bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cutting Edge Seismic Technology Boosts Mars B Project by Delivering Exploration, Maturation and Development of Two Subsea Fields Tied Back to New Olympus TLP at a Top Quartile Pace
Authors: Sloan Robert F. , King Kevin M. 
Published: June 2014

Deimos, discovered in 2003, consists of numerous high quality oil reservoirs which increased the depth and subsalt extension of the Mars Field. It was followed up one year later by the up-dip dry-hole exploration well, Boreas. The subsurface results from Boreas were sufficiently disappointing to discourage further exploration in the subsalt portion of the Mars Basin. Both Deimos and Boreas were drilled using our best seismic of the time, PrestackDepth Migrated narrow azimuth (NAZ) streamer data. However this data was insufficient in imaging the structural and stratigraphic complexities apparent in this subsalt environment.
Following the success of the Deimos Phase 1 Development, Shell acquired its first Ocean Bottom Seismic – Full Azimuth (OBS) survey in 2007 to plan Phase 2 of Development. The improvement in the seismic image over Deimos and the surrounding subsalt area was dramatic. The OBS along with an anisotropic corrected velocity model seismic data set resulted in a step change in our geologic and stratigraphic understanding of the subsalt portion of the Mars Basin. Two exploration opportunities, West Boreas and South Deimos were quickly identified. The new data also indicated that the Boreas dry-hole missed West Boreas by &lt; 200 ft, and drilled through a previously un-imaged fault which cut out most of a high quality reservoir sand.
The OBS seismic image facilitated a high quality interpretation of the subsalt portion of the Mars Basin that not only enabled the rapid maturation of the exploration opportunities, but also allowed for the sanctioning of the Mars B subsea development with only one penetration into each of the newly discovered fields. The seismic-to-well ties had an excellent match and instilled high confidence in our seismic interpretation and geologic modeling which enabled Shell to progress the Mars B subsea development at a rapid pace.
One of the largest risks to any subsalt development is the uncertainty of the target reservoir's quality, extent and structure. To date, two of the six proposed subsea development wells have been drilled, and the well results have confirmed our confidence in the quality of the OBS seismic. These subsea wells will be tied back to Mars B's newly installed Olympus TLP and deliver its first oil in 2014.
Mars B Development - Well Challenges & Solutions - An Evolution of Traditional Well, Rig and Facility Design
Authors: van den Haak Arno L.M. , Cameron Wylie J. , Grant Lisa S. , Japar Nor Janiah H. , Reagins Deandre R. 
Published: June 2014

The Mars-B project is Shell's sixth GOM TLP development and demonstrates Shell's commitment to GOM. The Mars-B project is aiming to unlock resources over the next 50 years through the deployment of a new 24 slot TLP structure (Olympus TLP) and additional subsea infrastructure for the West Boreas/South Deimos fields. The Olympus DVA rig is a novel platform drilling rig designed specifically to meet the execution requirements of complex Olympus DVA well designs. The well design and associated equipment must accommodate the 50 year design life, the longest design life of a TLP in Shell's history.
This is the first development to incorporate post-Katrina environmental design loads and new regulatory design requirements. Project challenges include numerous technical challenges pertaining to well designs for 24 DVA wells targeting over 50 horizons spanning 10, 500 ft TVD to approximately 25, 000 ft TVD encompassing both highly depleted brown field and deeper virgin pressure formations.
The Olympus DVA well trajectories range from near vertical to high angle extended reach both through sediments and through salt penetrations. Rig and surface facilities must be designed to address multiple challenges present to ensure well and facility integrity, reservoir isolation and desired well construction objectives are met. This requires successful development and deployment of novel technologies and world class systems. The design requirements have resulted in an evolution of traditional well designs which in turn drives novel rig and surface facilities requirements.
A high level overview of the design challenges and the resulting surface equipment requirements will be discussed. This includes rig equipment requirements to meet the specified execution directives, the development of an innovative drilling riser concept, added systems optimization to increase safety and overall execution efficiency.
New Hydrate Anti-agglomerant Formulation for Offshore Flow Assurance and Oil Capture
Authors: Sun Minwei , Firoozabadi Abbas 
Published: June 2014

Abstract
Gas hydrate formation often blocks flowlines in oil and gas production due to low temperature and high pressure, and may result in serious safety and environmental problems. Risk management of gas hydrate is a major challenge in offshore hydrocarbon production. Anti-agglomerantion (AA) is an attractive option because of effectiveness at low dosage and high subcooling. Hydrate particles are kept small and allow flow in slurry form, therefore avoiding plugging in flowlines. Until recently various authors have believed that anti-agglomeration is based on the formation of water-in-oil emulsion. We have demonstrated that the process can occur without emulsion or through oil-in-water emulsion. We have shown anti-agglomeration in methane and in one natural gas system. In this work, we demonstrate the effectiveness in two natural gases and in a crude oil system. In the crude oil, the effectiveness is shown in both water and in brine. These demonstrations pave the way for vast potential applications in both offshore flowlines and in oil capture from the seabed.
Early Production Systems – When Do They Make Good Sense for Your Project?
Authors: Coopersmith Ellen M. , Burkholder Kent , Mendoza Luis 
Published: June 2014

Abstract
Many teams believe an Early Production Systems(EPS) will be valuable for their offshore projects, but struggle when asked to make the business case. Typically, if there is value in an EPS it is derived either from early resource sales and or providing information on key dynamic uncertainties in order to decide whether and or how to optimize development. The latter often being the driver of value.
As the industry moves to deeper and deeper waters, getting quality information on dynamic uncertainties gets more expensive and for some, cost prohibitive. As a result, companies either need to be willing to sanction expensive developments with sizable risk (potentially bearing a higher risk tolerance) or find ways to make extended tests or Early Production Systems compelling financially in addition to technically.
The key dynamic uncertainties teams often want to reduce before sanctioning development are compartmentalization, natural or enhanced drive mechanism and or initial production rate. Each is linked to different decisions which can be optimized given uncertainty is reduced. Compartmentalization directly affects the number of development wells, drive mechanism affects the need for injection, associated well count and facilities and initial rate directly affects facility size.
Ultimately, the key to deriving value from an EPS resides in its design, which includes the type of EPS vessel, the associated fiscal terms and the quality of the information gathered from the early production system prior to finalizing development (Mastrangelo, et al. 2003, Valenchon, et al 2000). This includes the tests and data to be collected, as well as the duration of the production period prior to making the important development decisions.
This paper discusses the design aspects which drive value of an EPS and introduces a stepwise approach for teams to follow to frame and evaluate dynamic tests and EPS design options using a generic deepwater case example. Alternatives ranging from a drill stem test (DST) to an EPS to a tie-back are compared and sensitized to understand under which conditions each option might be worthwhile, ultimately providing information for an informed decision.
50 Reservoirs, 48 Well Slots & Two TLP's – Maximizing Recovery From the Deepwater Prolific Mars Field
Authors: Derek Newberry 
Published: June 2014

The Mars B Development is by IPA definition an " Industrial Mega Project" that is within the execution phase. The development is focused on the addition of new infrastructure to the Mars Field located in the Mississippi Canyon protraction area of the Gulf of Mexico. The development operated by Shell (71.5%) with BP as a Working Interest Owner (28.5%) can be summarized into three major infrastructure components:The Olympus Tension Leg Platform (TLP)West Boreas/South Deimos Subsea Tie-backDedicated oil and gas export pipelines and the West Delta 143C Shallow Water Platform.
The Mars B Development is a first for Shell in the deepwater GOM, in that it represents the first occasion that a second significant production and drilling facility (Olympus TLP) has been installed to complement existing infrastructure (Mars TLP).
The Mars Field is a true deepwater giant with close to 4 billion boe hydrocarbons in place. The Mars TLP was brought on production in 1996 and to date (01.01.14) has produced over 700mln boe. The Mars TLP, a 24 well slot Tension Legged Platform with multiple subsea tie-backs, has a significant track record in developing the field. Constraints, such as the number of available well slots and capacity for future subsea tie-backs, limited its expansion. The structural limitation of the Mars TLP was a main driver for the need to install a second TLP, the Olympus TLP.
Once the Olympus TLP is brought on production in 2014, the Mars Field Depletion plan can be characterized by the following numbers and the unique challenges of integrating the following:One Deepwater Giant Field50+ discrete Hydrocarbon reservoirsTwo Tension Legged Platforms48 Platform well bores + 6 subsea wellsField life extended to 2050(+)
This presents the unique challenges of developing a holistic and evergreen Mars Field Depletion plan that captures the synergies provided by two production and drilling facilities on a single field; and further the ability to extend the Mars Field life to 2050(+) results in a depletion plan that will ensure that we maximize the recovery from a key GOM resource base.
Serpentina FPSO Mooring Integrity Issues and System Replacement: Unique Fast Track Approach
Authors: Bhattacharjee Subir , Majhi Sai , Smith David , Garrity Robert 
Published: June 2014

Abstract
This paper provides an overview of the first documented industry intervention involving replacement of a permanent mooring system due to seabed trenching near the suction piles. Another unique aspect of this intervention was the use of readily available hardware for installing a temporary mooring system to minimize operational risks. Brown-field interventions are often required to address mooring integrity issues or life extensions. These are more challenging than new (green-field) designs and installations due to existing infrastructure. This includes the Floating Production Storage and offloading System (FPSO) hull, risers and flowlines. Also, the production shutdown has to be minimized while maintaining operational safety. The present paper summarizes mooring integrity issues and the complete mooring system replacement of the Serpentina FPSO offshore Equatorial Guinea (EG) within ten years of service. A partial mooring replacement campaign was initially planned to address wire rope degradation and chain chafing damage on selected legs. However, seabed trenches near the suction piles, discovered at a late stage, required a complete change in the project plans. The revised scope included installation of a new set of anchors and off the shelf mooring hardware for all nine anchor legs, to address the risk of potential mooring failure in an expedient manner. Installation of new anchors and mooring lines for this project was executed in roughly 6 months from the discovery of the trenches. The planning and execution of this fast track project is discussed, along with the multiple challenges that needed to be addressed. Industry has limited experience in seabed-trenching related mooring issues and associated mitigation. The importance of seabed trench inspection for taut-mooring systems is discussed. Finally, lessons learned in planning and execution of the project in safe and expedient manner is summarized.
Flow Assurance Solutions and Control Systems for Long Step Out Subsea Production Systems
Authors: Gharaibah Emad , Parsons Robert 
Published: June 2014

With the increasing need to operate Subsea Production Systems (SPS) in harsh environments, comes a need to produce with long distances (step out) from shore and in potentially deep water applications from the process plants, eliminating the need for manned offshore production units. This presents challenges for the flow assurance aspects to maintain high production regularity, asset integrity and thereby demands highly reliable control systems to ensure this happens. The Snøhvit project in the Barents Sea is a milestone in subsea oil and gas development, with a record breaking offset (147Km) and all subsea facilities tied-back to shore, without any surface-piercing structures such as platform or floating production facilities, with a consequent dramatic improvement in environmental impact. GE has further qualified the fibre optical control systems to 220Km. A similar control system is also now to be used for the Gorgon/Janz development. It is also envisaged that these systems can be utilised in offshore Tanzania.
The key flow assurance aspects to take into consideration for such a system are:Handling different operating regimes of transporting of multiphase fluids over the field lifeTransporting High viscous fluids at low pressure or temperature addressing Wax, Hydrates formations, mitigations and remediationStrategies to increase the operating envelope including shutdown or restart operations and the impact of operating modes on the production and system integrityFlow assurance challenges due to uneven seabed
In the recent years there has been increased focus on the aim for both standardisation and simplification, such that there has been new developments of new applications such as virtual flow meters. GE has developed this as part of the flow assurance aspect along with potential SMART system applications.
The presentation focuses on the technical and logistical achievements in executing this ultra-long offset subsea-to-beach project and the interaction with flow assurance requirements.
On the Shape of the Wind Wave Spectrum of the Norwegian Continental Shelf
Authors: Houmb Ole Gunnar , Øian Torkel 
Published: June 2014

Abstract
The ultimate aim of this work is to contribute to the understanding of the North Sea wave spectral shape, with special emphasis on design conditions.
More than 6000 wave spectra from the North Sea have been analyzed. The JONSWAP 1 model is fitted to the spectra using a least squares technique with a varying number of free parameters.
We observe a systematic tendency for the JONSWAPI model to fit empirical spectra better than that by Pierson and Moskowitz2.
Methods are proposed for estimation of JONSWAP spectral parameters when the zeros order moment of the spectrum is known.

Introduction
Present knowledge of the shape of the wave spectrum can be summarized as follows:
Under idealized conditions the spectrum has a standard shape that can be described by a set of shape parameters.
The shape of the spectrum of a fully developed sea in deep water is given by the PiersonMoskowitz2 spectrum. It is therefore quite natural that this spectrum includes wind speed but not fetch as a scale parameter.
For growing sea states the spectral shape is given by the JONSWAp1 spectrum. Dimensionless fetch is therefore one of the scale parameters of this spectrum.
The JONSWAP model spectrum is recommended by the Norwegian Petroleum Directorate in computing the interactions between waves and marine structures. However, the values of the JONSWAP model parameters are subject to discussion and disagreements. The main purpose of the work described in this paper has been to estimate the JONSWAP model parameters on the basis of a large number of wind wave, samples.
Efforts are concentrated on design spectra of high sea states. As extreme design sea states are likely to occur during growing or fully developed wave conditions, the analyses were concentrated partly on growing sea states. It is assumed that results on spectral shape from growing seas can be extrapolated to the extreme design sea states.
Based on more than 6000 spectra the JONSWAP model has been parameterized in two slightly different ways that are both useful for engineering applications. Both methods are presented in this paper.

The Design Sea State
It is common practice to define the design sea state as an event having a return period of 50 or 100 years. In the North Sea this corresponds to Hs=15 m and individual waves of height from 30 to 33 m. The period corresponding to the spectral peak is estimated at 15 to 20 s.
Such high and long waves will most likely appear during or close to the peak of a generation phase with strong winds of long duration and fetch.
If swell is present it will most probably be mixed with the wind sea and therefore not appear as an independent spectral peak. The energy of swell present in a design sea state will be small compared to that of the wind sea. We therefore assume that the shape of a design wave spectrum is not influenced by swell, and we assume also that it is satisfactorily described by a model spectrum like the JONSWAP.
Hazard Management and Safety Management Systems: A Structured Approach
Authors: Bentley P.O. , Stockley J.D. 
Published: June 2014

ABSTRACT

Description
The publication in November 1990 of the Public Inquiry Report by Lord Cullen into the events leading up to the Piper Alpha disaster in the UK North Sea on 6th July 1988 highlighted to the offshore industry that safety is "crucially dependent upon management and management systems". Lord Cullen proposed that oil companies should develop Safety Management Systems (SMS) that should "set out the safety objectives, the system by which these objectives are to be achieved, the performance standards which are to be met and the means by which adherence to these standards is to be monitored". SIPM (Shell Internationale Petroleum Mij. The Hague, Holland) fully accepts that the recommendations of the Cullen Report apply not only in local N. Sea application but in principle worldwide. This paper sets out the approach adopted by SIPM in the subsequent formalisation of their SMS guidelines). The approach is based upon a number of previous and existing safety and business improvement initiatives and is both compatible and complementary to activities already in progress within the Operating Companies.

Application
SIPM have to provide guidance to Operating Companies in very different technological environments, ranging from the N. Sea to the technically simpler and more clement S. China Sea as well as onshore in the deserts of Oman. The approach developed hence concentrated upon ensuring compatability with local conditions and upon the basic tenet that all hazards should be clearly understood by the "owner" or operator of the facility.
1) SIPM is a Shell Service Company which provides advice and services 00 Shell Operating Companies other than Shell Oil Company of the United States and its overseas subsiduaries.
The structure presented for hazard management is applicable for both new projects and existing facilities, and is aimed at control of safety critical operations. It maintains a strict focus upon the business introducing essential controls required for a safe operation on the basic fundamental criteria of necessity and sufficiency.

Results
Trials have been carried out in selected Shell Operating Companies and the SMS basis derived from this work is now being proven on a wider scale.

Significance
The development of SMS guidelines within SIPM for the use by Shell E&P Operating Companies has relevance not only to the onshore and offshore oil and gas industry but is equally applicable to all involved in the management of safety.

1. History of the Cullen Report and the development of Safety Management Systems
On 6th July 1988, an explosion occurred on the Piper Alpha production platform in the UK sector of the Northern North Sea which led to a course of events leading to the destruction of the platform and the loss of 167 lives. The UK government required Lord Cullen, a Senator of the Scottish College of Justice, to hold a Public Inquiry into the disaster.
Pile Load Tests In Dense Sand: Analysis Of Static Test Results
Authors: Al-Shafei K.A. , Cox W.R. , Helfrich S.C. 
Published: June 2014

ABSTRACT
This paper describes test results from two tension tests and one compression test on 0.61 - m-diameter steel-pipe piles driven to 18-m depth in dense sand. This paper is a sequel to "Pile Load Tests in Dense Sand: Planning, Instrumentation, and Results, Paper 4847, OTC (1985)". The piles were fully instrumented with strain gages along the pile walls. Shaft frictions and pile movements from the test are analyzed. Results confirm that piles driven into dense sand of the Arabian Gulf can support loads that are up to six times the design capacities calculated by industry-accepted procedures.

INTRODUCTION
More than 1000 piles have been installed in the Arabian Gulf, Saudi Arabia. The piles vary in size up to 1.22 m in diameter. Design penetrations range up to 80 m, however most are between 20 m and 40 m. Design ultimate loads are usually less than 22 MN, but range up to 50 MN. Soil conditions vary significantly in the Arabian Gulf, but in general, the soils are strong enough so that pile installation is usually a difficult and uncertain task. A range of hammer sizes and types have been used to drive these piles. Most were single acting steam hammers with rated energies ranging from 54 KN-m to 700 KN-m. For a recent installation a hydraulic hammer with an energy of 1000 KN-m was used to drive the piles to design penetrations.
One common difficulty of driving piles in the Arabian Gulf arises when piles reach a penetration less than the design penetration and can not be advanced any farther (refusal) due to the presence of strong soil at the site. Another problem occurs when the pile is driven to the design penetration without developing a significant capacity.
In 1982, seventeen driven well conductors were pulled out of three platforms in the Safaniya Field, Arabian Gulf, Saudi Arabia. These conductors were removed by pulling with a 500 ton capacity crane on the jack-up barge, ARB-I. The conductors could be pulled only after driving downward with a hammer to reduce the soil friction along the pile wall. The ultimate tensile loads required to pull the conductors ranged from 1.5 to four times the computed tensile capacities using API RP2A(1982).
The unexpected hard driving, high resistance of the conductors to tensile loads and high cone tip resistance in these dense sands led to a full scale pile load test program.
This paper discusses the results of full scale tests on two piles. One pile was tested only in tension, and the second pile was tested in compression and then tension. Also presented are the measured load distribution and the corresponding unit skin friction for all the tested piles. Details of the test program were discussed in Helfrich et al (1985).