Joensen Arnbjorn , Paul David 
Published: September 2011

Abstract
The paper describes a novel system for the transportation and installation of subsea structures without the need for an HLV. The method is applicable to structures weighing from a hundred tonnes to several thousand tonnes in water depths of 100m -3000m and is particularly well suited to hostile environments. It enables even the smallest crane vessels to install large structures and increases the development options for marginal fields in remote locations.
The structure is fully submerged throughout the tow and installation phases and consequently the surface weather conditions have little impact on the tow or lowering operations. The reduced weather sensitivity increases the operating window for hostile regions, offering greater schedule flexibility.
All the individual aspects of the system are derived from very basic principles, existing technology and low cost components but the combination has resulted in a potential "game changer" for the development, installation and decommissioning of subsea structures.
Practical Surveillance Analysis on Thermal Heavy Oil Projects: Integrating Seismic Data with Production Case Studies
Authors: Baker Richard , Sandhu Kerry , Lifshits Gary 
Published: September 2011

Abstract
Enhanced oil recovery methods for heavy oil are growing at a fast pace. In Canada alone, approximately 53% of the nation's crude oil production (~2.8 MMBbl/day) comes from Alberta's Oil Sands. Remote sensing and monitoring technologies developed for thermal methods are providing the industry with an immense amount of data that will aid in the improvement and optimization of production performance. This paper details how to integrate seismic, tiltmeter, temperature observation well data with field production data, first with simple surveillance techniques, then with flow simulation.
Currently, heavy oil is experiencing significant growth in reserves whereas conventional light oil reserves are essentially fully tapped and are diminishing: heavy oil is becoming key to meeting growing energy demands worldwide. Current analytical approaches to heavy oil reservoir studies are too general, and tend to not include rich surveillance data such as seismic, temperature and pressure. This general approach over-simplifies the dynamics present in these reservoirs and does not give an accurate depiction of behavior and performance estimation. On the other hand large simulation studies can be cumbersome and not adaptive to new surveillance data. This paper focuses on a hybrid approach to analyzing various heavy oil fields in Canada, and outlines newly developed surveillance methods which better characterize heavy oil reservoirs. These field cases include geological data, pressure readings, seismic analysis, temperature observations, and historical production, all of which are used to enable the optimization of field production.
The proposed analytical techniques allow for a more precise estimate of recovery and sweep efficiency so that an efficient optimization strategy can be developed. Applying these analytical techniques to the Surmont and Christina Lake projects in the Athabasca area has given particularly important insight into SAGD steam chamber development and has shown to accurately estimate steam chamber volume and shape.
KP4: Ageing & Life Extension Inspection Programme - The First Year
Authors: Stacey Alexander 
Published: September 2011

Abstract
With a significant proportion of the UK's offshore infrastructure having exceeded the original design life, the ageing population of offshore installations presents a constant and growing challenge to safety. Ageing is characterised by deterioration which, in the severe operational environment offshore, can have serious consequences for asset integrity if not managed properly.
The Health and Safety Executive's Ageing and Life Extension Inspection Programme, also known as Key Programme 4 (KP4), was launched in July 2010 to the UK offshore industry. The purpose of KP4 is to:
determine whether the risks to asset integrity associated with ageing and life extension are being controlled effectively; raise awareness of the need for specific consideration of ageing issues as a distinct activity within the asset integrity management process and of the need for senior management to demonstrate leadership on this matter; identify shortcomings in duty holder practices in the management of ageing and life extension and enforce an appropriate programme of remedial action; work with the offshore industry to develop a ‘best practice’ common approach to the management of ageing installations and life extension.
The first year of KP4 entailed a programme of eight duty holder onshore and offshore inspections, covering a wide spectrum of topic areas, including organisational factors, structural integrity, materials (including corrosion), maritime integrity, mechanical integrity, process plant integrity, fire and explosion integrity, electrical and control systems integrity, wells and offshore pipelines. This paper presents a general overview of KP4 and a summary of progress made and initial findings in the first year of KP4.
Deployment of the Reelwell Drilling Method in a Shale Gas Field in Canada
Authors: Belarde Miguel , Vestavik Ola 
Published: September 2011

Abstract
The Reelwell Drilling Method (RDM) is a multi-purpose system incorporating a unique flow arrangement. It employs conventional drillpipe into which is fitted an inner string to form a concentric drill string. This arrangement allows the return fluid containing drill cuttings from the bottom of the well to be transported back through the inside of the drill string. The technique enables improved hole cleaning and improved downhole pressure control, and has unique features for application to managed pressure and extended reach drilling operations.
Development of the RDM started in 2004 and has since then been through several full scale tests. In the fall of 2010 it was deployed in a shale gas well in Canada. The main goal was to demonstrate the system in a live gas well and to gain field experience of the technology. The system was used in both the vertical and horizontal sections of the well. The concentric drill string was used for drilling the whole well in several bit runs, with circulation in both conventional and concentric circulation modes. The well was drilled to 4250 m MD in 8¾" hole size. The operation validated the concept and demonstrated a practical implementation on conventional drilling rigs. The operation is an important step in the evolution of a technology, which has a significant potential to improve operational efficiency and thereby the recovery of petroleum resources.