bluuebunny/crossref_metadata_2025 huggingface dataset:
Pediatric Mortality in Males Versus Females in the United States, 1999–2008
Authors: Balsara Sheri L. , Faerber Jennifer A. , Spinner Nancy B. , Feudtner Chris
Published: September 2013

OBJECTIVE:

To evaluate whether differences between pediatric male and female mortality are due to differences in specific age ranges, specific disease categories, or differences in the risk of developing specific conditions versus the risk of dying once having developed the condition.

METHODS:

Using 1999–2008 mortality data for all deaths of individuals <20 years of age from the Centers for Disease Control and Prevention’s WONDER database, we calculated male-to-female relative risks (RRs), standardized to the 2000 US Census, by age and International Classification of Diseases, 10th revision (ICD-10), chapters. By using the Centers for Disease Control and Prevention’s record of linked birth and infant death records between 1999 and 2007, we also calculated male-to-female RRs stratified by gestational age; and by using Surveillance, Epidemiology, and End Results cancer registries for 1999–2008, we calculated incidence and mortality RRs for the 7 leading types of cancer.

RESULTS:

Males experience higher mortality rates in all age groups from birth to age 20 years (RR: 1.44; 95% confidence interval [CI]: 1.44–1.45) and among infant deaths in nearly all weekly gestational age strata (RR: 1.12; 95% CI: 1.11–1.12). Stratified by ICD-10 major disease categories, males experience higher mortality rates in 17 of 19 categories. For the 7 types of pediatric cancers, the overall pattern was similarly greater male incidence (RR: 1.13; 95% CI: 1.12–1.14), fatality rate (RR: 1.10; 95% CI: 1.07–1.13), and overall mortality (RR: 1.21; 1.18–1.25).

CONCLUSIONS:

Under 20 years of age, males die more than females from a wide array of underlying conditions. The potential genetic and hormonal mechanisms for the mortality difference between males and females warrant investigation.
Online Transient Simulation to Support Production Operations Planning in a Wet Crude Oil Gathering System
Authors: Mollinedo Ramon , Lopez Luis Fernando , Martinez Abigail , Kulkarni Mandar , Lazcano Juan , Villanueva Francisco , Vivas Pedro , Palacio Sergio
Published: September 2013

Production operations planning is an important function for the integration of petroleum midstream delivery activities, as it defines the strategy for product delivery at the operational level in order to meet delivery contracts.

This paper describes a practical application of real-time online transient flow simulation technology to support operations planning in a crude oil gathering system, in which an onshore terminal manages production from five offshore pipelines. Planning operations at the terminal is a daily challenge due to limited storage and water processing capacities, and is further complicated by large uncertainties in fluid arrival volumes and product quality caused by operating changes.

A production planning support system based on transient flow modeling technology was implemented in one portion of the pipeline network. The objective was to track the dynamic state of the system and use it to provide virtual measurements of hydraulic conditions in the pipelines, along with production volumes and product quality indicators at the terminal. Such information is generated in real time and has enabled the following business functionalities: Planning for crude oil production at the terminal proactively rather than reactivelyQuantifying oil and water volume impact on terminal operations in response to operational changes taking into consideration dynamic oil/water holdup effectsForecasting water production volumes and exposing results to manage operation of water treatment facilities according to capacity and availability

The modeling system has proven to be an effective tool in the tracking and forecasting of the pipeline operation, and has been incorporated into the operator’s daily production planning workflow. The system has also drawn much needed attention to the transient aspects of fluid flow in an oil-water pipeline network, behavior that is often perceived as immaterial for liquid only systems, but was largely responsible for the quality and volume tracking issues that the operator was facing.
Putting Pressure on Subsea Pipeline and Umbilical Blockages
Authors: Bain Rob
Published: September 2013

The low cost, non-intervention, effective solution for remediating flowline and umbilical blockages, that are in deepwater and a long distance from the Asset.

Blockages within flowlines and umbilical cores present an on-going concern within the oil and gas offshore industry. The more infrastructure that is installed subsea, the greater the risk of further blockages. Deepwater and cold water (arctic) fields are driving ever longer and more complex tie-backs. Maintaining these supply and production conduits free from blockages is a high priority for operators. Unfortunately, either through change in producing conditions or simply through human error, blockages commonly develop within these systems.

Few effective techniques exist for estimating the locations of blockages. A limited number of techniques also exist for removing them. However, neither task can be undertaken with certainty and, in particular, it is sometimes impossible to remove blockages by traditional means and at an acceptable cost. The actual costs of blockages to operators are enormous.
An Innovative Wireless H2S Sensor Based on Nanotechnology to Improve Safety in Oil & Gas Facilities
Authors: Piantanida Marco , Veneziani Maurizio , Fresca Fantoni Roberto , Mickelson William , Milgrome Oren , Sussman Allen , Zhou Qin , Ackerman Ian , Zettl Alex
Published: September 2013

Real-time monitoring of pollutant, toxic and flammable gases is important for health and safety of petroleum extraction and distribution operations. Small, lightweight, fast, low-power, low-cost sensors would enable ubiquitous monitoring of these gases, which would allow for prevention of exposure or explosions and aid in rapid response to hazardous leaks. Currently, there are many methods of detecting such gases, but most sensors suffer either from slow response times, high power consumption, high cost and/or inability to operate in harsh conditions.

Here we demonstrate a small, low-cost, low-power, highly sensitive and selective nanomaterials-based gas sensor, specifically targeted for the detection of hydrogen sulfide (H2S). A network of WO3 nanoparticles is heated by an on-chip microhotplate while the conductance of the network is monitored. The device can be heated with short pulses (<100 ms) without diminishing the sensor response, thereby drastically lowering the power consumption to less than 1 mW. The sensor shows high sensitivity to H2S, but it does not have direct cross sensitivities to H2O or CH4, two gases likely to be seen in industrial operation.

This low power H2S sensor has been integrated into a low cost, stand-alone monitoring system capable of measuring multiple environmental conditions, including temperature, humidity, and H2S concentration, and distributing that information via wireless protocols, namely 802.15.4 and 802.11 (WiFi). These environmental detection systems can communicate directly to smart phones via WiFi or be configured into a wireless mesh network of detection systems capable of relaying real-time environmental conditions and location to a safety monitor at a remote location. The nanoparticle-based sensor and integrated detection system developed here, once packaged as a fully manufactured tool, can enable a low-cost solution to real-time monitoring of environmental conditions that will greatly reduce the likelihood of hazardous conditions becoming disasters.
Development and Field Trial of a Non-Aqueous-Based Mud Lubricant
Authors: Lescure Jean , Teng Jerome , Degouy Didier , Espagne Bernard
Published: September 2013

To meet the ever increasing global demand for energy, oil companies are under constant pressure to increase production. Today, operators have to drill deeper and further (extended reach, deviated, HPHT, etc.) to seek out new sources of supply. Such operations are known to regularly challenge operators with issues of high torque and drag, often leading to increased wear in rig equipment (e.g. drill strings, casings and mud pumps).

Lubricants have been known to be added to Water-Based Mud (WBM) to improve its lubricating properties. When the desired lubrication can no longer be attained by such means, operators switch to drilling with Non-Aqueous-Based Mud (NABM). The natural lubricating properties of the base oil used to formulate NABM help achieve a lower friction coefficient compared to drilling muds formulated with water. However, in view of the harsh drilling conditions mentioned above, there is a strong incentive to enhance the lubricating performance of NABMs even further.

The aim of this paper is to explain the challenges and share the results of developing a Non-Aqueous-Based Mud lubricant.

We will focus successively on: –Screening tests on additives diluted in base oil from an adapted method using the High-Frequency Reciprocating Rig.–The need to develop new tribological tools to assess the performance of an NABM lubricant–Environmental constraints (biodegradability and ecotoxicity)–Laboratory stress tests (thermal resistance, stability)–Field test data on a deviated well in Nigeria, using 1% of lubricant in NABM, where a torque reduction of 20% was measured.

Conclusion: there is a clear operational benefit to the use of NABM lubricants, demonstrated both at laboratory level and in the field.
Jack-Up Drilling on Conventional Subsea Wellheads
Authors: Kotrla Johnnie , Cummins Ray
Published: September 2013

Throughout the 1970s, 1980s and 1990s, many relatively shallow-water wells were drilled at water depths less than 600 ft. (183M) utilizing conventional Semi-submersible Rigs, Subsea wellheads and/or subsea templates. A goodly portion of this drilling was done in the North Sea, in both the Norwegian and UK sectors. Now, as those wells age to the point of requiring intervention to maintain, or enhance production, new generations of large Cantilever Jack-up rigs are available that can rework thes wells at a much lower day-rate than conventional semi-submersible rigs, be they anchor moored or dynamically positioned.

Jack-up rigs hav not been, and were never intended to be able to attach to a subsea wellhead assembly. To date, this was the exclusive territory of Semi-submersible rigs or Drillships (but primarily Semi-submersibles). This basic equipment incompatibility needs to be addressed before detailed plans can be formalized.

The most obvious solution to this problem is to install a subsea BOP Stack onto each of these new Jack-up rigs so that the connection to the subsea wellhead can be accomplished in a traditionally acceptable manner with relatively conventional equipment packages.
Secondary Intervention for Blowout Preventers
Authors: Klassen William P.
Published: September 2013

Currently available secondary intervention systems may not successfully operate critical subsea blowout preventer (BOP) safety functions such as closing pipe rams, blind rams, and shear rams. Failure may occur because sufficient hydraulic power (pressure times flow rate) is not available to operate these functions quickly in a flowing well, causing failure of sealing elements. This paper describes current shortcomings and identifies a novel ROV-based intervention.

With numerous combinations of rams, bore pressures, bore flows, pipe sizes, and additional equipment inside the well, it is difficult to determine the right amount of hydraulic power required to meet closure times specified by the subsea industry and regulatory groups. This paper considers well conditions and determines the necessary power.

Neither current ROV hydraulic pumping interventions nor hydraulic accumulator interventions can provide the necessary combination of large amounts of flow and pressure for successful secondary operation of BOP safety functions. Also, because current intervention systems are not integrated with ROV systems, they require significant deployment time. Hydraulic accumulator intervention systems provide maximum power at the wrong time—at the beginning of the ram stroke instead of the end—and also have depth limitations.

Given the limitations of current hydraulic intervention systems, an ROV-based intervention system is being developed to reliably operate BOP safety functions. This intervention system, which is integrated with current work-class ROV electrical and hydraulic power functionality, uses novel power management designs.
Umbilical Communications Condition Monitoring
Authors: Bagley Phil , Gillespie Alisdair , Grant Kevin , Neale Dafydd
Published: September 2013

Umbilical communication utilising optical fibre has increased in recent years, however communication via an electrical umbilical still dominate the industry. When communicating over electrical conductor’s modulation techniques such as Orthogonal Frequency Division Multiplexing (OFDM) and Quadrature Amplitude Modulation (QAM) can be used to improve data rate and reduce transmission errors. These modulation technologies lend themselves to condition monitoring approaches that do not affect the performance of the communication channel. Here we present a condition monitoring system to detect in real time umbilical communications deterioration before failure.

The Aker Solutions electrical communications modem utilise OFDM or QAM techniques to encode digital data such that a particular phase and amplitude represent a binary code. These data can be represented graphically where a particular phase and amplitude are shown as locations on a XY graph (constellation diagram). Noise, communication channel interference, or any other factor reducing communication channel performance will result in a move away (an error vector) from the ideal location on the constellation diagram. The QAM data also contain pilot tones transmitted at know amplitudes and frequencies to enhance modem performance. These pilots can be utilised to produce a frequency response of the umbilical communication channel. For condition monitoring the error vector and channel frequency response can be utilised to determine the end-to-end health of the communication channel.

The communications modem is capable of fault free operation with large error vectors and poor channel frequency response. Therefore, the user may not be aware of deterioration in umbilical performance until the communication channel fails. The ability to monitor the condition of umbilical communications in real time without affecting data throughput presents a significant advantage. Enabling the user to detect and correct umbilical communications problems before failure.

This paper will present results from trials using the umbilical condition monitoring system on QAM16 communications over a Research and Development umbilical simulator.
Positioning Challenges of the Arctic Subsea
Authors: Hanton Sam
Published: September 2013

The location and environment of the arctic region provides a number of additional challenges and considerations to those experienced during operations in the current locations popularly serviced by the majority of the Oil and Gas companies and contracting subsea supply chain.

The paper provides a brief overview of the arctic region and the existing and forecast Oil and Gas investment and developments over the coming years.

The paper then focuses on the positioning and navigation challenges posed by operations in the arctic, both from a technical perspective and also with consideration of equipment design to survive the harsh environment. We aim to describe the challenges posed to the different types of positioning systems by the harsh environment, including the effects of high latitude on DGNSS and heading sensors, the difficulties of using the increasingly commonly encountered Inertial Navigation Systems around the North pole, and the potential effects of intact and melting ice on subsea acoustics. The logistics associated with arctic operations are also introduced.

Potential solutions and alternatives through assessment of system options and combinations of sensors will be discussed, along with recommendations of the basic essentials to be considered when planning positioning in the arctic.
Subsurface Interpretation and Pre-Messinian Deposits Prospectivity of the Algerian Offshore Basin
Authors: Khennaf Nahim , Benabdelmoumen Sadek
Published: September 2013

The Algerian offshore area is located in the western mediterranean sea, East of alboran basin, and south of algero provencal basin.

In geological perspective, it covers the area from the narrow continental shelf to the deep basin, water depth range from 0-2800m.

Prospectivity is primarily associated with pre-messinian deposits, in addition to Pliocene.

The seismic data consists mainly of 2D surveys, with relatively coarse coverage in addition to gravity and magnetic. The 2D seismic coverage acquired in 2011 (5000km) covers the main deep water area. The evaluation of the 2D seismic data has highlighted a number of significant leads with different sizes. They are related to different kind of traps (anticlines, faulted and tilted blocks, …).

Only one deep well (4496.5m) and two core drills have been drilled. The onshore geological map reveals the extension toward the offshore of the Chelif basin. The petroleum potential of this onshore basin is proven since the 1940’s with the discoveries of Ain Zeft and Tliouanet oil fields.

Reservoirs are expected to consist of sandstones related to Miocene, in addition to the Oligocene (Numidian flyshs) that can be found in the eastern part. The hydrocarbon potential interest in the eastern part could be enhanced by the positive discoveries in the Sicilian channel and also by the proven petroleum system of the Numidian in the onshore part of Tunisia and Algeria (Ain Regada).
Compact Processing Solutions : Inline Gas-Liquid Separator on the Santos Wortel Field
Authors: Imaduddin Imaduddin , Tienhaara Mika
Published: September 2013

For the Santos owned and operated Wortel field, shallow waters offshore Indonesia, there was a need to install compact inline gas/liquid separation equipment with high performance. Due to space constraints, an inline gas/liquid separator was selected. Santos implemented the ASCOM Twinline technology on the platform, which has been in operations since February 2012 and is performing very well. This is an example of rapid technology development, initiated in 2010, with performance verified over a longer period under operations.
Shearwater - Securing the Chalk - Effects of Depletion of a HPHT Reservoir on Chalk Overburden
Authors: van Bergen P. F. , De Gennaro S. , Fairhurst F. , Hurry R. , Concho M. , Watson J. , Sturgess L. , Bevaart M.
Published: September 2013

In preparation for a new phase of development of the deep, >8000 psi depleted, high-pressure, high-temperature (HPHT) Shearwater field in the UK Central Graben of the North Sea, the existing well stock had to be prepared to enable slot availability for sidetracking operations. Here techniques and key learnings gained from the slot preparation activities, in particular with respect to the chalk overburden, are described.

During the slot preparation activities new data on fracture gradients and the extent of porosity in the chalk was acquired. This information was then integrated with the results gained from the use of state of the art logging tools and unique data acquisition (including chalk hydrocarbon molecular and isotope compositions). In addition, an analysis of overburden time shifts from re-processed 4D seismic data was completed, along with geomechanical modelling work.

A new understanding was gained of the effects of reservoir depletion on the chalk, from being a solid uniform tight rock with very low permeability to a more heterogeneous permeable formation with differential reactions to reservoir depletion. The key learnings have been integrated into the ongoing slot recovery operations and future well plans. The overall integrated data allowed a greater understanding of the heterogeneity of the entire chalk section, which has been valuable in considering chalk overburden complexity.
Subsea Water Treatment and Injection Station
Authors: Olsen Jon-Erik , Pinchin David
Published: September 2013

Description

Many reservoirs in the UKCS are experiencing rapid pressure drop, reduced production, low recovery rates and high water cuts. More fields are also being developed as subsea fields. Moving the water treatment and injection to the seabed offers opportunity for improved recovery. Such a complete subsea water flooding system is now available as a Subsea Water Treatment and Injection Station with qualified technology for the first time, providing a change in mindset for offshore recovery by enabling treatment and injection subsea.

Application

Treating water at depth, and injecting from the seabed, enables cost-effective developments avoiding expensive flow-lines. 4D-seismic reveals that optimal positioning of water injection wells is not always technical or economical reachable from platform. With maximum flexibility and without the traditional topside restrictions, an improved reservoir drainage strategy enables increased/enhanced recovery. The technology is therefore applicable for all offshore fields at any stage of their production life.

The unique merging of proven technology into a standard template provides operators with a turn-key ready station for subsea water injection of treated water. The Subsea Water Treatment and Injection Station contains water treatment, injection pump(s), and injection trees. The station ties back to host with an umbilical, providing power and controls. Future systems may also include membrane modules.

The subsea water injection and treatment concept is applicable to Subsea Production and Processing Systems. With an added separator, fields with high water cut can be processed subsea to re-inject produced water.

Conclusions

The new subsea seawater treatment system has recently completed successful 24 months of trials on the seabed with the help of two global JIP ̀s. The new water treatment system provides water superior in quality compared to that achieved by a traditional topsides water treatment plant in areas important for water injection for IOR. – I.e. a lower degree of bacterial concentration, good disinfection and solids reduction.

In this paper, system capabilities and experience from testing together with membranes will be presented.
Pull or No-pull: Risk-based Decision Support for Subsea Blowout Preventers (BOPs)
Authors: van Asten Pieter
Published: September 2013

Overview

The tragic Gulf of Mexico accident in April, 2010 can be marked as the defining moment which confirmed the idea for making a subsea Blowout Preventer (BOP) risk model.

The accident showed that society is our biggest stakeholder with its own risk acceptance perception, enabled by the immediacy of social-media, the tenacity of the press, and today’s instantaneous technology for transmitting newsworthy and life-altering events.

When thinking back to that day in April, we can ask: what does the majority of society remember about this tragedy? The most common answer to this question is the graphic photos of massive amounts of oil washing up on once pristine Gulf beaches, killing fish, birds, and other ancillary industries which rely on clean Gulf waters and beaches to survive. Although not pictured with such detail, the casualties will never be forgotten either.
Approximations of Primary, Secondary and Tertiary Recovery Factor in Viscous and Heavy Oil Reservoirs
Authors: Kaczmarczyk Rafael , Herbas Julio , Del Castillo Juan
Published: September 2013

Limitations in the availability of methods to estimate recovery factor at the initial stage of petroleum exploration pushes for investigation new ways of analysing available datasets.

This work investigates empirical and volumetric methods to estimate recovery factors in viscous and heavy oil reservoirs. It also investigates newly available advance screening methodology to determine tertiary/ultimate recovery factor in these reservoirs. Initially, primary recovery factor was estimated based on field analogy. Secondary recovery factor was calculated using empirical equations. In the second, main part of this work, ultimate recovery factor was approximated using data mining/machine learning approach to reveal eventual trends in viscous or heavy oil databases.

Information contained within this project was used to estimate recovery factors in certain viscous oil reservoirs at the initial stage of exploration. However, after reformatting original data base, advance screening methodology would be potentially applicable to any viscous or heavy oil reservoir around the world.

It was found during the project that the primary recovery factor can be successfully estimated based on the field analogy. Empirical methods can be applied in some cases. The quality of the obtained results depends on whether they were derived for conventional or heavy oil reservoirs. Based on advance screening, it was shown that tertiary/ultimate recovery factor can be successfully estimated.

Final product includes development of a methodology on how to approach the recovery factor approximation in viscous or heavy oil reservoirs without production history or at early stage of the field life.
The Return to the North Sea: Looking To Unlock Further Value
Authors: Mayland P. J. , Conley B. , De Boer W. , Robertson L. , Clark R.
Published: September 2013

After a period of nearly 10 years absent from the North Sea oil and gas sector, in 2012 Cairn Energy re-entered the UK Continental Shelf, and for the first time entered the Norwegian North Sea through the combined corporate acquisitions of Agora Oil and Gas AS (a private Norwegian company) and Nautical Petroleum (an AIM-listed E&P company), respectively. Cairn had upstream experience in both the UK and Dutch sectors of the North Sea and was an active non-operating partner in the Gryphon heavy oilfield in Quad 9 and in the P6 and P12 gas fields in the Netherlands.

This paper outlines the method and approach taken to rebalance Cairn’s portfolio after sustained success in South Asia and the sale of Cairn’s majority shareholding in Cairn India and the subsequent need to rebuild a portfolio with a cash flow generating base to underpin exploration and appraisal opportunities, both internationally and in the North Sea itself. It explains Cairn’s rationale and key drivers for entry and (re)-investment in the North Sea versus other possibilities. It also discusses the importance and value of preserving knowledge and expertise within the acquired companies and the process of integration.

The paper will also investigate: (i) the technical aspects of Cairn’s acquired interest in two key oilfields, Kraken and Catcher which, in gross terms, will deliver approximately 10% of the UK's oil production when onstream and (ii) Cairn's remaining exploration portfolio in the North Sea and subsequent plans and opportunities for growth.
Development of Spilled Oil and Gas Tracking and Monitoring Autonomous Buoy System and its Application to Marine Disaster Prevention
Authors: Kato N. , Senga H. , Suzuki H. , Choyekh M. , Kimura R. , Akamatsu T. , Yoshie M. , Tanaka T. , Sakagami N.
Published: September 2013

This paper describes the ongoing project on autonomous spilled oil and gas tracking buoy system and application to marine disaster prevention system for 5 years since FY2011. The objectives of this project are as (1)autonomous tracking and monitoring of spilled plumes of oil and gas from subsea production facilities by an underwater buoy robot(SOATB-I), (2)autonomous tracking of spilled oil on the sea surface and transmission of useful data to a land station through satellites in real time by multiple floating buoy robots(SOTAB-II), (3)improvement of the accuracy of simulations for predicting diffusion and drifting of spilled oil and gas by incorporating the real-time data from these robots.

SOTAB-I is different from normal type underwater gliders in terms of vertical and horizontal movement, because SOTAB-I focuses on almost the same movement in horizontal plane as in vertical movement. It installs an underwater mass spectrometry, CTD and ADCP so that the vehicle can identify the characteristics of oil and gas and the place where they are leaked using data obtained by the vehicle in combination with numerical simulation of blowout of oil and gas from deep water.

SOTAB-II utilizes the control low of a sail so that the buoy drifts along the resultant velocity vector of water current and 2-5 % of wind velocity watching the drifting substances on sea surface by sensors mounted on the mast. Multiple SOTB-IIs are deployed just after an oil spill accident to track patches of spilled oil. SOTAB-II can provide us with real-time measured data on position of spilled oil on sea surface, the meteorological and oceanographic data and characteristics of spilled oil for a long range. The combination of the real-time data and the numerical simulation of the drifting spilled oil on sea surface will enable us to predict the precise drifting of the spilled oil.
Post-fire Structural Integrity of Composite Gratings for Offshore Platforms
Authors: Holliday R. J. , Gibson A. G. , Humphrey J. , Di Modica P. , Christke S. , Kotsikos G.
Published: September 2013

In parallel to studies by the HSE resulting in the issuing of a Safety Alert warning to the offshore industry on possible failure of fire resistant composite gratings (Bulletin No: HID 2-2012), a study was made by MMI Engineering in conjunction with Newcastle University into the post-fire integrity of phenolic and polyester FRP gratings to determine whether such gratings can be safely used following exposure to fire.

Firstly the range of weights of offshore workers was established. The recommended residual strength required for post-fire use should exceed the load generated by a running person, at the upper 5-percentile of the weight spectrum, carrying fire fighting or rescue equipment. This load includes a dynamic amplification factor to allow for the effect of running, additionally a further safety factor is required to account for fatigue effects.

Samples of gratings were tested to determine the stresses resulting from running or walking by applying strain gauge instrumentation to individual beam elements of gratings to measure the strains produced. The strain gauge study was augmented by modelling to quantify the relationship between applied load and local strains. These strains were found to depend on the ‘footprint’ area over which the load was applied.

Fire exposure tests involved using a propane burner to expose individual beam elements to three heat fluxes of 12.5kW/m2, 37.5kW/m2 and 100kW/m2 as well as jet fire testing at ~250kW/m2 representing the full range of fire types considered on oil and gas installations. The duration of the fires were increased in increments up to 16 minutes to establish the rate of deterioration.

This paper presents the results of the testing, provides information to operators on where these materials can be safely used as well as providing grating manufactures with guidance on future product testing and development to produce more fire resistant systems.
Structural Response Monitoring Of Huntington HP Drilling And Completion Riser
Authors: Rimmer A. , Bamra B. , Allan R. M. , Proud G. , Davidson S. , Parker B.
Published: September 2013

Use of full bore high pressure (HP) risers in ever more challenging locations and conditions has increased requirements to collect in-situ response data to confirm that the riser design is acceptable and confirm integrity. Due to the challenging combination of the 91m water depth and harsh environment at Huntington field in the North Sea, considerable analytical work was required to design and configure the proposed 24inch diameter HP drilling riser and well conductor system to allow successful and safe all year operations from the jackup rig. As well as careful strength and fatigue design of the upper and lower most HP riser joints, this potentially required modifications to the rig’s CTU deck to support the high loads expected. Typical conservatisms in analysis methodologies also needed to be removed to allow for a viable theoretical design. In-field measurements were therefore proposed to allow for verification and calibration of the analysis used as a basis for the design decisions and to ensure that the integrity of the riser was maintained during the 12 months of drilling and completion operations. The monitoring system developed to address this, the first type of its kind to be installed on a jackup rig, incorporated a range of accelerometer and strain sensors to record motion, load and fatigue responses of the riser and jackup system in real-time.

This paper describes the background to the monitoring system design, the components that make up the monitoring system and presents the comparisons between the collected data and analytical predictions that allowed the objectives of verifying the analysis and confirming integrity of the riser to be achieved. Recommendations are also given as to how the monitoring system can be improved for future use in similar applications.
An Organisation-Wide Investigation Into The Human Factors-Related Causes Of Hydrocarbon Releases On Offshore Platforms
Authors: Gilroy Jenny , Dumolo Derek
Published: September 2013

An offshore Operator contracted Lloyds Register Consulting to conduct an independent HF-focussed organisational assessment into the underlying contributory factors to HCRs on their platforms, in order to support their own internal initiatives to reduce HCRs. The aim of Lloyds Register Consulting’s assessment was to help the organisation confirm and identify the key areas of focus in order to combat HCRs and prioritise further actions going forward.

Lloyds Register Consulting adopted a systematic approach to investigate the HF contributions to HCRs on the organisation’s platforms, including a Thematic Analysis of past incident data, offshore interviews and onshore interviews with staff and detailed analysis of findings to identify common emergent themes issues. Eight key areas were identified as priorities for further action, and Lloyds Register Consulting provided the operator with recommendations for improvements and/or remedial actions to deal with identified contributory factors

This presentation will explain the approach followed by Lloyds Register Consulting and the findings from the study, including the key Human Factors causal factors that were identified. It will also highlight the key lessons learned that are considered to be potentially relevant to the wider offshore sector.
NUGGETS Gas Field - Pushing the Operational Barriers
Authors: Saha P. , Parsa A. , Abolarin J.
Published: September 2013

NUGGETS subsea development in the Northern North Sea consists of 5 gas wells with 40 – 70 km tie-back to the Alwyn platform with 1st gas in 2001 and a peak production of 6 MMSCM/D of gas in 2004. Project life was expected to be 10 years with main constraints being methanol requirements for hydrate management and sealine minimum turndown.

Due to increasing water production, the wells were shut-in one after the other and the field was due to be decommissioned in 2010. At that time, minimum recommended MeOH concentration was ≈ 28% (wt/wt) which allowed a maximum water production of 40 Sm3/d. Thanks to a concerted effort to keep gas rates at targets which respected all constraints and reduce methanol use to zero, an additional 2.8 MBOE has been produced from NUGGETS. This represents an incremental recovery of about 2.0%. In addition, the field life has been extended with the possibility of further prospects being tied-in to the existing facilities.

With methanol constraints removed, new issues are subsea system life longevity and reservoir management. Current field operations philosophy is optimised to respect minimum turndown of the subsea line and the minimum gas rate per well with/without water production. It is also aimed to manage water coning in the reservoir. The reservoir has very high permeability with Kv/Kh ≈ 1 and strong aquifer influx. Moreover, numerical as well as analytical methods were used to investigate the coning.

This paper provides a critical assessment of the methods employed from a flow assurance, a well performance and a reservoir management point of view. It concludes with a set of observations and recommendations for operators of dry gas fields with strong aquifers and long subsea tie-backs.
Barrel Chasing Through Well Interventions - Can We Get Better At This?
Authors: Kitsios S. , Shields C. A. , Vroemen S.
Published: September 2013

This paper presents a recent initiative by European operators for improving production enhancement via well interventions. It is based on the output of a benchmarking exercise into the performance of the various intervention activities. Data is historic and the aggregated and anonymised results of the benchmarking exercise are shared only amongst participating operators. Operators meet annually to discuss technical successes and failures and to identify potential areas for technical collaboration. Collaboration projects are only kicked off once win-win situations can be defined. Results to date indicate a broad range of performance impying ample opportunities for raising both operator and industry performance. The aim of this paper is to attract more participation in this European initiative and to raise interest for replicating it in other regions.
Role of Artificial Lift in Wells With a Downhole, Flow Control Completion
Authors: Gasbarri Sandro , Muradov Khafiz , Davies David
Published: September 2013

Several hundred of Intelligent wells well that combine downhole flow control and monitoring have been installed over the last decade in a wide range of reservoir production scenarios. Numerous publications have reported the successful use of the technology to reduce the number of well interventions, improve sweep efficiency, reduce risk, mitigate production problems, etc. A number of zonal inflow and outflow control methodologies have been proposed to meet a wide range of different well objectives as well as different production or injection conditions. Research still continues in the areas of simple reactive or predefined passive control methods employed by Intelligent wells. This is even more true if it is planned to use proactive control which requires optimisation of a complex multivariable problem.

Efficient downhole flow control comes at the cost of adding an additional pressure loss. Such losses can be significant, jeopardizing the well productivity and sometimes carrying the risk of a reduced well performance of the intelligent well when compared to the corresponding conventional well. Installing artificial lift can compensate for this reduced well performance; not only extending the well life, but also adding additional well control flexibility. However, it also poses two extra problems: how to (a) optimally design the artificial lift equipment and (b) avoid interference between the I-well’s control of the zonal inflow and control of the artificial lift.

This paper sets out how to(1) Add control flexibility to downhole flow control by artificial lift and (2) Design an electric submersible pump that operates flexibly with down hole, multi-zone inflow control actions.

Improved active and passive downhole flow control will be discussed in a rigorous, mathematical manner that allows the conclusion that the combination of artificial lift and downhole flow control provides greater zonal flow control flexibility and reduces the inflow imbalance. Also, two conceptual, electric submersible pump design options, employing (1) a variable wellhead choke and (2) a variable pump operating frequency, are proposed and illustrated. Both of these proposed pump design options could cope with the changing well inflow performance created by downhole flow control devices in situations where the standard pump design workflow was ineffective.
Seismic Full Waveform Inversion improves Valhall Reservoir Management
Authors: Andorsen Kent , Barkved Olav , Idsøe Christian , Wrobel Lukasz , Kristiansen Tron G , Tjetland Gunnar
Published: September 2013

The Valhall field has been on production since 1982 and produced in excess of 800 mmboe. The primary reservoir is the over-pressured, high porosity and fractured Upper Cretaceous Tor formation. The field compacts during depletion, resulting in subsidence in the overburden.

In 2003 a permanent seismic array, LoFS, was installed across the field. The main objective of the system was to support the water flood program. To date15 seismic surveys have been acquired and the LoFS program has proved to deliver valuable information.

In monitoring of the Valhall water-flood program we were facing two fundamental technical challenges; poor p-wave seismic quality in part of the field and the presence of very thin dense, zones with pervasive fault induced fracturing. These fractures act as conduits and distribute the water away from the well.

Fortunately, the type of seismic recordings achieved using the permanent system are favorable for the use of full waveform inversion, and we have been able to produce velocity models containing much higher resolution than conventional ray-method based tomography. This model supported focusing of primary seismic reflection such that the presence of the reservoir could be interpreted from 4D seismic images, as the noise that still dominated the conventional 3D images appears to be highly repeatable and was reduced in the inherent differencing process.
Estimated Fluid Contact Using Material Balance Technique and Volumetric Calculation Improves Reservoir Management Plan
Authors: Ghahri P. , Berthereau G. , Milner S. , Orta M. , Sikandar A. S.
Published: September 2013

The Gryphon Field located in block 9/18b of North Sea was discovered in 1987 and originally comprised of a ~200ft thick oil rim under a gas cap with a strong aquifer. It is connected to another nearby field via the gas cap and has been producing since October 1993. One of the biggest challenges in placing future wells is that production has significantly thinned the original thickness of oil column above the oil-water contact (OWC) and the gas-oil contact (GOC) has moved up due to gas movement and production.

A methodology has been developed to estimate current water (OWC) and gas (GOC) oil contacts in the field from initial fluid in place, production and rock and fluid properties. The methodology is based on the volume of remaining fluid in the reservoir using material balance techniques and calculation of the fluid contacts assuming the whole reservoir as a single tank, and with best estimates of initial contacts and residual saturations.

Here, the contact movements have been calculated versus time. The calculated fluid contacts show a good agreement for two direct measurements of GOCs from two pilot holes. There is a 50 ft difference between OWCs from these two pilot-holes measurements; the calculated OWC is almost the average of these two values - providing confidence in the approach.

The calculated fluid contacts were also compared with recently obtained 4D seismic and up to date reservoir simulation model for different producing wells that show a good match.

The completion interval of all wells has been mapped versus the contact movements. The results show that in order to increase oil production from the current the wells, gas injection could be increased in a way that takes into account the effects of fluid movement. The wells need to be operated as much as possible at low gas oil ratio that is possible due to strong water drive. It is also shown that the datum of the new infill wells should be at a shallower depth compared to previous wells.
Ninian Southern Platform Jacket Repair Readiness Strategy: Development of a Modular Hyperbaric Habitat System
Authors: Mann Gavin , Wilson Mark , Martin Robert , Branch Ian
Published: September 2013

Hyperbaric welding habitats provide a dry environment where divers can perform subsea welded repairs to structures or pipelines. The Ninian Southern Platform jacket structure in the northern North Sea has suffered a history of weld defects and fatigue-induced brace failures since it was installed, a number of which have required extensive hyperbaric weld repair work.

Previous repair projects have typically been long and expensive as they have relied on a purpose built welding habitat which requires a long lead time and significant up front cost for each repair. The need to have in place a repair readiness strategy for the Ninian Southern Platform jacket, to minimise the time and cost involved in carrying out repairs to critical welds led to the development of a modular system which can allow access to a large number of different weld locations.

This paper describes the concept, design, building and testing of a unique Modular Habitat system to fit 80% of the brace welds on the Ninian Southern Platform. The design has kept diver safety as the over-arching driver, but with flexibility, speed and quality of repair as key objectives of the project.

Evolution of the design to suit the maximum number of weld configurations is explained, through detailed design to the importance of sealing onto the different brace configurations. Key to this achievement was a collaborative approach that involved CNRI, Subsea 7 and Atkins; input from diver experience of working in bespoke jacket repair habitats was invaluable. As well as developing an optimised enclosure small enough to be located in confined areas but large enough for practical working, the opportunity was taken to include state-of-the-art features in the Habitat’s integral diving system, making it as far as possible a safe and comfortable place in which to work. The design was refined by the use of full scale mock-ups, and proven by wet-testing of the completed Habitat Modules.

The Modular Habitat system plays a key role in the overall life extension strategy for the Ninian Southern Platform, ensuring that the costs, risks and production downtime associated with future subsea repairs are minimised.