bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full-Azimuth Marine Acquisition Using the Coil Shooting Technique
Authors: Brown Gordon , Palmer Ed 
Published: December 2009

Abstract
In this paper, we describe a new single-vessel full azimuth (FAZ) seismic acquisition technique named Coil Shooting*. Whereas conventional marine 3D seismic acquisition records only a narrow azimuth of seismic traces, this new technique acquires FAZ data. We show data examples from extended field trials, review data processing challenges such as noise removal and multiple attenuation, and discuss survey design.
The Coil Shooting technique is a development of wide-azimuth (WAZ) acquisition. Over the last five years WAZ has been used extensively in the Gulf of Mexico to produce enhanced images in the subsalt section. However, WAZ marine acquisition using towed-streamer technology still requires the use of multiple vessels (typically three or four vessels). In the North Sea and surrounding areas there are significant advantages in deploying a single vessel, as multivessel operations are subject to availability and logistical constraints. FAZ acquisition records over the full range of azimuths and offsets. In the case of Coil Shooting, this is achieved by sailing the vessel in a series of circles or coils.
WAZ and ocean-bottom cable seismic operations are proven techniques for improving illumination. Results from recent modelling and field tests demonstrate that the Coil Shooting technique has similar capabilities.
Although the idea of recording while sailing in circles dates from the 1980s, Coil Shooting requires modern streamer positioning and control techniques. We demonstrate that limitations from the 1980s have now been overcome and show that FAZ recording has the potential to improve imaging of geological structures that continue to cause interpretation problems in the European continental shelf, e.g., subsalt, salt flank, and Jurassic tilted fault block structures.
Offshore Crew Supply–Modern Marine Options Challenge Helicopters
Authors: Brittan D. , Douglas S. 
Published: December 2009

Abstract
The helicopter has long been regarded as the default choice for crew supply due to its speed, flexibility and passenger comfort. Marine crew transportation has until recently being regarded as slow and more hazardous. Three specific technological advancements, high speed hull design, DP2 automatic vessel station keeping and advances in transfer capsule design, now offers high speed marine crew supply, with levels of passenger safety and comfort that exceed helicopter transfers. Utilizing the ‘state of the art’ CrewZer Class vessel, this new crew supply solution is leading many operators to re-evaluate their crew supply options.
A good crew supply solution should provide high levels of safety, speed and reliability, as well as operational flexibility. As offshore development cost rise and other assets mature, there is increased pressure to reduce operating costs, whilst attending to crew welfare and morale. The CrewZer access solution can deliver up to 30% savings on logistical costs, whilst enhancing safety or passenger welfare.
The first CrewZer Class vessel, the Seacor Cheetah (the fastest offshore support vessel ever built) was introduced to the market in February 2008. Voted ‘American Ship of the Year’, it has an aluminum catamaran hull, capacity for 149 passengers and a cruising speed in excess of 40 knots. It's DP2 station-keeping and wide stable hull provide an ideal platform for personnel transfer operations. The vessel also utilizes a custom designed 9-passenger advanced transfer capsule. The entire system is expected to provide one of the safest crew transfer solutions in the industry. This integrated solution provides the following additional benefits:- An ideal emergency evacuation tool (e.g. hurricanes), capable of the rapid evacuation of large crews. This allows operators to delay evacuation decisions, possibly avoiding unnecessary shut downs, without compromise to safety.A high speed vessel suitable for early response to offshore fire, equipped with two large fire monitors.150 ton of deck load optimized for fast track logistic support.Enhanced vessel stability which increases the operational weather window for transit and loading operations.
After over a year in operation and tens of thousands of successful transfers, the system has been thoroughly field proven. This paper describes the system in full, the experiences of the first year in operation and goes on to explore likely future developments in crew supply operations.
Investigation of Production Tubing Coupling Failures From a Suspended HPHT Well
Authors: Hillis David J. , Eddy Michael , Cassagne Thierry , Ligertwood John 
Published: December 2009

Abstract
The challenging nature of high pressure high temperature (HPHT) oil and gas production wells has necessitated the development of new technologies and the use of high performance materials and fluids. Inevitably, this has resulted in some unexpected phenomena and field failures have been responsible for stimulating research into several aspects of corrosion and environmental cracking associated with HPHT production.
This paper details the investigation of production tubing coupling failures, which occurred during the retrieval of cold worked 25Cr duplex stainless steel production tubing. The tubing had been present in a suspended well for two years and was being retrieved as part of a workover operation. The investigation was conducted to determine the nature of the failures and identify contributory factors and has resulted in recommendations for long term use of formate brines at high temperature.
Harding Central–Achieving 74% Recovery
Authors: Zhang P. , Green S. 
Published: December 2009

Abstract
Harding Central is a high permeability turbidite reservoir in the Central North Sea. It has been produced with water injection for pressure support and gas injection for disposal of evolved gas since 1996. The initial oil in place has been tightly constrained by high quality seismic, high density of well penetration and various dynamic data. The production data show that we have already recovered 70% of the oil initially in place by end of 2008. We expect the reservoir to achieve 74% recovery without further infill drilling by the end of field life.
We attribute this extremely high recovery factor partly to high rock quality with low Sor, and more importantly to the good understanding and effective management of the reservoir. This paper will summarise key methods by which we have achieved such a high recovery factor, namely (1) good well design and placement to ensure high rate and avoid early coning; (2) 4D seismic used to manage fluid contacts and identify unswept area for infill targets; (3) repeated GOC logging to underpin reservoir management strategy; (4) solid reservoir engineering to support business decisions; and (5) stable production.
North West Hutton: Decommissioning the North UK's Sea's First Large Platform With a Fixed Steel Jacket: Topsides Removal
Authors: Farrow Chris R. , Harris Glyn , Groot Jan 
Published: December 2009

Abstract
During the summer of 2008, Heerema's semi-submersible crane vessel Hermod and a small fleet of transportation barges successfully removed the topsides modules from the North West (NW) Hutton platform. The NW Hutton platform was commissioned in 1983 and lies in the northern North Sea in 143m of water roughly half way between Shetland and Norway. The 17,000 tonnes eight leg steel jacket supported a modular topsides with a combined dry weight of approximately 20,000 tonnes. Removal of NW Hutton represents one of the most challenging decommissioning projects tackled by the offshore industry to date.
This paper describes the preparation phase and actual removal of the topsides, including the associated transportation and load-in phases. Topics covered include: History of N W HuttonDecommissioning PhilosophyNormally Unmanned Installation PhaseTopsides Removal; Engineering and its ChallengesTopsides Removal and Transportation; Execution of Work and its ChallengesKey Lessons
Overall the topsides removal project was completed safely with no significant Health Safety or Environmental issues despite the very significant offshore scope. Success factors included: A dedicated client team ensuring compliance with standardsPre-agreed go/no go gates and the authority for those gatesextensive planning,detailed on-site reviews, andclose co-operation between HMC and BP.
The First all Electric Subsea System on Stream: Development, Operational Feedback and Benefits for Future Applications
Authors: Gerardin Pierre , MacKenzie Rory , Van Den Akker Jan 
Published: December 2009

Abstract
In September 2008, Total E&P Netherlands BV and its partners started up production from K5F field with the first all electric subsea production system. The field is located in the Dutch sector of the North Sea, and is tied back to a platform (K6-P/C) located18 km away. The K5F development consists of a manifold designed for 3 wells and a potential step out. Initial installation includes 2 subsea X-Trees with associated controls.
The all electric system uses the concept of end to end redundancy, consistently from surface to the subsea actuators, with the objective to maximize operational availability. The system uses high voltage DC electrical supplies, to minimize power losses and umbilical cross section. The system does not rely on batteries or accumulators and hence allows unlimited actuator operations. The true environmental friendly design fully complies with the Zero discharge concept.
The joint paper will describe the experience gained during development, qualification and commissioning, as well as the system operational performance during the first period of production. Operational results will be evaluated against key initial objectives: Simplification of subsea control systemImproved monitoring of system status and condition
The paper will also discuss the following inherent advantages of the all electric technology applied to subsea production systems: Increase in potential field offset distanceReduction of umbilical size, complexity and cost
Consideration will be given to the benefits of this technology when applied to HIPPS systems and deepwater subsea processing applications for which fast acting subsea process control valves may be required: Significantly reduced valve actuation timeIncrease in reliability and availabilityEnhanced monitoring allowing superior process control
A Practical Methodology For Evaluating Appalachian Basin Waterfloods
Authors: Freeman David C. 
Published: December 2009

Abstract
The Appalachian Basin, the oldest domestic United States producing area, is home to a number of active waterfloods and even more waterflood candidates. Efforts to evaluate existing floods and assess new opportunities, however, are often hampered by scant reservoir rock and fluid data, as well as incomplete, or nonexistent, fluid production and injection records.
The purpose of this paper is to illustrate, through the study of a case history, a practical methodology for evaluating a 30-year old Appalachian Basin waterflood, beginning with culling original in-house documents and well files and concluding with numerical simulation. The studied flood is the Richardson Unit Waterflood (Calhoun and Roane Counties, WV).
Swellable Packers in Unique Horizontal Completions Solves Difficult Challenges in Offshore India Vasai East Field
Authors: Kalyani Tejas , Avtar Ram , Srivastava A. K. , Singh Ram Suresh , Badwaik D. Z. 
Published: December 2009

Abstract
Oil and Natural Gas Corporation (ONGC) operates the Vasai East Field in western offshore India. The reservoir is challenging to drill and complete because of the inherent risks of gas and water coning, permeability differences, and declining reservoir pressures. An innovative horizontal completion strategy for new wells to meet the many unusual challenges was required. The need for appropriate zonal isolation was identified after the wells in the Vasai West Field had been completed without segmentation in the open hole. The requirements included:
Oil production without breakthrough of gas or water Effective hydraulic seal in washed-out hole conditions Contingency options for intervention, if needed Equipment to withstand high bottomhole static temperature.
This paper describes how the challenges were met using swellable-packer, high-temperature isolation systems placed between perforated tubing/sliding-sleeve circulating devices and blank pipe spaced out across the oil-bearing zones. The swellable packer systems were located at the ends of each facies change to isolate the local high-permeability zones. Swellable packers use expanding rubber around the packer mandrel that expands to seal the annulus and create a permanent seal when it contacts liquid hydrocarbon or water in both cased or openhole environments.
Five wells have been completed in Vasai East field to date with swellable packers in conjunction with pre-perforated liners or sliding sleeves. PLT logs have been run in one of the wells post completion, and isolation has been verified. Low water cuts and low gas/oil ratios (GOR) also verify that the packers isolate the various sections of the wells as planned. On the success of these completions, this technology is currently being planned for ONGC's completions in other fields.
Expandable Liner Hanger Drill-in Capability Provides Reliable Solution for North Sea Case History
Authors: Montañez Carlos Mario , Jensen Søren Lundgren , De Clute-Melançon Daniel 
Published: December 2009

Abstract
The combination of unstable, highly pressured formations overlaying depleted reservoirs or low-pressure formations continues to challenge the drilling of oil and gas wells. A primary concern is the possible collapse of the formation due to the lack of mud weight window resulting in stuck pipe and incapability to run casing to depth, significantly impacting operational cost.
One identified and proven solution for this challenge is the implementation of a "Drilling with Liner technique" (DwL). If the formation collapses during this operation, the casing is already in place, and thus, the weak formation is cased off.
Due to the challenges intrinsic to DwL, the need for specialized drilling tools with sufficient mechanical capabilities such that the formation becomes the only limit has been identified.
This paper will discuss one of these specialized drilling tools – an Expandable Liner Hanger (ELH) that has elastomeric elements bonded on to the hanger body. As the hanger body is expanded, the elastomeric elements are compressed and sealed against the casing. This provides gas tight liner-top pressure integrity as well as delivering impressive tensile and compressive load capacity on setting. The system can be set up for liner drilling, which enables the liner to be drilled into the low pressure reservoir, cemented, and the liner top to be isolated upon setting.
Recently, an operator in Denmark used an ELH in combination with a liner to successfully drill into a formation that had caused problems in previous attempts. Advances made to an ELH system to address the various contingency activities, job planning methodology, activities that took place, and lessons learned from the job will be presented.
Wellbore Instability Predictions Within the Cretaceous Mudstones, Clair Field, West of Shetlands
Authors: Narayanasamy R. , Barr D. , Milne A. 
Published: December 2009

Abstract
Wellbore instability within Cretaceous mudstones overlying the Clair oilfield has prevented successful drilling of high-inclination wells in the past. Detailed investigations of the possible reasons for borehole failure led to a decision to cut two cores within the unstable interval and carry out laboratory testing to investigate the failure mechanism. Analysis of rock failure based on a "planes of weakness" theory fitted previous drilling observations. This theory has been applied primarily for layered hard rocks (e.g. mining and tunneling) and is here extended to significantly weaker mudstones showing strength anisotropy. Minimum required mud weight predictions were made for a range of well configurations. The results of this study were used to plan an Extended Reach Drilling (ERD) development well targeting a previously undeveloped part of the Clair field. The new well was successfully drilled, cased and brought on stream within budget, in 2009.
This paper describes the basic geology of the field, rock properties of the Cretaceous mudstones, details of laboratory tests conducted and analyses carried out. Cretaceous mudstones of the Clair field are characterized by low strength and minor anisotropy. Various rock tests were conducted on core to define their failure behavior: Unconfined Compressive Strength (UCS), single-stage triaxial strength and multi-stage triaxial strength tests were conducted, all at various angles to bedding. In addition, the effect of mud invasion was analyzed by performing a multi-stage triaxial test in drilling mud at high pressure. The analysis used commercial software to evaluate borehole instability in a rock medium that fails along weak planes. Minimum mud weight requirements derived from this analysis were compared with previous drilling experience and subsequently used for predicting mud weight required to drill an ERD well. Lessons learned from the successful drilling of this well will be applied in future Clair development wells and may be of relevance elsewhere.
Produced Water Management in Mature Field Operation
Authors: Hansen Lars Hvejsel 
Published: December 2009

Abstract
From 2002 to 2008 the oil discharge has been reduced by 10% despite an increase in the produced water discharge of 230% (Figure 1). This has been achieved by reducing the average oil concentration in the produced water to 9 mg/l in 2008. Significant reductions have especially been recorded from 2007 to 2008. The reductions are primarily a result of the following initiatives.
Rerouting of recycles - rerouting of e.g. used H2S scavenger have improved separation and produced water treatment Individual KPI's for the different produced water treatment systems On-line cleaning of the produced water treatment systems System analysis - continued optimisation of the separation and produced water treatment systems
This paper presents the significant reductions that have been achieved primarily through technical improvements and better operation of the installed equipment.
CO2-Brine Surface Dissolution and Injection: CO2 Storage Enhancement
Authors: Eke Paul Emeka , Naylor Mark , Haszeldine Stuart , Curtis Andrew 
Published: December 2009

Abstract
Carbon capture and storage (CCS) is capable of reducing atmospheric emissions of greenhouse gases from coal or gas fired power plants. The upward buoyancy of dense phase carbon dioxide (CO2) in deep reservoirs means that sites need to be chosen with a methodology which has carefully evaluated details of performance during and after the injection process. Standard methods of site evaluation for saline aquifers focus overwhelmingly on the aspects of geological containment and monitorability. Also important to storage site performance is the engineering design of transport and injection. Transport to storage in offshore saline aquifers is normally expected to be by pipeline. There are several proposed methods of CO2 injection, for example as a dense phase, in the liquid or supercritical phase, as water-alternating gas cycles, or as carbonated brine. These result in different migration pathways in the aquifer during the short term (1-50yr) and storage distributions in the long term (1,000 – 10,000 yr). To develop a methodology suitable for making informed decisions for aquifers offshore of the UK, several of these different methods are being evaluated. A chemical engineering and reservoir engineering approach will be used to define some of the important surface transport and subsurface interactions. Important surface features may include the energy balance, location, sizing, materials specification and costing of surface equipment for mixing and transporting CO2.
Pipe Rotation Improves Hole Cleaning and Cement-Slurry Placement: Mathematical Modeling and Field Validation
Authors: Moroni N. , Ravi K. , Hemphill T. , Sairam P. 
Published: December 2009

Abstract
Placing the cement slurry in the entire annulus, in both the wide and narrow sides, is essential to achieving effective zonal isolation. Well conditions, such as deviated wellbore geometry, eccentric annulus, and gelled drilling fluid, pose unique challenge in achieving this objective.
It is known in the industry that pipe movement helps improve hole cleaning and cement-slurry placement. However, the quantitative effect of pipe rotation on hole cleaning and cement-slurry placement for a given eccentricity, flow rate, and geometry was not well studied. Hence, it was difficult to design a primary cement job where the effects of all these parameters were considered at the same time and optimized for best results.
The effective velocity and pressure drop in an eccentric annulus with and without pipe rotation is modeled for Herschel-Bulkley fluid. This is then extended to evaluate the effect of pipe rotation on hole cleaning and cement-slurry placement. The modeling clearly demonstrates the improvement in hole cleaning from pipe rotation in an eccentric annulus. Now there is a tool available to study the interaction of various factors on hole cleaning and optimize them for the well in question.
The results from the modeling study have been compared with field data. The comparisons show a good match between the improvement in cement-slurry placement predicted that was inferred from the cement bond logs. The study clearly indicated the importance of using representative rheological model and input values.
The modeling results and field validation are presented and discussed. The work presented in this paper should help the industry optimize the various factors during a cement job to help maximize hole cleaning and cement-slurry placement in the wide and narrow sections of the annulus. This should help in achieving zonal isolation for the life of the well and reduce operating expenses by reducing remedial jobs.
Platform Re Design for CO2 injection: Process and Safety Engineering Challenges
Authors: Hargreaves John H. 
Published: December 2009

Abstract
There has recently been Conceptual and FEED studies to convert existing hydrocarbon producing facilities to CO2 injection. Often the most cost effective option for CO2 injection is when combined with enhanced hydrocarbon recovery. This new operation, however, increases levels of risk; the additional CO2 gives rise to a new asphyxiate hazard, while the increased CO2 in the Process stream brings its own production and safety trade-offs. This paper addresses these hazards and the conundrum of optimising production and safety. Presented herein is an integrated Process and Safety Engineering approach to control the risks and develop a decision making framework to allow confidence for the safe design of future CO2 injection Projects.