bluuebunny/crossref_metadata_2025 huggingface dataset:
Riserless Drilling with Casing: A New Paradigm for Deepwater Well Design
Authors: Kotow Kenneth James , Pritchard David M.
Published: July 2009

As the deepwater Gulf of Mexico (GOM) drilling operations move into deeper water and well depths there has been a lack of consistent and sustained drilling performance improvement. This is an evaluation of the GOM deepwater wells in an attempt to understand the reason for this poor drilling performance and propose a solution to adapt the well designs for the specific challenges of deepwater drilling. Execution of these very expensive wells, which often fail to achieve objectives, or worse are lost, requires a step change in drilling performance.

The complex deepwater drilling environment has pushed the typical offshore well construction design model to its limits. Many of the well design philosophies and the well equipment itself are not well suited for the unique deepwater drilling environment. This requires step changes in well design philosophy, and the understanding and acceptance of the associated risks of implementing new practices. The acceptance of change has been a monumental driver in our industry. The goal is to ensure that exploration and development of oil and gas continues to be feasible in this industry subject to volatile commodity prices and ever increasing costs. A paradigm shift in well design philosophy that involves managing the drilling risks in the shallow hole sections, where the well costs are minimum, rather than the current practice of incurring risks after significant investment has been made, is critical to future success and economic viability of deepwater drilling.

The well design model presented uses the shallow and rapid growth of the pore pressure/fracture gradient (PP/FG) environment to optimize casing seats. Drilling with Casing (DwC) is an enabling technology that can be a mitigant for managing shallow hazards. The fundamental premise is to use this technology to set the first, and possibly the second, casing strings significantly deeper than current practice.

The proven ability of DwC to mitigate many similar drilling hazards as those encountered in deepwater drilling would allow the casing seats to be based upon the prevailing PP/FG environments, rather than being influenced by the shallow hazards.

This could allow for the following well design improvements:Larger annuli below salt for improved drilling margin management.Less total casing strings in the well.More use of conventional casing strings sizes for drilling and geological contingencies.Enhanced planning and use of solid expandable systems.Decreasing the risk of not obtaining at least an 8-½ in. ID completion, essential for economic success in deepwater environments.Batch drilling into salt, which optimizes horsepower as well as cost, utilizing smaller capacity rigs for the lighter hook load casing lifts.
Bit Selection Using Mathematically Modeled Indices Deliver Significant Improvement in Directional Drilling Performance
Authors: Barton Steven Paul , Card Kirk Dean , Nwachukwu David , Cozon Bertrand , Marinho Cristina , Solarin Adebowale
Published: July 2009

Despite the development of models describing Fixed Cutter (FC) bit performance, selection is still made on the basis of visible, geometric features. Optimal selection is complicated further by the large variation in characteristics of cutting structures, in combination with a diverse range of gauge lengths and geometries.

A set of performance indices is presented for FC bits. These are derived from a sophisticated mathematical model and describe performance in terms of Rate of Penetration (ROP), Durability, Stability, and Steerability. Once the relative importance of each index is established, the optimal bit for the application can be selected.

Due to the growing diversity of directional tools, a specialist interface for Rotary Steerable Systems (RSS) is also presented. This software incorporates logic regarding tool operation and trajectory requirement, and assesses these against key characteristics of the bit including length, profile, gauge, cutting structure, and sidecutting capability. The software will list bits ranked by decreasing suitability.

Bits can now be modeled routinely and described in terms of their technical interaction with the drilling assembly and the formation. Selection on the basis of modeling and this interaction is novel and valuable, and will provide consistent selection and improved performance.

Performance summaries are documented for global RSS applications. Use of the software lead to optimal bit design selection. Some of the designs selected had not been considered suitable from prior visual review. The designs delivered excellent performance in terms of both footage and penetration rates. In addition, they were accurately matched to the specific RSS utilized, enabling the system to efficiently deliver the required directional control.

Introduction

Offshore drilling in West Africa poses several drilling challenges which have limited drilling performance and build rate capabilities in directional applications. The extremely soft sandstone and shale lithologies in the vertical intermediate section are prone to erosion and hole enlargement with high hydraulic energy. Hole enlargement reduces deflection forces for commercial Rotary Steerable (RS) tools as well as mud motors, which significantly decreases build rate capabilities and limits directional plans and capabilities. The associated hole enlargement in the vertical section creates a drilling environment that is subject to increased risk of lateral vibration (bit whirl), which even in soft formations is capable of catastrophic damage to BHA components and the bit cutting structure. This, in turn, results in reduced drilling performance and increased drilling costs.
Agbami Field Development; Subsea Equipment Systems, Trees, Manifolds and Controls
Authors: Kelly Thomas P. , Strauss Richard H.
Published: July 2009

This paper describes the subsea facilities designed and built for the AGBAMI field development as defined by the Subsea Equipment Vendor (SEV) contract issued to FMC Technologies by Star Deep Water Petroleum Limited - an affiliate of the Chevron Corporation in partnership with Texaco Nigeria Outer Shelf Inc, Petroleo Brasileiro Nigeria Limited, Statoil Nigeria Limited, Famfa Oil Limited and the Nigerian National Petroleum Corp. The history of the design, manufacturing, testing and project logistics are described along with useful lessons learned.

The Agbami field is located offshore from the central Niger Delta in water depths ranging from 4,200 to 5,400 feet of water, graphically illustrated in Figures 1 & 2. The physical size of the field can be visualized as fitting tightly within interstate (Loop) 610 which girdles the city of Houston as illustrated in figure 3. The field is being developed using 100% subsea completions tied-back to an FPSO and tanker mooring system. The subsea completion system includes 16 production trees, 6 Gas Injection Trees, 10 Water Injection Trees which will be tied back to 6 production manifolds, 2 gas injection manifolds and 4 water injection manifolds. The SEV contract covers this equipment as well as all flowline and jumper connector kits, electrical flying leads (EFL's) and Hydraulic (Steel) Flying Leads (SFL's), topsides Multiplex (MUX) controls system and installation tooling. The remainder of the subsea kit was supplied by the Subsea Installation Contractor, Technip, including the umbilicals, flexible flowlines, risers, flexible jumpers and subsea umbilical terminations.

Project success was dependent upon more than simple hardware delivery and installation. Included with the contract hardware deliverables were extensive requirements for documentation management, interface management, Nigerian manufacturing and engineering content, technology transfer for sustainable long term development in Nigeria and facilities logistics as well as field and technical personnel support in a location which has limited support facilities for offshore field developments and well as security challenges which had to be managed successfully.
SWIMMER: Innovative IMR AUV
Authors: Tito Nicolas , Rambaldi Eric
Published: July 2009

If deepwater field developments are to continue to integrate complex subsea equipment for seafloor processing, sometimes in harsh environments and remote locations, the offshore industry has to find new means for Inspection, Maintenance and Repair (IMR) interventions that ensure and improve both integrity management and the flexibility and reactivity of the interventions.

" SWIMMER?? is a new AUV incorporating a light work-class ROV with tooling designed for long-term subsea deployment - 3 months minimum - and able to perform light IMR operations such as:valve operation: manual or hydraulic failing valvesequipment survey: subsea production systems, pipelines and risers, umbilicalsprocess monitoring: hydrate localization, thermal leak identification,…light equipment replacement: hydraulic or electric flying leads, …trouble shooting assistance, using an ROV commanded from the surface facilities through the production control umbilical, rather than a dedicated service vessel.

In early 2007, CYBERNETIX, TOTAL and STATOILHYDRO joined their engineering forces to work on a SWIMMER prototype, and set themselves the target of deploying it offshore by the end of 2011.

This paper presents the project's industrial objectives, highlights key component specifications along with challenges such as AUV system, ROV/TMS, AUV payload, docking station, control and power umbilical, topside interface, and puts forward conclusions on feasibility, technological gaps, associated qualification programs and views on industrial integration on subsea oil and gas fields.

Reliability, flexibility and autonomy are the key words in support of the integration of this concept in future field development architectures which could be fine-tuned with a SWIMMER-based operating intervention philosophy.

Introduction

The offshore industry is facing new challenges with new field discoveries. Reservoirs are often deeper, smaller and in remote locations. The fluids are more complex, often heavy, acid and with low energy. To improve oil recovery, operators are seeking to install complex subsea equipment for boosting, or more generally processing production. Consequently, the capital expenditure figures for future developments are soaring and in the meantime, the costs of IMR operations, mainly driven by ROV support vessels and associated resources, have risen significantly. More than ever, innovative solutions have to be found, not only to decrease the operational expenditure but also to improve flexibility and reactivity.

Over the past years, the use of AUV has increased extensively in various industrial sectors such as oil and gas, military and research. AUV are currently employed in seabed mapping where they have proved to be a choice answer. A couple of programs have attempted to demonstrate that AUVs can perform pipeline surveys but so far, no autonomous vehicle has been really used in inspection, maintenance or repair applications. No intervention AUV are currently available on the market.
The Intentions and Achievements of the Angola Deepwater Consortium
Authors: da Costa Ruben Monteiro , Teixeira Jaime Lopes , des Déserts Loïc , Harris Richard J.S. , Burban Pierre-Yves
Published: July 2009

The Angola Deepwater Consortium (ADC) regrouping Sonangol, Doris Engineering and Pride International was created in 2000, at the initiative of Sonangol, with a view to develop a long term relationship, allow transfer of knowledge to Sonangol and perform conceptual studies in order to optimise field development in deepwater Angola and improve Angolan content.

Over eight years, ADC has carried out more than ten studies, on various subjects, including:–Study of a FPSO for Angolan waters, development of the FPSO specification–Review of offloading systems for spread moored FPSOs in Angola–Further development of the FPSO specification as shipyard enquiry package–Review of Angolan yard capabilities and planned future development–Study of multi-purpose intervention vessels to service Angolan deepwater fields–Study on sharing of data on subsea reliability–Study on marginal field development (issues, key enablers)–Creation and management of an Angolan subsea reliability database–Study on metocean data and uses in design, creation of a regional metocean database–Study on pigging operability and application to single production line concepts–Study on soil characterisation and uses in design, creation of a soils GIS database

The studies performed by ADC are selected by Sonangol and the four historical deepwater operators in Angola: BP Angola, Cabinda Gulf Oil Company (Chevron), Esso Exploration Angola (Block 15) Limited and Total E&P Angola, jointly referred to as ‘Participants’.

The studies are driven by a Steering Committee composed of representatives/experts of each Participant. Participants inform the ADC team with corporate expertise, lessons learned or data from their company.

Introduction - Field development in deepwater offshore Angola

Exploitation of the hydrocarbon reserves located in deepwater offshore Angola started less than a decade ago. The first deepwater fields to be developed were Kuito located in Block-14 in 400 m water depth, on stream since late 1999, and Girassol located in Block-17 in 1,450 m water depth and on stream since late 2001. There has been a considerable deepwater activity since then, especially since 2002 following significant security improvement. Several deepwater fields have been developed, either independently from any other development or as tie-backs to existing field facilities. Today there are a number of projects going on and even more prospects identified.

Even though it has gained in maturity over the years, field development in deepwater remains a real challenge which often requires new approaches and highly engineered solutions. The challenge will certainly get bigger in the near future as there will be more and more reservoirs either smaller in size or having characteristics making them more difficult to commercialise.
SS: Exploration Prospect Interpretation and Risking Using Modern Geophysical Technology - Success in Amplitude Anomalies and AvO - Technology has the Might, but the Basics must be Right
Authors: Pettingill Henry S. , Lindsay Richard Owens
Published: July 2009

Advanced technology provides elegant solutions to complex E&P problems. We should never forget, however, to respect the basics of subsurface sciences, since getting the basics right is a necessary prerequisite for applying advanced technology. This holds particularly true for the evaluation of seismic anomalies - Direct Hydrocarbons Indicators (DHIs) and Seismic Amplitude-versus-Offset (AvO) anomalies

The optimal solution is to always force " Low-Tech?? to precede " High-Tech??, and never the reverse, meaning these three " basics?? must be considered first:Basics of Seismic GeophysicsBasics of GeologyBasics of Risk Analysis

With these three areas of basics covered, the higher-end analytical geophysical techniques that are commonly employed to predict risk and reward in DHI and AvO prospects can now be effectively employed to create value rather than destroy it.

Introduction

Technology provides elegant solutions to complex E&P problems. High-speed workstations armed with geoscience software are uniquely capable to address these complex problems. Advanced hardware and software perform the mechanics of E&P geoscience; but when using these technological wonders we should never forget to respect the strength of basics-done-right. This holds particularly true for the evaluation of seismic anomalies - Direct Hydrocarbons Indicators (DHIs) and Seismic Amplitude-versus-Offset (AvO) anomalies

High-end interpretation technology produces beautiful maps, profiles, and cross sections, often combined into 3D volume interpretations. It can also quickly provide predictions of source, reservoir, and seal properties. When added to precise renditions of trap areas, these technologies may lead us to believe that risk is well-understood and resource calculations are fairly accurate. But even the best algorithms can produce mathematically correct solutions that are geologically impossible, leading to inevitable destruction of value!

The optimal solution is to always employ " Low-Tech?? as a prerequisite to " High-Tech??, and never the reverse, meaning " basics?? must be considered first. Ironically, the same high-tech tools that can lead to geologically impossible interpretations when not integrated with basics, can be used properly to more effectively assure the basics are in place. This paper summarizes some concepts and combines them with case examples to address three areas of basics that must be pre-supposed before " High-Tech?? can be employed:Basics of Seismic GeophysicsBasics of GeologyBasics of Risk Analysis
Prospect Exploration Risking Using Modern Geophysical Technology
Authors: Moreno Carlos E. , Perez Maria A. , Meyer Jeffrey Scott , Huffman Alan R. , Etemadi Mohammad , Benkovics Laszlo
Published: July 2009

Amplitude versus offset (AVO) and spectral decomposition (SD) techniques were used for direct hydrocarbon identification (DHI) in the Plio-pleistocene section in Deep Water Trinidad & Tobago to help to quantify better the risk during hydrocarbon prospecting. In order to understand and predict the seismic response for different fluid types and lithologies, AVO and SD modeling based on existing well log information close to the study area were performed. The controlled synthetic models simulated the seismic response for wet sands, commercially saturated gas sands, and partially saturated gas sands, as well as variations due to lithology. After modeling and validation of the technique with real pre-stack and post-stack seismic data on calibration well locations, seismic analysis supported with AVO and SD technologies was performed to evaluate prospects located in Deep Water in Trinidad & Tobago. Very subtle differences in the AVO and SD responses were the only way to discriminate between hydrocarbon and lithology. Very subtle variations during AVO and SD analysis suggest that the lithology factor can produce false DHI in the area. SD also showed the potential of helping separate fully saturated gas sands from partially saturated gas sands.

Introduction

The use of amplitude versus offset (AVO) and spectral decomposition (SD) techniques for direct hydrocarbon identification (DHI) in the Plio-pleistocene section in Deep Water Trinidad & Tobago can help to quantify better the risk during hydrocarbon prospecting. These seismic technologies require the use of pre-stack and post-stack seismic data that has been processed for preserving relative amplitude and frequency spectrum. In order to understand and predict the seismic response for different fluid types and lithologies, AVO and SD modeling based on existing well log information close to the study area was performed. The controlled synthetic models simulated the seismic response for wet sands, commercially saturated gas sands, and partially saturated gas sands, as well as variations due to lithology. The fluid substitution was performed using Gassman's equation after proper petrophysical analysis and invasion/dispersion corrections were done on the well data.

Petrophysics and Fluid Replacement

Invasion and dispersion corrections were applied to the well log data previous to fluid replacement. Fluid replacement was performed using Gassman's equation to simulate the fluid and saturation effect on the well log response on the P-Wave Velocity, Density and S-Wave Velocity due to the presence of brine, partially saturated and full gas sand cases. The resultant fluid replacement log responses are shown in figure 1. Figure 2 shows a sketch of the expected response for P-Wave Velocity, Density, S-Wave Velocity, Poisson Ratio and Acoustic Impedance for the same fluid cases.
Scenario-Based Assessment of Risks to Ice Class Ships
Authors: Kendrick Andrew , Quinton Bruce , Daley Claude
Published: July 2009

The rise in resource related projects in the Arctic has created the need for new approaches to assessing and minimizing risk. The new tankers and drill ships required for the Arctic will be larger and stronger than any previous ships, but will be very carefully designed and operated. The paper presents a methodology for assessing risk to large Arctic ships in a variety of scenarios. For the purpose of illustration of the approach, two ice collision scenarios are described. One is the case of a large ship with a bulbous bow hitting an iceberg head-on. The second is an aft waterline collision with a sea ice floe. Both scenarios are outside the conditions formally considered in standard ice class rules but are significant issues. The paper provides owners/designers/regulators with an example of a methodology to examine ice loads using a rational set of design scenarios. The results show that vessels can easily be operated in a manner that can create dangerous load levels. The results are directly relevant to the structural design of new large Arctic tankers (oil and LNG) and large Arctic drill ships. The second part of the paper presents some initial results from consideration of plastic structural response to moving ice loads. The significance of the movement (sliding) of the load increases as the response level increases. Elastic responses are only slightly influenced by the movement of the load along the hull, while the larger plastic responses are greatly affected by movement. This paper is mainly intended to raise this as an issue of potential concern.
The Value of Model Testing in Understanding the Behavior of Offshore Anchors: Towards New Generation Anchors
Authors: Ozmutlu Senol
Published: July 2009

This paper introduces the model testing of drag embedment anchors under laboratory and offshore conditions. As the anchors form the foundation of a floating unit (both permanent and temporary), the model tests help in designing new generation anchors with higher performance and reliability. Furthermore the physical models are used to test and simulate the anchor handling/installation procedures, and serve as powerful teaching aids for operating personnel offshore.

The new directions in psychical model testing of offshore drag anchors are highlighted. The benefits of well controlled testing and the ability of measuring new anchor-ground interaction variables are discussed. It is shown that the new model testing programs will increase our current understanding of the anchor behavior and performance in operational and storm loading conditions.

Introduction

A special category of drag embedment anchors is a commonly used foundation option for offshore mooring of floating units (i.e. MODU, SPM, FPU, FSO, FPSO, etc.). The anchors in this category are labeled as High Holding Power (HHP) anchors owing to their very high efficiencies or performance ratios. The old generation drag anchors had efficiencies (i.e. the ratio of Ultimate Holding Capacity - UHC to dry dead weight of anchor) as low as 3, and had suffered from penetration and stability problems in slightly challenging subseabed soil conditions. Today, the modern HHP anchors have reached efficiencies over 65 by overcoming the penetration and stability issues thus presenting a reliable as well as practical and economical foundation solution in challenging soil conditions. This development would not be possible without continues testing of scaled model anchors in laboratory, in centrifuge, and under actual field conditions.

This paper presents the model testing of both fluke (e.g. Stevpris - Stevshark series) and plate (e.g. Stevmanta VLA series) anchors (Figure 1) of drag embedment type. The drag embedment fluke anchors are commonly used in catenary mooring systems whereas the drag embedment plate anchors (i.e. Vertically Loaded Anchors - VLAs) are commonly chosen for semi-taut or taut-leg mooring systems. Both anchor types are installed by lowering the anchor to the seabed first and then by applying a pull load from a surface vessel (Vryhof 2005).

The quantities given in this text, unless otherwise referenced in the text, refer to the in-house testing database and track record of the company that the author is affiliated with.
Required Developments Towards Ultra High Pressure/Temperature Subsea Tree System Solutions.
Authors: Queseth Per-Olaf , Dyson Andrew
Published: July 2009

The need for oil and gas in the world wide market does not seem to have an established limit. With the hydrocarbon prices on to-days level and the long term tendencies of a steady average increase, new fields have to be found and produced regardless of existing technology gaps. For the subsea oil and gas production systems, there are many challenges but what seems to be a primary challenge is to provide good solutions for High Pressure, High Temperature reservoir exploitation based on an overview of already discovered potential fields and an evaluation of what might come.

The paper will present a résumé of Aker Solutions previous development in this area exemplified with experiences from testing and operator observations during production start.

Further improvements are required to comply with the extreme pressures and temperatures sought to overcome.

The presentation will therefore compile current international standards impact on this development, sorting of material parameters upsetting the progress, nominating materials with high potential and giving an indication on how to qualify these materials for use.

History have shown the importance of combined, cyclic testing with multi parameter variation and even forming and finding the right testing facilities is tedious and costly. An overview of current availability and future needs will be tabled and requirements formed.

To make a practical approach to all the details involved and all the standards impacting the end result, a program to qualify subsea production X-mas trees will be presented with high-light on feed-through solutions for hydraulics, electric and optic power and signal communication. Preliminary and intermediate test results will be presented and outstanding activities summarized.

Introduction

When newly industrialized and heavely populated countries like China and India really starts to increase their number of motorized viechles there will not be an immediate limit to their need for destilated hydro carbon products. Hence there will be exploration to find new reservoirs in places and under conditions not yet seen today.

Although hydrocarbon reservoirs are found onshore as well as offshore, this presentation will concentrate on offshore field developments and more specifically fields equipped with subsea production equipment. Production equipment is classed by API or ISO. The majority of current subsea completions are designed for Class U (10 Kpsi and 121 oC) and this is the level required for 80 - 90% of all found reservoirs.

High Pressure, High Temperature level is currently considered as above 10 Kpsi. and 150°C.

A number of HPHT discoveries, previously on hold while suitable HPHT technology has been engineered, are now being enquired about, considered for development, contracted and some already delivered.
SS: MODU Anchor-Changes in anchoring rules and regulations for MODUs
Authors: Ruinen Roderick Michael
Published: July 2009

The past few years have seen the updating of codes for the use of drag embedment anchors (fluke and plate anchors). Examples are the specific requirements for drag embedment anchors in the Gulf of Mexico due to the hurricanes and the updating of anchor codes in Norway. This paper will summarize the current rules and recommended practices for drag embedment anchors and their application. It will then show the effect on drag embedment anchors and the application for MODU moorings.

Introduction

Most floating MODUs are moored using drag embedment anchors, either fluke or plate anchors. Setting of the anchors using conventional guidelines has generally been sufficient to ensure a safe mooring. However recent hurricanes in the Gulf of Mexico resulted in a number of mooring failures. Storms in the North Sea have also resulted in a number of mooring failures. These mooring failures and specifically anchor failures have resulted in new guidelines and regulations being developed for among others the Gulf of Mexico region and the Norwegian section of the North Sea. This paper will focus on these guidelines / regulations with regards to the use of drag embedment anchors for MODU operations.

Background

Gulf of Mexico

In the period 2002 to 2008 a number of severe hurricanes passed through the Gulf of Mexico region causing severe damage to offshore infrastructure. Damage consisted of floating MODUs drifting off station due to mooring line failures and damage to fixed platforms and jack-ups. During hurricanes Ivan (2004), Katrina and Rita (both 2005) a total of 17 moored MODUs broke free from their moorings and drifted off-station for a distance larger than 1 mile. Of these, only four cases reported the drag embedment anchors dragging for a significant distance. The damage that occurred to the platforms has led to the development of interim guidance for the 2006 and 2007 hurricane seasons (API 2006) and an amendment to API RP 2SK (API 2008).

North Sea

The regulation of offshore safety in UK Continental Shelf (UKCS) is the role of Health and Safety Executive (HSE) and Department of Energy. In Norwegian Continental Shelf this role is shared by Norwegian Maritime Directorate (NMD), Petroleum Safety Authority (PSA) and Norwegian Petroleum Directorate (NPD).

For the UK continental shelf the audits and accident statistics between 1981 and 2003 are published by Health and Safety Executive (HSE 2005). Within this period, among 3485 reported incidents on all moored units (permanent and mobile), 240 incidents relate to mooring system failures (a failure frequency of about 0.2). The mooring system failures include problems with mooring lines, mooring devices, winching equipment or fairleads, and anchors. Among the 240 mooring incidents only 34 incidents are categorized as accidents, the rest are incidents of near misses or insignificant situations. Only one of the 34 incidents categorized as accident relates to anchor drag due to one line being damaged and the tension control on the winches could not be implemented.
Intelligent Wired Drill-Pipe System Provides Significant Improvements in Drilling Performance on Offshore Australia Development
Authors: Lawrence Luke , Redmond Bruce , Russell Richard Buchanan , MacNeill Dave , Reeves Michael E. , Hernandez Maximo
Published: July 2009

An ‘Intelligent’ wired drill-pipe system has recently been used on a large offshore development in North West Australia for Apache Energy Limited. The IntelliServ® network is designed to overcome the shortcomings of mud pulse telemetry in terms of real-time data transmission speeds and pulser reliability. By utilising this unique system of Intellipipe® wired drill pipe and associated drilling tools connecting the Rotary Steerable System and LWD string to the surface, transmission speeds of up to 57,000 BPS theoretically can be achieved.

For the development of the Van Gogh Field, Apache Energy Ltd decided to utilise the IntelliServ system along with Halliburton's rotary steerable system and LWD tools.

This paper will describe the wired drill pipe network and its integration with a drilling assembly containing a rotary steerable system, multiple formation evaluation and drilling dynamics sensors. The objectives for running the wired drill pipe system on this project will be discussed and the actual operational experience reviewed. Topics to be covered will include the improvements in drilling optimisation and drilling performance, the increased accuracy in wellbore placement, and the improved quantity and quality of the formation evaluation data received in real-time. The future uses and benefits of this technology also will be reviewed.

Introduction

Modern MWD and LWD sensors now generate so much data that it is not possible to take full advantage of this data due to the limitations imposed by conventional mud pulse telemetry systems. Although advances have been made in the form of data compression and batch transmission modes, mud pulse transmission is still the limiting factor in many potential applications.

Typical LWD assemblies may now consist of tool combinations including gamma-ray, multiple resistivity, density and neutron petrophysical measurements. The latest LWD sensors can provide formation images, sonic waveforms, and multiple geosteering signals, all of which require large bandwidths in order to take full advantage of them. In addition, directional survey data, downhole drilling optimisation measurements also may be transmitted. This amount of data can place a great strain on conventional mud pulse telemetry systems. As drilling rates increase the data density of the real-time measurments becomes increasingly sparse until at some point, drilling rates must be held back to ensure that a useable log is received in real-time.
Enabling Ultra-Deepwater Mooring with Aramid Fiber Rope Technology
Authors: Chi Cheng-Hang , Lundhild Evelyn Margaret , Veselis Todd , Huntley Mark
Published: July 2009

New high-strength synthetic ropes constructed of para-bonded aromatic polyamide (aramid) fiber are being developed for ultra-deepwater mooring applications. This paper highlights new laboratory tensile/fatigue testing of rope assembly, computer modeling analysis of mooring performance under operating conditions, and the potential economic impact.

As the industry moves into ultra-deep water, traditional steel wire rope and chain moorings are being gradually displaced by polyester ropes. These synthetic ropes have been used in water depths between 3,000 feet and 8,000 feet. Questions arise, however, about whether polyester mooring ropes provide enough stiffness to maintain acceptable platform offsets in increasingly deeper water in all cases. Aramid fiber ropes are inherently stiffer and stronger than polyester ropes and therefore offer new solutions for ultra-deepwater mooring, as well as for other applications where production platform offsets may be critical.

Advanced technologies are being developed to optimize aramid fiber performance and rope design configurations. New laboratory tensile and fatigue data are presented to demonstrate aramid fiber rope properties, performance capabilities, and minimum tension settings meeting API RP 2SM guidelines. Mooring analysis comparing the performance of an aramid mooring system with that of a polyester mooring system under simulated hurricane and loop current conditions shows significant reductions in platform offsets are achieved with the aramid system without compromising safety.

This paper describes a new technology for ultra-deepwater mooring. The new approach offers the opportunity to design mooring systems for deeper water without modifying certain platform components and systems by incorporating stiffer, high-strength aramid fibers in the platform mooring system. Potential benefits include achieving optimal offsets for production risers in ultra-deep water, easier handling and installation due to smaller rope size, and greater flexibility in mooring system design. Economic analyses are presented to illustrate the advantages of the new technology as well as the financial impact.

Introduction

Industrial and commercial grades of aramid fiber have been used successfully for more than 25 years in numerous marine rope and cable applications, because of their unique combination of physical characteristics and performance capabilities. The linear molecular structure of aramid fiber yields a strength-to-weight ratio more than five times that of steel wire in air and more than 20 times steel wire in water. Aramid fiber is corrosion-resistant, nonconductive, and exhibits low elongation properties—or stiffness--in response to high loads, variations of mean load and rapid cyclic loading. Aramid fiber also performs well in arctic or elevated temperatures and is highly resistant to tension-tension fatigue.
Advanced Flow Assurance System For The Ormen Lange Subsea Gas Development
Authors: Lunde Glenn Gahr , Vannes Knut , McClimans Ole Thomas , Burns Cathy , Wittmeyer Kristina
Published: July 2009

Ormen Lange Flow Assurance System (FAS) is to date the most advanced real time and simulation support system for operators, flow assurance engineers and management. The system is delivered by FMC Technologies with SPT Group and Prediktor as sub-suppliers.

The Ormen Lange field is the largest gas sub-sea development of its kind with onshore processing facilities at the Nyhamna on the west-coast of Norway.

Several flow assurance challenges must be taken care of to enable secure and stable production in deep water (down to 1100 m/ 3600 Feet), low temperature (-2°C/ 29F) at the seabed in addition to long distance (120 Km/75 Miles) to shore through rough sub-sea terrain. Such conditions highly expose the production system to potential flow assurance phenomena like hydrate formation, liquid holdup, water breakthrough etc..

Ormen Lange FAS represent a barrier breaking system and play an important role in production monitoring and operator support. The system includes the following modules:Virtual Flow Metering System (VFMS):Model generated values of flow rates (gas, condensate and water) as backup to physical multiphase meters, sensor surveillance and leakage detection.Pipeline Monitoring System (PMS):Model generated values of pipeline flowing conditions and onshore receiving facilities.MEG Injection and Monitoring System (MIMCS):Continuous MEG injection monitoring and optimization.Production Choke Control System (PCCS):Individual well production chokes control for overall field optimization.Formation Water Monitoring System:Monitoring and alarm generation when / if formation water breakthrough is indicated. The system is based on advanced usage of statistical process control.

Based on practical experience gained in the period from December 2007 up until now, this paper focus on the systems potential of early detection of flow assurance problems, sensor and metering surveillance and how the system is being used to solve practical day to day operational challenges.

During the last years, the status of the Ormen Lange development project has been reported during OTC, as well as in other conferences and in papers, covering a multitude of disciplines and methods in order to finalize such a grand challenge. In 2007 there was a dedicated technical session for the Ormen Lange development as part of the OTC program, /1/, /2/, /3/, /4/, /5/, /6/ and /7/.
SS - Optimizing Horizontal Well Performance In Non-Uniform Pressure Environments Using Passive Inflow Control Devices
Authors: Krinis Dimitris , Hembling Drew E. , Al-Dawood Naseem Jaber , Al-Qatari Sadiq Ali , Simonian Sam , Salerno Giovanni
Published: July 2009

Passive Inflow Control Devices (ICDs) are used to enhance performance of horizontal wells in unfavorable environments, such as nonuniform permeability and/or pressure along horizontal sections. This is the first attempt at using ICDs to manage inflow along horizontal wells with substantial reservoir pressure differential.

This paper presents how passive ICD completion technology is used to optimize well productivity and reduce water production in a well with significant reservoir pressure differential across the horizontal section. Prior to running the ICDs, this horizontal carbonate well exhibited a nonuniform production profile, cross-flow, and high water production resulting in reduced well performance.

A production log of the initial (open hole) completion confirmed downward cross-flow of fluids from heel to toe and production contribution from only the first 10% of the horizontal section. Following the installation of the ICD system, water production was greatly reduced and oil rate doubled indicating significant improvement of the well performance. A second PLT survey showed contribution from the entire horizontal section and elimination of the cross-flow.

The key factor in the success of this project was the ICD system design derived from numerous wellbore hydraulic simulations, determining the appropriate number of ICD units and compartments.

Introduction

Horizontal wells have been globally used to maximize reservoir contact and ultimately improve well performance. Variations in permeability, pressure and frictional pressure drop along horizontal sections can create nonuniform inflow profiles, which can lead to early breakthrough of water or gas in reservoirs with an aquifer and/or gas cap. Breakthrough typically occurs in regions of high permeability or at the heel of the lateral section in homogenous reservoirs. This ultimately leads to a reduction in reserve recovery and well performance.

The use of ICD systems to effectively manage nonuniform inflow profile has been described in past publications1-4. In this paper, ICDs were used to control nonuniform pressure profile. The variation in reservoir pressure was 200 psi from heel to toe, with high pressure at the heel.

Background

Horizontal wells are common practice in this giant Middle East field with a production history of more than 50 years. The reservoir is a composite Jurassic carbonate anticline, with several gently dipping crestal regions containing undersaturated Arabian Light grade oil. Full pressure maintenance was initiated in the 1980s by peripheral power water injection. Infill drilling is still underway tapping oil behind the flood front areas utilizing horizontal well technology. The most prolific zones in this gravity dominated reservoir exhibit high matrix (300 mD - 2,000 mD) permeability, which is the principal source of production.
Motion Behaviour of the Mono-Column FPSO Sevan Piranema in Brazilian Waters
Authors: Saad Arthur Curty , Joao Leonardo Vilain , Loureiro Rodrigo Reis , de Brandao Renilton , Filho Remo Zauli Machado , Lopes Clovis , Gioppo Heitor Luiz
Published: July 2009

The world's first floating, production, storage and offloading (FPSO) mono-column type platform was installed in June 2007 in the Piranema field, located offshore Sergipe state, Brazil, in 1,090 meters water depth. The unit is equipped with a process plant capable of handling 30,000 bpd (41 to 44º API) of crude, and capacities for 2,400,000 Nm3/day gas compression and 300,000 barrels oil storage. It was designed, built and commissioned by Sevan Marine according to the novel concept. The unit is currently being operated by Sevan Marine for Petrobras under a long-term charter contract.

A Technical Cooperation Agreement, between Petrobras and Sevan Marine to investigate the mono-hull concept since initial tank tests, also allowed monitoring motions and environmental data since the platform was commissioned, under a project led by Petrobras Research and Development Center.

This paper is intended to provide information on the motion behavior of a mono-hull production platform in real environmental conditions, and presents a comparison among data acquired from field measurements and results from numerical simulations as well as from model tests performed during the design phase. Other FPSO key functionalities are also addressed in this paper, such as the offloading operations and mooring system performance.

Introduction

The current drive to produce offshore oil fields in deep and ultra deep waters has pushed oil companies and operators to pursuit novel concepts for production units which are capable of storing and offloading the oil to shuttle tankers. The mono-column floating production platform is considered a unique concept of great interest by the industry. The expected enhanced motion behavior of this concept in comparison to ship-shaped production units is very beneficial for the performance of the production plant, safety of the crew and mainly for long-term integrity of the risers connected to the platform. Moreover, the mono-hull concept has good constructability with low capital expenditure during construction. Easiness of installation is also considered one of the advantages of this mono-column concept.
BP King - Deep Multiphase Boosting made Possible
Authors: Davis Brian Edward , Kelly Cathal , Kierulf Katrine , Eriksson Klas Goran , Normann Truls , Homstvedt Gunder
Published: July 2009

The BP King subsea pumps were commissioned in November 2007 in record-breaking water depth of 5430 ft (1700 m) offshore Louisiana in Gulf of Mexico (GoM). Two twin-screw multiphase pumps were installed with a 17-mile (27 km) tieback to the Marlin Tension Leg Platform (TLP). Besides the technical challenges that have been overcome in this record breaking project, installation and commissioning under these conditions are a major achievement.

This paper gives a presentation of the system evaluation ahead of launching the project and the various engineering tasks during design of the system. The complete pump system with all necessary topside and subsea components is presented and discussed. Attention is also given to training, pre-deployment work, installation and commissioning of the pumps. This joint BP America Inc. (BP) and Aker Solutions ASA paper also describes the operational experience and methods for continuous monitoring of the various sub-systems at the pump station.

Introduction

BP King is an oil field located in the Gulf of Mexico (GoM). It consists of three wells, King D5 and D6, producing since 2001 and King West, D3, producing since 2003. The wells are located in water depths ranging from 5000 to 5430 ft (1520 - 1655m). All three wells are 100% owned by BP and are produced back to the Marlin TLP which is also operated by BP. The field is located approx. 100 miles (160 km) offshore the coast of Louisiana in the GoM.

The Marlin Tension Leg Platform is located approximately 86 miles SSE of Venice, Louisiana in Viosca Knoll Block 915 at a water depth of 3245 feet. There are a number of fields that are tied back to the TLP and one of the longest of those is the King Field Complex. The wells are connected via rigid jumpers to one of the two flowlines going back to the Marlin TLP approximately 17 miles (27 km) away.

As pressure in the reservoir has been declining, BP initiated studies of various methods of keeping up the production and increasing the field life. A structured approach was applied throughout the project period based on BP's project execution stage gate process:Appraise - Determine the feasibility of the project and align with business strategySelect - Select the preferred project option and establish execution plan and fundingDefine - Finalize project scope, cost, schedule and execution plan. Complete contract negotiations with key suppliersExecute - Procure and install equipment in alignment with scope, cost and schedule targets.