bluuebunny/crossref_metadata_2025 huggingface dataset:
Latest Developments in Acoustic Subsea Control and Monitoring for the Drilling Industry
Authors: MacDonald L..
Published: September 2011

This presentation will review the case for secure, high reliability acoustic signalling through water, with applicability to communication, monitoring and control requirements. Illustrations will be drawn from NASBOP to provide an example of critical data being transmitted and received acoustically in the deepwater Oil and Gas arena today.

Advances in Digital Acoustic Technology and the specific inception of spread spectrum communication technology have resulted in high integrity, high reliability transmission and reception of critical command and control data from Subsea BOP to surface vessels. These systems have unique ability to operate reliably in deep water, high multipath environments with greater than 99% reliability.

The foundation of Nautronix signalling is ADS2 (Acoustic Digital Spread Spectrum) technology. Proven ADS2 technology allows high integrity data transmission and excellent immunity to interference. Its long range capability (in excess of 5km dependent on environmental conditions) as well as reduced battery consumption, makes this technology the ideal solution as primary or secondary data management and communication. Ultimately, this technology will provide options for a wide range of life of field applications in the future.

NASeBOP, using ADS2 technology, provides the solution from a subsea control perspective without the traditional umbilical to remotely monitor other subsea equipment and retrieve data such as pressure/temperature wirelessly. NASeBOP provides 16 critical functions with feedback for the Subsea Isolation Device and allows for read-back of 8 analogue sensors to monitor critical subsea pressure and temperature readings. The system also allows the ability to activate an Emergency Disconnect Sequence (EDS) and to monitor the BOP status after disconnect.

The next evolution of BOP control is NASMUX; using 128 channels to fully control and monitor the BOP with acoustics. This technology will revolutionise BOP operations by addressing many of the current issues by providing a reduction of umbilical's and reels, elimination of downtime caused by umbilical damage and increased safety by reduction of moon-pool activity in handling of umbilical's. The system would provide full BOP functionality in the event of umbilical failure, in order to allow the operator to safely shut in a well before recovery for umbilical repair.
Planning the Combined Revitalization of Two Carbonate Reservoirs in The Campos Basin
Authors: Pires P.. , Furuie R.. , Sarturi J.. , Benac P.. , Pereira J..
Published: September 2011

This paper presents the revitalization plan of two long producing fields located in the Campos Basin, offshore Brazil. Both produce from high OOIP, complex albian carbonate reservoirs. The fields started producing in the early 1980's and their exploitation strategies were mainly based on vertical and deviated wells. No secondary recovery process was initially adopted. Both reservoirs exhibit low average permeabilities (less than 10 millidarcies) and high heterogeneity. In Albian-B, vertical heterogeneity has led to uneven reservoir depletion. From the drilling of recent wells, stratigraphic layers with better properties have been found to be severely depleted. Albian-E exhibits remarkable areal contrasts. The northern part of the reservoir is extremely tight while the southern is naturally fractured.

Currently, the production performance of both reservoirs creates the opportunity of increasing their ultimate recovery factor. In 2009, a pilot project aimed at appraising water injection toke place. The project scope was defined by a pair producer-injector, both horizontal multi-fractured. Through the monitoring of the two wells the displacement efficiency has being characterized in Albian-B reservoir. This information has guided the revitalization plan of the reservoirs. New drainage strategies were defined with help of assisted optimization. The studies pointed out attractive revitalization scenarios with a new platform to produce both reservoirs.
An Innovative Approach for Laboratory Evaluation of Defoamers for Oilfield Cementing Applications
Authors: Mahmoudkhani A.. , Bava L.. , Wilson B..
Published: September 2011

Defoamers and antifoams are crucial components in many processes of the oil and gas industry. In particular, they play a vital role in well cementing where many additives would otherwise contribute to foam formation and air entrapment during the mixing of the cement slurry. If not controlled, foam can cause serious problems such as pump cavitation, undesired slurry densities, inadequate mixing and gas permeability issues. Quest for high performance defoaming agents has been intensified in recent years due to the challenging industry standards and new environmental regulations such as those for offshore drilling and completion operations. The major task is to find suitable additives that pose little to no risk to the environment without compromising the performance and system integrity.

Quantification of defoaming performance is critical to achieve success in cementing operations as well as in the development of new and environmentally friendly defoamers. Most commonly, defoamers for cementing operations are appraised by non-standard or traditional test methods such as blender and sparge tests. While these methods are simple to perform, they often show poor reproducibility, lack of objectivity, and do not accurately replicate field conditions. This paper presents a unique test method using a dynamic foam analyzer which is capable of characterizing defoamer performance based on fluid density during simulated mixing operations. The dynamic foam analyzer generates objective data that shows initial and persistent defoamer effectiveness. This enables more accurate dosage comparisons in the lab resulting in more controllable operations in the field.

In addition, non-silicone based defoamers are desirable due to increasingly strict environmental regulations. The current challenge is to develop green alternatives while maintaining or improving the current performance levels of the defoamers used. This paper presents an innovative approach for evaluations of cement defoamers using a unique laboratory setup and a modified blender foam test method that provide more insights into cement foaming and defoaming processes. A mechanism is proposed for action of common cement additives as foam stabilizing agents. Performance of a green non-silicone based cement defoamer was evlauted to elucidate viability of the dynamic foam analyzer in comparison to the new blender foam test method.
Holistic Workflow for Autonomous History Matching using Intelligent Agents: A Conceptual Approach
Authors: Zangl G. , Al-Kinani A. , Stundner M.
Published: September 2011

The current practices of assisted and automated history matching refer only to specific methods to address the optimization problem in history matching, but never span over the complete workflow. Computational power and the development of sophisticated software should allow us today to capture the whole workflow and automate it rather than just a piece of it (usually the regression method). The approach presented in this paper is based on the principle of domain decomposition. The reservoir history matching (HM) problem is decomposed into smaller and smaller pieces (from reservoir to region, from region to layer) to allow a refinement of the final result and hence the HM quality. The decomposition of the problem can be commenced by introducing time dependent well influence areas. These areas are sub-divisions of previous decomposition processes, as there are lithofacies types, clusters, flow units and vintage intervals. For the time dependent "influence areas", the success of the optimization can be tracked over the sequential iterations as well as across the different realizations. The progress of the most sensitive parameters can be tracked and successful strategies can be applied to other, similar areas of each realization. Finally, the interference of the influence areas has to be accounted for in the selection of the parameter values in each of the regression loops. A smart expert system that includes machine-learning techniques (cognitive agents) is used to drive the global history matching process, control the sub-domains and find the best parameter combination amongst all influence areas. The approach presented in this paper allows an automated history matching process, which is scalable for very large reservoir models. Relying on smart run selection and cluster technology even large models (many hundreds to thousands of wells) can be successfully matched in a reasonable amount of time. As the system is reservoir independent and learning from human experts, less and less user input is necessary over time leading to an autonomous history-matching agent.
Cross-Industry Innovations in Artificial Intelligence
Authors: Piovesan C. , Kozman J.
Published: September 2011

Artificial intelligence (AI) has been applied in various digital oilfield applications, but primarily for subsurface analysis in areas such as artificial lift optimization or production process integration (Sandoval et. al., 2010). While oil and gas continues to be one of the primary producers and consumers of digital data (Heggelund, 2009), other similarly data and operationally intense industries use advanced predictive analytic technologies that could be applied across industries to reduce downtime on offshore platforms. Such proven capabilities are now being applied to data from rotating and reciprocating equipment on the topsides of offshore assets to develop predictive models that can be used to prompt preemptive actions before a critical and economically expensive downtime event.
Gulf of Thailand Information Super Highway, A Business Case on the Foundation of Integrated Operations
Authors: Senivongse Chulatep , Lecksiwilai Naruepon , Kiatrabile Thitiya , Mehrabian AJ
Published: September 2011

Today's offshore oil & gas production environment must maximize recovery for the on-going and future projects to be economically viable. Newly discovered reservoirs must be designed to address issues such as HSE, greater water depths, and other well related gradients.

To undertake the above, in 2010, PTT Exploration & Production Plc., PTTEP, a Thai National Oil & Gas E&P Company, had endorsed the service contract of having Submarine Fiber Optic cable to interconnect its offshore main operating complexes. This initiative is seen as the initial breakthrough in order to step closer to the PTTEP Integrated Operations program, PINTO. It's a foundation of the Digital Oil Field maturity model that could transform the whole operating processes and concepts for PTTEP.

This case study reviews the business case for the Submarine Fiber Optic Cable initiative, and how it was utilized to get support of PTTEP management to realize the benefits and transform of the "Business As Usual" for PTTEP aligned with long term corporate vision.
Assessment of Yet-To-Find Oil in the Brazilian Pre-Salt Region
Authors: Jones Cleveland M. , Chaves Hernani Aquini
Published: September 2011

The Brazilian Pre-Salt region has garnered much attention since the first major discoveries were announced by Petrobras, in 2006. Since then, discoveries in the region have ranked among the largest in the world in the last ten years, including Lula (former Tupi), Iara, and Libra. This led to various estimates, from within and outside the government, that mentioned extremely large total possible accumulations, ranging from 50 to over 300 billion barrels of recoverable oil in the "Picanha Azul" region, an area of approximately 150 thousand square kilometers. Since none of these estimates was accompanied by technical data, or a description of the methodology used, an assessment of the potential for yet-to-find oil was carried out using a software tool which models the exploration process, making Monte Carlo simulations based on the information available regarding wells drilled, discoveries made, respective dates, and the areas involved. The assessment methodology used has been successfully applied by the authors in evaluating the potential of other areas, such as the shallow waters of the Campos Basin. While the present Pre-Salt region assessment does not have as many information points available as in those prior assessments, the intense exploration activity has resulted in enough information being available about the region so as to be able conduct an assessment over the entire area. Applying the concepts of discovery sequence and field size distribution, and making geological estimates for parameters of the number and size of accumulations, the current assessment furnished a probability distribution for the number and expected size of individual accumulations (fields) yet to be discovered, as well as for the total accumulation of yet-to-find recoverable oil in the region. The relatively large range of possible values of the results reflects the lack of more exploratory experience (discoveries or dry wells), which will only come about with time, despite the intense exploratory efforts currently under way. Even so, it was possible to suggest that within probabilistic confidence levels of 95% and 5%, field sizes expected will range from 165 million barrels to eight billion barrels, and total accumulations will range from 115 billion barrels to over 288 billion barrels.
Virtual Metering System Application in the Ceiba Field, Offshore Equatorial Guinea
Authors: Petukov Anton , Saputelli Luigi , Hermann Jeffrey , Traxler Alex , Boles Kim , Nnaji Obiageli , Vrielynck Bruno , Venugopal Deepak
Published: September 2011

Well rate surveillance is essential for reservoir characterization and selecting potential activities to enhance and optimize production. However, such variables usually lack consistent or direct field measurements, which is related to technology availability, equipment reliability, and cost control. As a result, many technologies have been developed to estimate well rates from indirect measurements (e.g., virtual metering or soft sensors).

The well rate estimation requires consistent pressure-volume-temperature (PVT) data, fit-for-purpose production well tests, and reliable sensors. In most cases, field data are used to ‘tune’ data-driven models. Missing, biased, or failing sensors may break the rate estimation, and a new calibration would be required. In addition, sensor input uncertainty and rate estimation confidence were commonly overlooked in previous approaches.

This paper discusses the implementation of a data validation and reconciliation pilot study in the Ceiba Field to estimate well rates. In this case, data, uncertainty, and models are combined to minimize a global error function. Rigorous statistics are used to calculate new sensor estimates. Unlike previous well rate estimation approaches, field-collected data are validated and corrected using physical models.

The pilot technical scope included calculating oil, water, and gas rates for each well; calculating the tolerance of rate measurements and gauge readings; and identifying sources of unreliable measurements. Although the approach is not new in the petrochemical industry, the application is ‘young’ in the upstream.

Project benefits included less downtime due to well testing and early problem detection, 65% less time expended on validating well tests and allocating individual well rates, and improved cost control due to calculating well-produced volumes hourly. These findings provide a better understanding of reservoir and well performance, which facilitates production optimization management. This paper presents a summary of current project status, the lessons learned during pilot implementation, and the procedure for further progression.

Project success criteria, application key performance indicators (KPIs), and expected benefits are reviewed and analyzed. As far as they can be evaluated at this stage, they were all achieved successfully.
Data Mining For Safety
Authors: Tuzin Bill
Published: September 2011

"There are a million ways to lose a work day, but not even a single way to get one back."~Tom DeMarco and Timothy Lister

The old saying "What gets measured gets done" has been put into use to reduce the hazards of the workplace. Virtually every company involved in the exploration and refinement of hydrocarbons has installed procedures and systems to measure workplace hazards and incidents. Monitoring incidents and hazards and performing timely analysis leads to effective remediation efforts. Many of these hazard identification systems and procedures are ineffective because they may be paper based, may be cumbersome for part-time computer users, and are often unavailable at the job site. In addition, event and hazard detail records are often difficult to comprehend, fail to fit into neat categories, and rely heavily on the personal skills of individuals assigned to review these records. All of these conditions impede the value and quality of information entered into the system, resulting in additional challenges to maintaining a safe workplace. Every impediment to the full use of the systems increases the risk that events and hazards will go unidentified and un-remediated.

This paper identifies new technologies that have been implemented in other industries that could improve the performance and outcomes of safety systems used in the energy industry. The principle benefit is the ability to overcome the many obstacles that prevent identification and reduction of risk. By enabling easier data collection from virtually anywhere, with assurances that automated processes will consistently and correctly interpret the data collected, the outcome will be a process of prompt and accurate risk mitigation.
Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales
Authors: Miller Camron , Waters George , Rylander Erik
Published: September 2011

Production logs from more than 100 horizontal shale wells in multiple basins have been acquired and interpreted. An evaluation of this data set confirms that production is highly variable along the length of the wellbores. In some basins, two-thirds of gas production is coming from only one third of the perforation clusters. Furthermore, when looking at all basins, almost one third of all perforation clusters are not contributing to production. This highlights a significant opportunity to improve overall completion effectiveness and economics in these high profile projects.

Observations of near-wellbore reservoir quality and completion efficiency can be attained from the analysis of this data. Rock properties such as mineralogy, natural fracture density, and closure stress in the near wellbore region impact reservoir quality and hydraulic fracture conductivity. Completion parameters such as the staging of stimulation treatments, the number of perforation clusters per frac stage, and perforation cluster spacing can all impact the productivity of an individual perforation cluster. Correlations between productivity and key geologic, petrophysical and completion parameters can be made. The result is a better understanding of the parameters that are controlling completion effectiveness, and corresponding productivity in horizontal organic shale wells.
Numerical Simulation of Shale-Gas Production: from Pore-Scale Modeling of Slip-Flow, Knudsen Diffusion, and Langmuir Desorption to Reservoir Modeling of Compressible Fluid
Authors: Shabro V. , Torres-Verdin C. , Javadpour F.
Published: September 2011

We combine a new pore-scale model with a reservoir simulation algorithm to predict gas production in gas-bearing shales. It includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. The pore-scale model quantifies macroscopic petrophysical properties of formations using an algorithm of gas transport in porous media that simultaneously considers the effects of no-slip and slip flow, Knudsen diffusion, and Langmuir desorption. Subsequently, the reservoir model populates petrophysical properties derived from the pore-scale analysis at every numerical grid and at each time-step to calculate the production history and pressure distribution in the reservoir. This approach examines the contribution of different transport processes (i.e. advective flow, Knudsen diffusion, and desorption) to quantify their corresponding contributions to overall flow. Previously, we showed that slip flow and Knudsen diffusion play a significant role in explaining the higher-than-expected permeability observed in shale-gas formations with pore-throat sizes in the range of nanometers. It is shown that Langmuir desorption from organic-matter surfaces is important in the calculation of stored gas in gas-bearing shales. Modeling results show that gas desorption maintains the reservoir pressure via the supply of gas. In comparison to conventional reservoir descriptions, the contributions of slip flow and Knudsen diffusion increase the apparent permeability of the reservoir while gas production takes place. The effects of both mechanisms explain the higher-than-expected gas production rates commonly observed in these formations.
Transmission and Scanning Electron Microscopy Investigation of Pore Connectivity of Gas Shales on the Nanoscale
Authors: Curtis Mark E. , Ambrose Ray J. , Sondergeld Carl H. , Rai Chandra S.
Published: September 2011

Shale reservoirs represent a significant and increasing portion of natural gas production within North America. In order to better understand gas deliverability of these reservoirs, the flow paths and their connectivity within shales need to be understood at a fundamental level. The pores within gas shales are on the nanoscale and below optical resolution. This necessitates methods such as electron microscopy to image them. Recently, the introduction of Focused Ion Beam/Scanning Electron Microscopy (FIB/SEM) technology to the petroleum industry has enabled the imaging of these nanoscale pore structures in three dimensions (3D) for the first time. Imaging of 125 μm3 shale volumes has been performed on different gas shales and the pore systems within these volumes have been reconstructed. Throughout our investigations it has been difficult to obtain pore connectivity across the reconstructed shale volumes. High pressure mercury injection capillary pressure (MICP) measurements on gas shales suggest that the connections between many of these pores are less than 2 nm. Because the size of the smallest pores and pore throats detected within gas shales approaches the resolution limits of SEM, higher resolution techniques must be employed.

Transmission electron microscopy (TEM) can image the internal structure of thin shales specimens and enables much higher resolution imaging than SEM. Utilizing this imaging technique in conjunction with other methods we discuss our investigations of pores and their connections that are below the SEM imaging resolution used in previous studies. Initial imaging suggests that isolated pores previously imaged with the SEM exhibit connectivity. It is the connections of pore spaces that control the gas flow in shales and such insights will have far reaching implications in better understanding this flow.
Drilling Performance Improvements in Gas Shale Plays using a Novel Drilling Agitator Device
Authors: Barton Steve , Baez Franklin , Alali Aref
Published: September 2011

High friction of the drill string against the wellbore has become a concern in the process of drilling, irrespective of whether it is a vertical, directional or horizontal application. This source of additional torque and drag will lead to low rates of penetration, poor tool face control, short runs, severe drill string and bit wear, and at the same time, could cause problems while running casing, liners and completions. In directional and horizontal applications, this high friction could also lead to high well tortuosity, which will limit the amount of step out and can even impair productivity.

The implementation of a unique tool, referred to as a Drilling Agitator Tool (DAT), has demonstrated clear improvement in drilling performance by reducing stick slip and torque at the drill string. This has enabled reduction in drag and thus improved weight transfer to the bit when drilling through highly interbedded formations, directional applications or long horizontal sections. It has also shown greater accuracy in maintaining tool face control once the static friction was minimized. This DAT relies on three main mechanisms: a power section, a valve and bearing section, and an excitation section. The tool operation vibrates the drill string with a low frequency and low amplitude axial vibration.

This paper illustrates case studies from the Haynesville, Fayetteville and Barnett Shale Plays, where the DAT has proven to help reduce torque and Stick-Slip when run on rotary in vertical applications, as well as Motor assemblies through directional and horizontal sections. These improvements in drilling performance have resulted in longer runs and faster rates of penetration compared to offset wells, thus reducing the number of bits and improving the economics in drilling these shale plays.
Reservoir Engineering for Unconventional Gas Reservoirs: What Do We Have to Consider?
Authors: Clarkson C. R. , Jensen J. L. , Blasingame T. A.
Published: September 2011

The reservoir engineer involved in the development of unconventional gas reservoirs (UGRs) is required to integrate a vast amount of data from disparate sources, and to be familiar with the data collection and assessment. There has been a rapid evolution of technology used to characterize UGR reservoir and hydraulic fracture properties, and there currently are few standardized procedures to be used as guidance. Therefore, more than ever, the reservoir engineer is required to question data sources and have an intimate knowledge of evaluation procedures.

We propose a workflow for the optimization of UGR field development to guide discussion of the reservoir engineer's role in the process. Critical issues related to reservoir sample and log analysis, rate-transient and production data analysis, hydraulic and reservoir modeling and economic analysis are raised. Further, we have provided illustrations of each step of the workflow using tight gas examples. Our intent is to provide some guidance for best practices. In addition to reviewing existing methods for reservoir characterization, we introduce new methods for measuring pore size distribution (small-angle neutron scattering), evaluating core-scale heterogeneity, log-core calibration, evaluating core/log data trends to assist with scale-up of core data, and modeling flow-back of reservoir fluids immediately after well stimulation. Our focus in this manuscript is on tight and shale gas reservoirs; reservoir characterization methods for coalbed methane reservoirs have recently been discussed.
Minimising HSE Impacts During Design and Construction of a Major Gas Pipeline Through the Baltic Sea
Authors: Valeur Jens Rosendal , Strøbæk Neel , Andersson Nicklas
Published: September 2011

During the period 2010-2012, two parallel gas pipelines (the Nord Stream Project) are being installed in the Baltic Sea, between Vyborg in Russia and Greifswald in Germany. The pipeline system will enable an annual transport of 55 bcm of natural gas from the large Russian gas fields to the European gas grid.

Comprehensive environmental and safety studies were carried out already in the design phase. The outcome of these studies was used in iterations with the pipeline design process, ensuring that the final pipeline design has minimal impact on the environment as well as on human activities in the Baltic Sea. Also, due consideration has been given to ensuring the health and safety of construction personnel and minimizing the environmental impacts during construction.

Major changes to the design were made in order to minimise project impacts, i.e.

– An originally planned intermediate service platform was "engineered out", eliminating the risk of ship collisions in the operation phase, – The pipeline route was optimised to avoid sensitive nature areas and heavily used ship traffic routes, – Extensive geophysical surveys were carried out in order to identify and mitigate interaction with dumped chemical and conventional munitions and cultural heritage objects, – It was insured by theoretical analysis verified by measurements that the pipeline with the chosen route did not have a negative impact on inflow and mixing of water in the Baltic Sea, – Environmental monitoring and subsequent feedback to the construction vessels were carried out during seabed intervention works near sensitive habitats.

Unique for this project is the major design changes that have taken place as a result of the HSE analysis. One outcome of this has been that all five affected countries have given permit to the project in a relatively short time period, even though it is the first major pipeline project in the Baltic Sea.
The State of Business Continuity Preparedness In The Supply Chain – An Operator's View
Authors: Wright Boyd , Teed David
Published: September 2011

Centrica's analysis of business risk confirmed several years ago that reliance on key contractors and its supply chain brought significant threats to the business. Centrica's business model reflects a similar exposure to that faced by other operators in relation to the dependency upon the major contracting companies, although Centrica also "contracts out" duty holdership of two of its producing platforms in the North Sea. We therefore recognized quite early on in our business continuity management programme that we could be exposed to an operational disruption through one of our key suppliers not having effective plans in place to cope with an incident that causes an unexpected loss of resource. During the past 3 years we have carried out regular supplier continuity reviews, with some interesting results. This paper outlines the issues and risks that should be understood by other operators and their suppliers to ensure that, as an industry, we can safeguard our credibility and the continuity of operations.

Practical interview, workshop and exercise methods have been effectively utilized to gain an appreciation of the maximum levels of service disruption that we could be exposed to. Our key contractors are scored on their level of business continuity preparedness. Appropriate risk mitigation activity was then identified to help reduce the likelihood or impact of a serious disruption to our operations.

This ongoing review has proved extremely useful for our management team to appreciate the actual state of preparedness of key contractors and identify any weak links in the supply chain. A common attitude expressed by suppliers showed an element of "risk blindness", often stated as: "we will just deal with the situation, should it ever happen". It is essential that the benefits of pre-planning become more widely appreciated, otherwise our industry could face some unwelcome impacts as the result of future incidents.

Being seen to manage an effective response and recovery, when faced with an unexpected event, is not only important for the credibility and sustainability of individual organizations but also for their customers, partners and the industry as a whole. This paper also includes some useful learning points in relation to how other industries have successfully addressed business continuity in their supply chains.
Component Inspection and Repair Using 3D Modelling Photogrammetry Technology
Authors: MacCormick Marie , Hall Anthony , Trower Alastair
Published: September 2011

3D modelling photogrammetry technology uses high-quality digital still images to construct geometrically accurate 3D models suitable for detailed measurements, Finite Element Analysis, 3D printing, and comparison to as-built components. Model manipulation and construction of interior geometry can also be performed to generate alternative configurations if needed.

Photographs are collected either subsea or topside, and pixels are matched between overlapping images to produce a 3D point cloud representing the component geometry. The point cloud is refined using the least squares method to achieve a model accuracy of better than 1mm under ideal conditions.

Resulting models can be exported in a variety of formats that are compatible with 3D drafting or Finite Element Analysis software packages. Image overlay can be applied to the models to better identify points-of-interest.

Welaptega has used this technology for a variety of applications, including:

Riser corrosion: the surface of a topside section of a heavily corroded riser was 3D modeled to determine corrosion depth and evaluate the riser's fitness for operation. Flange alignment: Leaking mating pipe flanges were 3D modeled to determine if misalignment was the source of the leak. The relative orientations of the flanges were determined by aligning a plane with each flange. Pipeline curvature analysis: An18-inch natural gas pipeline was impacted and dragged by an anchor, resulting in a dent and an unknown degree of curvature. A 3D model of the section of pipe surrounding the point of impact was constructed to determine the radius of curvature and perform finite element analysis. FlexJoint inspection: 3D models were constructed of FlexJoints in support of a regular inspection program. Points-of-interest and signs of wear were identified, measured, and monitored for progression using the 3D models. Wellhead repair: A wellhead was damaged when impacted by a falling Blow-out Preventer during recovery operations. A 3D model was constructed of the wellhead, and imported into design software for comparison to as-built drawings. The 3D model was also used to design a bespoke Internal Tree Cap hold-down tool to ensure well integrity.

In all cases, the 3D models provided critical information about component conditions, enhancing clients’ abilities to make decisions regarding repair.
Drilling Challenges in the North Atlantic Margin
Authors: Bagala S. , Getliff J. , Zaske J. , Watt I.
Published: September 2011

Chevron and its Partners are facing several challenges in the North Atlantic Margin exploration and development. These challenges affect drilling design and operations, which should take in account several important factors occurring concurrently in this area: deepwater conditions;complex lithological sequence and target imaging uncertainty;geomechanical conditions.

Hole section design is strongly affected by the uncertainty of the subsurface data, in particular the seismic data, where the presence of thick basalt flows, as strong reflectors, induce relatively poor seismic imaging of intra–basalt or sub–basalt drilling targets. This issue is mitigated with contingency plans for final hole section size and casing string setting depths. The complex lithological sequence, geomechanical conditions and lithological uncertainty also affect drilling fluid design and bit/bottom hole assembly (BHA) selection. The consideration of some of these factors had the outcome of using thixotropic muds to counter serious lost circulation events. A further successful outcome was the design and implemention of riserless drilling techniques, a first for Chevron Upstream Europe and Halliburton Baroid UK, to counter the threat of shallow water flows in the top hole sections. The paper demonstrates how a multi – disciplinary approach in both drilling design and operations is beneficial to successful drilling optimization in the North Atlantic Margin, a geographically and geologically challenging area.
Applying Fault-Tolerant, Hot Swappable Control Architectures in Subsea Environments
Authors: McLin Rick
Published: September 2011

Topside oil and gas installations have relied on control and safety system architectures for fail-safe, fault-tolerant, hot-swappable hardware for many years. But such systems have not been available for subsea installations – until recently.

The concept of a hot swappable subsea control or safety system may seem strange. After all, replacing failed subsea hardware usually entails shutting down underwater production, sending a surface vessel to the site and deploying a ROV to make repairs.

But the recent development of new system architectures has led to the creation of subsea versions of topside systems that can tolerate multiple faults, without compromising control or safety functions. These new systems also offer the capability to hot swap failed hardware.
West Franklin - How Geophysical Tenacity Led a Modest Franklin Satellite to a Full-Blown Field Development
Authors: Patel Kailesh , Ugolini Jean-Marc , Millancourt Francois-Jean , Falconer Chris , Soyeur Christophe , Neillo Valerie
Published: September 2011

The West Franklin HP/HT Field discovered in 2003 by the well 29/5b-F7z was drilled on a simple structure defined using the 1996 Elgin/Franklin 3D seismic - vintage data which has since been superseded by state-of-the-art seismic processing techniques. The original PSTM displayed relatively continuous seismic reflectivity with large uncertainty on imaging and interpretation.

The highly productive porous sandstone interval within the Upper Jurassic Fulmar Formation was identified as a high amplitude reflector due to a strong decrease in impedance. Anisotropic PSDM processing followed by an acoustic inversion study highlighted the probable extension of this ‘Porous Zone’ to the west and underlined the high potential for a second appraisal/development well.

Positive results from the second well 29/5b-F9y in 2007 showed dramatic thickening and improvement in reservoir quality to the west and initiated additional PSDM processing of the original 1996 data. Following developments in tomography and migration algorithms, strong imaging improvements were observed from the integrated anisotropic velocity model updates and by reducing the amount of destructive interference from multiples. The resulting interpretation allowed for a better understanding of the salt tectonics and in predicting Fulmar reservoir thickness to the west.

A 7km Long Offset 3D survey acquired by CGGV in 2009 with subsequent PSDM processing is bringing further imaging improvements over areas of amplitude degradation leading to potential upsides. A first 4D monitor acquisition over Elgin/Franklin in 2005 (before production had started on West Franklin in 2007) is being followed-up by a second 4D monitor in 2011, aimed at providing additional information on the depletion pattern around the field. Such strategy in ongoing investment in seismic data will further unlock the resource potential over and around West Franklin in the coming years, ensuring a mature area remains in the spotlight.
Ageing Infrastructure Offshore - A Risk-Based Approach to Supporting Investment/Divestment
Authors: Flint Marcus , Angelsen Sture , Amundsgård Øyvind
Published: September 2011

With increasing focus on the state of offshore installations as many approach and often exceed their original design life, there is a need for practical and cost effective methods to assess facility condition and assist operators and authorities in making decisions about the future investment / divestment of these assets. This paper presents one technique being developed and used by DNV for this requirement.

Normal asset integrity and condition assessments concentrate on work processes of the organisation which, though valuable, do not produce quantified results for decision making, or they concentrate on very detailed equipment assessment based on RCM or RBI techniques which can provide information, but take a long time to complete.

The technique outlined in this document provides an efficient methodology to develop a semi-quantitative result. This is sufficient in many cases to make the major decisions necessary to support Opex and Capex budgeting for continuing operations or to support the technical due diligence for change of operatorship in acquisition or divestment.

Using straightforward tools and principles, the paper leads through the top down approach covering: the consideration of current systems and their operational status; consequences of failure in terms of safety, production and environment, and how reliability and obsolescence are taken into account. Together these factors enable a risk ranking to be established which prioritises future budget and work requirements.

Inputs to the process are taken from a combination of historical operations and maintenance records, on-site examination of equipment and direct experiences of selected site personnel. Through these means, the technique combines a desk study with important buy-in of the local operations staff.

Samples of recent work in Africa and elsewhere will be demonstrated and refinements to the technique and other possible applications will be discussed.
Ageing and Life Extension of Offshore Oil and Gas Installations
Authors: Wright Iain
Published: September 2011

Over 50% of the offshore oil and gas installations in the UK Sector of the North Sea have now been operating for at least 20 years. Most assets are now approaching or operating beyond the original design intent. With the continuing rise in oil and gas prices and the advances in technology, there is an increasing requirement to extend the operational life of these assets. Coupled with this is the fact that most installations have seen considerable changes in the composition of the well fluids over the life of the field and there is an increasing trend for additional subsea tie-backs.

All of these issues have raised concerns regarding the integrity and fitness for purpose of the structures and equipment for this extended life. As a result, the safety case regulations were modified to include a technical justification for extended operation and the Health & Safety Executive has recently launched the Key Programme 4 (KP4) to ensure that all duty holders have suitable management systems in place to adequately address the ageing related issues.

This paper will outline a structured methodology that can be used to identify the issues which may prevent safe and reliable future operations of an offshore oil and gas installation. Some of the specific issues from previous ABB studies for offshore assets in the UK, Danish and Norwegian sectors of the North Sea will be outlined. These will include corrosion, obsolescence of equipment, changes in design duties, changes in oil or gas properties, availability of historic information etc. The paper will present a methodology for the evaluation of the risks associated with these issues and also outline how the recommended actions from such an approach can be used to help justify continued operations from a health & safety, environment and financial standpoint.
Flow Assurance Challenges in Gas Storage Schemes in Depleted Reservoirs
Authors: Kazemi Alireza , Tohidi Bahman , Nyounary Emile Bakala
Published: September 2011

Gas storage and subsequent production is of great interest due to fluctuations in gas demand and the difficulty for large scale gas storage in surface facilities. However, the injection and production of dry gas into or from a depleted gas reservoir could result in serious flow assurance challenges. The injected gas will evaporate connate/formation water to satisfy thermodynamic equilibrium. This will also happen during production phase and may cause salt precipitation, and potentially pore throats plugging.

In this paper we quantitatively describe and discuss the parameters involved in water evaporation/production and salt precipitation for a gas production/injection well in a field. In this work, the impact in terms of formation damage (skin) will be evaluated and some recommendations for prediction and mitigation will be proposed. In addition, the water present in the produced gas is a major flow assurance threat due to possibility of gas hydrate formation in the production system. Origin, description, prevention and mitigation methods are discussed and compared.

The results show that an increase in the salinity of formation water (due to production) will result in a decrease in the water vapour pressure, hence water vaporization, hence a decrease in the amount of hydrate inhibitor required for preventing hydrate formations in the system. Another important factor observed in this study is capillary pressure. A high capillary pressure will increase the gas/water transient zone and therefore there could be more water production from the well. In addition to water production problem we also observed that due to salt precipitation the porosity and permeability in the vicinity of the wellbore can be reduced by more than 50%. The effect of salt deposition and vaporised water production are potentially serious challenges in gas storage projects. It is necessary to carefully address these challenges in order to make gas storage projects practical and commercial.
The Practical Application of Process Safety Principles to Determine and Monitor Asset Integrity of Oil and Gas Facilities
Authors: Hopkins John
Published: September 2011

This paper discusses the differences between Process Safety Management and Asset Integrity Management.

It demonstrates how Asset Integrity is defined and managed simultaneously across a wide range of asset types –oil and gas, offshore production, onshore terminal, fixed platform, FPSO, NUI, new and mature assets.

The process is based on simple yet established principles which give clarity to areas that require attention. At its centre is a tool which defines the current vulnerability of the assets against engineering, production, maintenance, systems and human factors parameters. The vulnerability of an asset is ‘benchmarked’.

The information is displayed in different formats to meet the requirements of each level of risk management and accountability in the Duty Holder organization. This accelerates understanding of the current risks against Major Accident Hazards as both single and combined events. Remedial actions can be prioritized and resourced. Senior Management can interrogate the process to a detailed level in order to challenge the effectiveness of the interventions.

The process is based on the Barrier Model and uses Process Safety Performance Indicators selected to monitor Asset Integrity based on the company’s experience of managing offshore oil and gas assets. Each barrier is different and has an appropriate weighting. Calibration against a standard defines the strength of the barriers which in combination should prevent Major Accident Hazards on a site. Lagging and Leading PSPI are treated as ‘Holes’ and ‘Cracks’ in the barriers respectively. Weekly performance against the PSPI is recorded and used to derive the Vulnerability Index for the asset for that week. After any event against a PSPI, a simple Root Cause Analysis is carried out to determine which individual barriers were involved. Combined Risk is displayed in a number of different formats.

The process is adaptable, and can be scaled to suit a wide range of different types and size of facilities. It can be adapted for use in Process Safety Management

This process has evolved over three years. Asset Integrity Management is now imbedded in the organization. The implementation journey has not been easy. The paper gives an insight into the traction factors on this journey.

Asset Integrity is a status; you either have it or do not have it. Process Safety Management may deliver Asset Integrity. Asset Integrity Management is specifically designed to deliver Asset Integrity on a facility. Process Safety Management has the benefit of being applied to a wider range of industries and size of facilities.

Appendix D discusses the above and the company’s journey in terms of Asset Integrity Management up to 2008.