bluuebunny/crossref_metadata_2025 huggingface dataset:
Buoyant Tower: Drilling and Production
Authors: Mueller Wayne , Blanco Hugo
Published: May 2013

The CX-15 platform was installed off the coast of Peru in block Z1 in September 2012. The buoyant tower is designed for tender assist drilling and production. This is achieved through two opposing cantilevered 12-slot drilling and production templates and guide assemblies. By the time of presentation, the initial drilling phase will be underway and data from the whole process will be available for review, discussion and evaluation. The platform is the world's first application of a proprietary design that is a fusion and combination of existing and proven technology from deep water cell spar floating platforms, compliant tower structures and shallow piled foundations. The paper presents an overview based on project information for the drilling operations from the CX-15 buoyant tower and the use of a modified onshore rig with barge tender assist. The drilling philosophy is designed to efficiently enable rapid drilling and completion of wells and reduce time to first oil. The well design includes the innovative use of the 20 in. conductor as a cost effective bend-restrictor at the mud-line. The design and provision of a fully integrated topside facility is " state-of-the-art " offshore Peru. Lessons learned from drilling and production operations are shared.

Introduction

The CX-15 platform is located approximately seven miles off the northwest coast of Peru in a water depth of approximately 175 ft (see Fig. 1). The platform consists of a three-level, four-legged deck supported by a buoyant tower hull. The platform is a drilling and production unit and would generally be compared to a fixed jacket platform with an API skidded platform rig. To reduce the size and payload of the platform, most drilling support equipment is located on a tender barge moored adjacent to the platform.

The hull structure is a buoyant tower and consists of four cellular columns and an integrated suction-can foundation centered below the four tubular cells. Because the columns are arranged close together without a moon pool, two wells bays are located outside of the tower's footprint. The drilling rig is supported by cantilevered wing decks (see Fig. 2).

In addition to the wells, the platform is equipped with production equipment to produce, separate, and treat oil, gas, and water from the CX-15 field. Stabilized and dehydrated sales oil is transferred by pipeline to an existing FSO moored in the area. Wet associated gas is compressed and transferred by pipeline to the existing CX-11 platform. The produced water is treated on the platform and can be re-injected locally or transferred by pipeline to the existing CX-11 platform. Provisions for lift gas and gas injection are also included.

The drilling rig mast, drive, and skidding system are newly constructed but based on an existing telescoping land rig. The land rig mast design was upgraded for use on the buoyant tower and the skidding system and support base were designed and constructed specifically for this project.
Thin-Wall Approximation: Implications for the Expansion and Global Buckling of Thick-Walled, High-Pressure Flowlines
Authors: Kurusamy Doraraju
Published: May 2013

R.E. Hobbs in 1984 addressed in detail the buckling of heated pipelines using thin-wall theory. His work was instrumental in starting much interest and active research in the global buckling of pipelines. Since then, publications on pipeline expansion and global buckling base their analyses on thin-wall theory. Joint Industry Projects like SAFEBUCK and HOTPIPE and the industry's recommended practice and guidance have also mostly addressed global buckling of pipelines based on thin-wall formulation. Presently engineers use thin-wall FEA methodologies to routinely design flowlines/pipelines for axial expansion and global buckling. Thin wall theory is accurate for ratios of D/t >20. High pressure thick-walled flowlines can reach values of D/t<6 and the continued use of thin-wall theory can lead to flaws in their design.

Although a few authors have addressed the topic of pressure-induced axial strains of thick-walled pipelines, the lack of need for heavy walled pipes has not motivated the industry to use thick-wall formulation. Although industry is aware that the use of thin-wall theory for thick-wall pipelines can lead to design flaws for the pressure-induced pipeline expansions and buckling mitigation, there has not been a comprehensive comparison between thin-wall and thick-wall theory based on experiment, analysis and numerical modeling in this regard.

The purpose of this work is to quantify the errors due to the inappropriate use of thin-wall theory for thick-walled pipeline expansion and global buckling. Experimental and FEA results are in excellent agreement with analytical results. Parameters relevant to axial expansion and global buckling of thick-walled flowlines under high pressure loads using thick-wall theory are compared against those obtained using thin-wall theory. It was found that thin-wall theory can substantially underestimate the pressure-induced axial expansion of thick-walled flowlines, in some cases errors in excess of 80%. With errors of such magnitude caused by the improper use of thin-wall theory, the design for flowline/pipeline expansion and global buckling (lateral and upheaval) mitigation can be inadequate and thus lead to non-conservative design especially in scenarios where pressure-induced axial strains dominate (e.g. hydrotest case) or when they are not negligible compared to axial strains caused by temperature.
Seismic Normal Compaction Trends and Lithology
Authors: Ebrom Dan
Published: May 2013

Eaton's method, the standard method of determining pore pressure from seismic velocities, has been adapted from logging techniques. It requires the use of a normal (i.e. hydrostatic) compaction trend specific to very-low-silt shales, and also that the analysis only be performed upon relatively silt-free shales. As a practical matter, the gamma ray log is used to distinguish shales which are low enough in silt to be appropriate for comparison to the normal compaction trend. (Other methods of determining pore pressure from sonic velocities, such as Bowers (1995), also require a normal compaction trend for low-silt shales and restrict the analysis to very-low-silt shales.)

The obvious challenge in applying Eaton's method to seismic velocities is that all lithologies present in the subsurface contribute to the seismic interval velocity, and not just the shales. Again, the logic for practical matters is that, since shales are the most statistically likely lithology (at least in the Tertiary GOM), then a large enough velocity analysis window will be dominated by shales in terms of the velocity response. Hence one must be careful not to use velocities with too high a vertical resolution for fear of too strongly mixing lithology velocity responses in with pore pressure velocity responses. The exact limit of useful vertical resolution is debatable. Alan Huffman, at the 2010 SEG Annual Convention, opined that velocity analysis vertical resolutions finer than 1000 feet begin to run the risk of lithology effects. As likely, the highest useful velocity resolution is probably both depth- and area-specific.

But since pore pressure prediction from seismic velocities is routinely performed and found to be useful, these problems are clearly not insuperable. One of the key issues is to pick a normal compaction trend that honors the siltiness level of the local geology by adjusting the trend away from a pure shale compaction trend to that silty shale which is statistically the most likely in the region and depth of interest. As a practical matter, this can be performed by manually altering the compaction coefficient of the compaction trend until the resulting predicting pore pressure agrees with mudweights, well formation pressure tests (RFTs and MDTs), and other drilling information. Alternatively, if the compaction trend is calculated explicitly using volume of clay (VClay) as an input, then the VClay is manually altered until the predicted pore pressure agrees with the mudweights, MDTs, etc. In essence, the problem is solved by simply calibrating it away.
Carbon Fiber Armors Applied to Presalt Flexible Pipe Developments
Authors: Hanonge Didier , Bernard Gary , Do Anh Tuan
Published: May 2013

Pre-salt fields discovered in offshore Brazil require flexible pipe structures capable of reaching water depths of 2,000 meters and beyond.

Over the past decades carbon fiber technology has been widely used in a number of industries and is now ready for introduction to the flexible pipe industry. As a demonstration of what will be possible with composite materials in the near future, this paper will present the benefits of Carbon Fiber Composite armors and why it will be a game changer.

For example, this technology dramatically increases the achievable range in free hanging riser configurations, resulting in optimization of ancillary equipment and faster installation. Furthermore, the fatigue performance and corrosion resistance result in a higher safety factor with improved product service life.

A comprehensive qualification campaign, including prototype testing at conditions more severe than the pre-salt field specification, has resulted in a new design of flexible pipe using Carbon Fiber Composite that can be considered a qualified technology.

The present paper will focus on the carbon fiber integration within flexible pipe technology. We will go a step after the other from the material qualification tests, to the carbon fiber armors demonstrated fatigue performances, and in the end in the flexible pipe design and manufacturing.
Liuhua 11-1 FPS Dry-dock Upgrade and Life Extension - Mooring System Evaluation and Optimization
Authors: Zhong Wen Jun , Liu Bo , Luo Yong , Yang Hui , Yin Han Jun
Published: May 2013

The evaluation of existing mooring system and the development of an appropriate optimization design became the key issues in the Liuhua 11–1 FPS dry-dock updating project because this optimized mooring system has to face new challenges, such as the update of site metocean conditions, the revision of wind force coefficients due to upgraded topsides, and the additional corrosion allowance for chain links due to extra 15-year service life extension compared with the original system design.

A design team was formed to give the evaluation of the existing mooring system based on mooring line tensions and offset limits according to the latest industry standard for a permanent mooring system. Since the existing mooring system marginally failed the design requirements based on the evaluation, system optimization design focused on the adjustment of mooring line pretensions has been carried out to improve the mooring system performance and eventually to satisfy the classification requirements for the tension safety factors and the platform offset limits driven by the riser designs. The mooring system analysis was conducted in time domain. The Ariane program developed by BV was used in the detailed mooring system analyses. For the calibration and verification purpose, the system evaluation and the optimization design had also been independently verified with DNV's DeepC program.

Introduction

The LH 11–1 oil field is located about 200km southeast of Hong Kong in the South China Sea in approximately 310m depth of water. LH 11–1 FPS, which named ‘Nanhai TiaoZhan’, is a major component of LH 11–1 oil field development. The FPS was a modified drilling semi-submersible converted from a Sedco 700 series drilling rig built in 1975 and in 1995, it was converted again to a floating production unit in Singapore and then deployed at LH 11–1 oil field, permanently moored by 11 mooring legs. The Unit is classed by American Bureau of Shipping (ABS). It was originally designed for a service life of 10 years (from 1995) and has been continuously operating for more than 15 years. At the same time, a new oil field Liuhua 4–1 (OTC-24042), about 11 km away northwest LH 11–1, was in development planning with the utilization of LH 11–1 FPS facilities through a subsea tieback. Therefore, additional topsides capacities and the life extension of this aged semi-submersible FPS became necessary. CNOOC Ltd, Shenzhen is the owner of this LH 11–1 FPS. COOEC was selected as the contractor for the engineering and construction support of this FPS dry-docking upgrading and life extension project. CSSC Guanzhou Huangpu Shipbuilding Co., Ltd was contracted by the owner as the dry-docking shipyard for the upgrading construction.
Effects of Fiber Rope - Seabed Contact on Subsequent Rope Integrity
Authors: Head William , Del Vecchio Cesar J. , Ayers Ray R. , Devlin Paul V
Published: May 2013

A 12-month research project was initiated in September 2012 funded by the Research Partnership to Secure Energy for America (RPSEA) and industry partners with the goal of investigating the effects of polyester mooring rope segments contacting the seafloor prior to installation as part of a deep-water mooring system. It is possible for some soil particles to bypass the particle filter, become embedded in the rope core, and intensify normal fretting wear damage as the installed ropes respond to the cyclic loads resulting from extreme weather forces (such as hurricanes).

Potential soil ingress into rope due to accidental contact with the seabed may affect the long-term integrity of the mooring system and increase the risk for failure. This situation, in turn, places nearby subsea and surface infrastructure at risk. This investigation may also provide the ability to qualify particular rope designs for pre-installation on the seabed prior to hook-up. This option would greatly reduce overall risk by reducing the time required to hook up mooring lines to a floating facility, thereby reducing time to reach a safely moored condition before arrival of severe weather.

This paper describes progress in (1) performing experiments to investigate particle ingression and migration, and soil particle impact on cyclic wear (including hypothesis of mechanisms) and (2) full-scale tests exposing rope segments to the offshore seabed and then performing bench-type subrope soil-ingression sampling and full-scale subrope cyclic wear testing to determine the impact of seabed soil contact on the long-term performance of a mooring system.

An important project goal is to reach agreement between industry participants and US regulatory agencies to qualify polyester mooring ropes for incidental seabed contact and seabed pre-installation.
Subsea Pipeline Repair by Composite System: One Step Deeper
Authors: SLIMANI Hacen , BOULET D'AURIA Stanislas , GAFFARD Vincent , WIET Paul , POPINEAU Dominique
Published: May 2013

Composite repairs are increasingly used in the oil and gas industry, for temporary repairs and for permanent repairs provided long-term performance is demonstrated. Composite repair systems are mainly used for onshore pipelines or offshore topsides. They are generally made of fibers tapes (aramid, glass …) impregnated with epoxy resin and then wrapped around the pipe. The number of fibers tapes layers and the repair length is determined from design calculations following standards such as ISO/TS 24817 or ASME PCC-2.

For subsea application of composite repair, five main issues must be considered:–pipe preparation: coating removal and surface preparation are necessary to ensure adhesion of the repair,–resin properties: the resin working time must be extended to allow fibers tape preparation above water and application under water,–repair performance: it must be demonstrated that underwater application do not affect repair strength,–repair system application: this is mainly a manual task today which can be performed by divers but is not applicable for deepwater,–design to lateral buckling and collapse: specific design criteria and limit states of composite repair must be determined for deepwater.

Several tests of divers' assisted underwater applications have been performed under third party supervision, using a specifically developed epoxy-resin. The experimental database covers repairs of through thickness defects and localized wall thickness reduction up to 80%. All tests results were comparable to results obtained for above water repairs and evidenced that the original pipe strength was fully restored.

In parallel, a specific tool has been developed to apply automatically the repair system with two main objectives:–to improve quality and repeatability of the wrapping operation, with applying constant tension and winding path,–to allow diverless (ROV) applications, which is a pre-requisite for deepwater applications.

This tool has been already tested underwater in the " semi-automatic" mode (operated by divers) with a positive feedback.

Composite system is, technically and economically, a promising way to repair subsea pipelines. There are no more restrictions to consider composite repair systems for shallow water applications. Additional tests with ROV, as well as collapse and bending resistance tests are now to be performed to open the way to deepwater repairs.
Study on Development Scenarios of Gas Fields around the Continental Slope of South China Sea
Authors: Feng Wei , Xie Bin
Published: May 2013

The Liwan 3–1 gas field, situates in block 29/26 with an average water depth of 1,300m, represents the first major deepwater discovery in the South China Sea. The development scenario of Liwan 3–1 indicates potentially an efficient way for those gas fields around the continental slope of South China Sea. Before the first appraisal well being drilled, CNOOC Research Institute was commissioned to carry out Liwan 3–1 feasibility study on December 27, 2007. This paper provides an overview of several development scenarios based on the limited data of Liwan 3–1 such as wells information and assumed data such as reservoir profile and pressure. In view of those potential discoveries near Liwan field, regional development strategy is also taken into consideration. As a result, the suggested development scenario is subsea wells tieback to Boosting and Processing Center (BPC). Through BPC, the natural gas is processed and boosted via shallow water pipeline to onshore terminal plant. BPC is actually not only a feasible scenario to speed up Liwan 3–1 development, but also a regional solution for potential fields near Liwan 3–1.

Introduction

The Liwan 3–1 gas field is the first discovery in the deepwater of South China Sea and shared by CNOOC and Husky. Liwan 3–1 locates at a water depth of nearly 1500m and about 65km from PY30-1–1. The discovery of Liwan 3–1–1 well in 2006 showed that the gas production rate almost reaching 5 billion m3/a. Two appraised wells named Liwan 3–1–2 and Liwan 3–1–3 were also completed in the end of 2008 and in the middle of 2009 by West Hercules semisubmersible drilling platform respectively followed by another appraised well later.

In this paper, several development scenarios of Liwan 3–1 gas field are demonstrated firstly. Then the scenarios of BPC (Boosting and Processing Center) are also studied based on a regional development view of potential fields near Liwan 3–1 and the scenario of one APP (accommodation and power platform) plus two PCPs (processing and compressing platform) is recommended. In view of minimizing investment and adopting regional development scenario, subsea wells tieback to BPC is suggested for the development of Liwan 3–1.
Design and Verification of High Load Bearing Interfaces
Authors: Peters Dan , McKie Nigel
Published: May 2013

Exactly how we are to verify the design of HPHT equipment is still being debated. It is almost certain to involve some form of Finite Element Analysis (FEA). FEA is well established as a stress analysis method for use in conventional Pressure Vessel design; however it is not so well established for load bearing interfaces. This leaves a gap in our Design Methods, since load bearing interfaces are intrinsic to Wellhead Equipment Pressure Vessel design. Intrinsic because many of our Pressure Vessels are " capped" by hangers and connectors instead of flanges; if a hanger Load Shoulder fails then the Pressure Vessel above it has failed.

The oil and gas industry would like to make more use of the expertise and experience of ASME but need to assess the consequences of applying ASME's methods product wide. It is possible that ASME VIII can be expanded to make it more directly applicable to the oil industry.

Unique to the oilfield are infrequent but extremely high loads. These loads are much higher than the Working Condition and in most cases they stem from field testing and emergency situations. If the established ASME methods are used for these cases certain projects may not be viable.

The authors will present analyses that assess the load bearing capacity of various field proven Wellhead Equipment designs against some of ASME's Design Criteria.

Introduction

It is essential that we provide clear guidance for engineers designing HPHT oilfield equipment. This involves establishing realistic and uncomplicated Design Criteria: a quantitative method for determining if a design will be fit for purpose or not.

There are many aspects of a design that need to be addressed: Plastic Collapse, Local Strain, Ratcheting, Shakedown, Tri-axial Strain, Serviceability, Fatigue etc… The primary topic of this paper is Plastic Collapse which is usually the starting point for design.

ASME VIII is a code written specifically for Pressure Vessel verification. It is made up of three divisions. Division 1 is a basic design code for simple low pressure vessels. Division 2 is an alternative set of rules that makes use of higher allowable stresses but with more rigorous design and analysis requirements. Division 3 is for the design of high pressure vessels, which are generally defined as being above 10 ksi and allows even higher stress levels. To maintain the same level of safety the higher divisions require progressively more stringent verification methods. Higher allowable stresses lead to the possibility of more compact technology and weight savings, but it is also a way to design viable High Pressure equipment by allowing thinner wall sections, which will allow reliable heat treating. Excessively heavy wall sections can make it difficult or impossible to heat treat and achieve uniform properties through the thickness.
Hero: A New Tool for Hull Inspection
Authors: BECART Romain , Bouchet Christophe
Published: May 2013

The purpose of the underwater inspection of F(P)SO and FSU hulls is to verify the floater's integrity and ensure the safety of personnel and production equipment. It is required by internal rules and by international maritime conventions applicable to floating units.

Today, hull inspections are performed by divers who operate in relatively deep waters (down to 30 m), on live installations and in an open sea environment subject to swell and variable weather conditions, all of which add up to significant risks for the divers' safety. These operations also involve mobilizing considerable logistic means for several weeks (support ships, decompression chambers, numerous teams).

An integrated solution has therefore been developed to perform this task with dedicated ROVs. It offers important advantages not only with regard to safety by limiting the number of diver interventions and thus the risk of accidents, but also in terms of reducing OPEX, as the HERO can operate for longer than divers and in harsh sea conditions which usually limit the duration of diving campaigns.

HERO is now under qualification and the first industrial trials have started.

This paper develops the method for specifying the equipment, positioning the system with NDT measurement tools (CP and US probes, magnetic sensing), HP cleaning and operational deployment. It also presents the results of various qualification tests carried out in the laboratory and the harbor to develop this new technology such that it satisfies hull inspection specifications.

HERO inspection methodology and performance have now been qualified by the main classification companies (Bureau Veritas, Lloyd's, DNV, and ABS).

The main applications envisioned for this solution are:Underwater inspection in lieu of drydocking (UWILD) for classification requirementsAccurate hull evaluation for life-extension purposesAssessment of floating assets prior to sale or conversion
A Comparison of Dynamic and Static Pile Test Results
Authors: Stevens Robert
Published: May 2013

Class A predictions of static pile capacity for three projects are presented. Pile driving is monitored using strain transducers and accelerometers attached near the pile top. The CAse Pile Wave Analysis Program (CAPWAP) is used to estimate the distribution of the soil resistance to driving along the length and at the toe of the pile. The static capacity is predicted from dynamic pile test results and compared to the actual static load tests.

Our first case history is for two 1235-mm-diameter steel pipe piles driven to penetrations of 12.5 and 20 m with a Junttan HHK 14S hydraulic hammer. When the piles were redriven, there was little change in the shaft resistance and end bearing. Therefore, the shaft resistance obtained from the CAPWAP analyses was compared directly to the results of tension tests performed about 50 days after redriving.

Our second case history is for a 914-mm-diameter steel pipe pile redriven using a Berminghammer B-6505 diesel hammer in dense to very dense silty sand to sand, stiff to very stiff clay, and very dense silty sand. The pile was redriven 46 blows for 25 mm of movement, and CAPWAP analyses were performed at the beginning and end of restrike at 47.5-m penetration. The minimum compressive pile capacity was predicted by adding the shaft resistance for Segments 1 through 13 at the beginning of driving and the shaft resistance for Segments 14 through 24 at the end of driving, and compared to a load test performed 5.5 months after driving.

Our third case history is for a 2000-mm-diameter steel pipe pile driven with a Menck MRBS 5000 steam hammer to a penetration of 30.6 m in very silty clay. The compressive pile capacity was predicted for a load test performed 52 days after driving using CAPWAP results for the end of initial driving and the beginning of restrike after a delay of 43 hours for one of the reaction piles and an estimated dissipation in pore pressures.
Rigless Intervention: Case Studies, UK and Africa
Authors: Bosworth Phillip , Willis Oliver
Published: May 2013

This paper describes and highlights, via two case studies, the benefits of conducting rigless subsea well intervention from specialist monohull vessels. The case studies provide an overview of the operations on subsea wells, from intervening through the production tree (XT), to XT change-out and well P&A / wellhead removal operations.

A brief overview of rigless intervention techniques and equipment is also described.

The operations described in the case studies were completed in two very different operating regions. The United Kingdom North Sea (UKCS) and West Africa (Equatorial Guinea).

In the first case study, the paper describes how over a 68 day period a Light Well Intervention Vessel (LWIV) successfully and safely performed mechanical repair & well maintenance (and well integrity surveillance); data acquisition (production logging), well suspension (for a XT recovery); scale-squeeze pumping operations (production enhancement) and finally well plug and abandonment (decommissioning) on a variety of wells across several subsea Fields.

The second case study summarises a 105 day campaign in which a LWIV was contracted to undertake subsea well interventions (for both well maintenance and production enhancement needs) and a temporary well suspension (for a XT change-out) on multiple subsea wells within a Field. The vessel optimisation, through performance, coupled with its ease and speed of transit and set up (DP3 rated) were key to this particular campaign as the 7 wells identified to be worked on by the Operator were a number of kilometres apart precluding the efficient use of a moored unit.

Introduction

Rigless and Riserless Light Well Intervention (RLWI) activities have been executed for over 25 years across the North Sea. The purpose of these case studies is to demonstrate that with effective project management (planning, developing, execution and close-out) the use of RLWI is both a flexible and extremely cost effective method which Operators can utilize for a single well, or across a number (a campaign) of subsea wells, irrespective of subsea tree type or close proximity.

Case study #1 outlined below summarizes the flexibility & efficiency of multi-service LWIV in the North Sea with the ability to perform intervention/subsea operations in a cost effective and efficient manner, allowing remedial operations to be conducted in order to maintain well integrity, and other remedial well servicing techniques in order to maintain and often enhance hydrocarbon production (manage life of well productivity) before eventual Cessation of Production.
Fatigue Testing of Shrink-Fit Couplings for Joining High Strength Steel Riser Pipe
Authors: Shield John , Bowman Jonathan , Wightman John , Pappas James
Published: May 2013

The shrink-fit connection has been designed and developed to enable the manufacture of high pressure deepwater riser systems when traditional pipe join methods such as welded or threaded and coupled are not feasible. For example, welding may not be suitable for joining high strength steels due to hardness limitations.

Shrink-fit technology has been employed for manufacture of a full bore, high pressure, shallow water drilling riser system in the North Sea. For this application, development testing focused on static capacity, sealing, and manufacturability, as joint fatigue life was not a limiting design case.

In 2012, Subsea Riser Products (SRP) and RPSEA, together with project champions Chevron and BP, collaborated to investigate the potential of the technology in deepwater drilling and production riser systems. In these systems, riser weight and fatigue life often drive the design, motivating the use of thinner wall, high strength steels and efficient, fatigue resistant connections.

SRP's analysis had previously demonstrated the shrink-fit connection's potential: very low geometric stress concentration factors (SCF) and parent metal material classification.

A test program was devised to test the manufacturability of shrink-fit joints made from high strength (>100ksi) mill pipe and forged couplings. This aspect of the program demonstrated the economic viability of the technology, by using readily available project materials; and a construction method that could potentially be used on riser installation vessel (e.g., J-lay).

A second aspect of the test program focused on the installed performance of the connector: burst, sealing, and fatigue life. Six specimens were produced and tested on a resonant bending rig at various stress levels to produce an indicative fatigue curve. Metallurgical failure analysis and comparisons with calculated results then enabled development of a plan for future testing and improvement of the connector performance to commercialize it for deepwater use.
New Developments in the Simulation of Slurry Behaviour in Spooled Hoses for Offshore Mining Applications
Authors: Rhee Cees van , Munts Edwin , Bosch Jochem van den , Lotman Rick , Heeren John
Published: May 2013

The presentation will describe the developments to analyze mining slurries in spooled risers and the benefits of this knowledge in de the design process of spooled risers.

Current technology in deep sea mining applications dictates that the slurry produced by the seabed mining tool is transported using a flexible riser to the vertical riser inlet. The vertical riser, similar to oil & gas risers, is a series of steel pipes which transports the mineral slurry from the seabed to the mining support vessel. New developments in riser technology enable flexible hoses to be used for applications in water depths up to 500 meters.

In this application, a single riser using flexible hoses is used for transporting the slurry from the Seafloor Mining Tool (SMT) to the Mining Support Vessel (MS). The advantages are (i) that the flexible riser can be launched and recovered by spooling it on a drum installed on the mining support vessel and (ii) can cater for varying water depths.

In the section of flexible hoses spooled on the drum, the slurry behaves differently from what might be expected. The paper starts with a description and consequences of the phenomena that occur in elbows and in the spooled hoses at the entrance of the spool. Followed by the development of the slurry to a new stratification regime along the first part of the spooled hoses and finally the phenomena which occur thereafter. The envelope of slurry conditions (concentration, particle size distribution and velocity) have an impact on the dynamic pressure losses in the spooled hoses.

Insight into the slurry behaviour is obtained using 3D CFD simulations. Verification is performed with information retrieved from literature. To represent better the slurry behaviour a pressure ratio, Rpressure, is introduced, which is the local pressure gradient in the spool divided by the pressure gradient of a straight pipe. When the total pressure ratio is calculated over a typical length of a design configuration, like an elbow or complete turn, this figure can be compared with other results found in lecture. The envelope of this figure along its design length is even more important. The changes can be related to changes in mixture behaviour.

The new insights not only explain why some slurries show the secondary flow of Dean and others don't, but also why some slurry mixtures show lower dynamic pressure losses compared to slurry in a straight pipe. From a practical point of view construction parameters as the spooled riser diameter to drum ratio and consequences of alignment in the horizontal or vertical position are discussed.
Including Enabling Technologies in the Wellbore Construction Basis of Design: Smart Strategy to Benefit From Casing While Drilling, Open-hole Expandable Liners, and Liner Drilling
Authors: Siddiqui Asim A , Karimi Moji
Published: May 2013

Historically, conventional drilling has been considered the method of choice for drilling challenging wells; substitute methods have been used only if conventional drilling has failed or proved ineffective. Some of these innovative alternatives are Casing while Drilling (CwD), expandable liners, and liner drilling (LD). This study investigates how inclusion of these enabling technologies in the basis of design (BOD) can help operators achieve greater benefits in comparison to use in contingency plans. Casing/Liner Drilling has been successfully employed as a solution to lost circulation and wellbore instability. Moreover, casing/liner seats can be optimized and pushed further, taking advantage of Plastering Effect wellbore strengthening. Due to the different drilling dynamics of Casing/Liner Drilling, special measures should be taken to maximize the effectiveness. Unfortunately, sometimes the implementation of these measures is compromised since they have not been included in the BOD. This study reviews these issues and provides recommendations. Open-Hole Solid Expandables can be used in telescopic deep-water well plans, primarily to save borehole diameter and hence improve production. Usually more troublesome zones are encountered as we drill deeper, hence the time window to leave the wellbore open will be shorter. It is recommended that expandable liners be used further up the wellbore in a lower risk environment as opposed to trying to save diameter after the casing has been set higher due to drilling problems. Examples are provided demonstrating the benefits of including the technology in the BOD. As wells get more challenging, the industry needs to pull alongside the enabling technologies accordingly. CwD, LD, and Solid Expandables are proven drilling hazard mitigation technologies, which if included in the well plan early can be implemented more effectively than if considered as contingency plans.

Introduction

Lost circulation and wellbore instability have plagued the drilling industry since its onset. Despite extensive research aimed at understanding the occurrence mechanism for these unwanted events, the solution has been the same for a long time; setting additional casing and adding lost circulation material to the drilling fluid have been the only option. On the other hand, the complexity of wells and severity of problems have constantly increased to the point that some prospects are simply undrillable with conventional methods, or they incur a huge time/cost burden that challenges the economic feasibility of the project. Only in the past decade have new solutions such as Managed Pressure Drilling (MPD), CwD, solid expandables, etc., emerged that allow new prospects to be explored, and provide new life for fields considered for abandonment because they had reached the technical limit of conventional methods.
First Floating, Production, Storage and Offloading Vessel in U.S. Gulf of Mexico
Authors: Ganguly Partha , Mastrangelo Carlos Ferraz , Daniel Jeremiah
Published: May 2013

This paper is based on work performed during design, implementation and operation of the Cascade and Chinook fields in ultra-deep waters of the U.S. Gulf of Mexico. It describes how Regulatory compliance was accomplished for this the first Floating Production Storage and Offloading System in the Gulf of Mexico and the decision making towards selecting a disconnectable Floating Production Storage and Offloading System and critical activities from award to operation of this innovative disconnectable Ultra Deep Water FPSO in over 8,200 feet of water, making it the deepest moored FPSO. It is an Early Production System (EPS) that will establish production potential prior to installing the full production facility for the production potential anticipated. Crude is offloaded by tandem offloading to Jones Act shuttle tankers.

Introduction

The path Petrobras took, from applying for approval from the U.S. Regulatory Agencies for the use of a Floating Production Storage and Offloading system (FPSO) with tandem offloading to purchase of the Cascade and Chinook (C&C) fields and to produce both fields with a FPSO, was challenging in many ways.

Petrobras accepted the challenges of having to incorporate new technology, breaking records in the process to achieve production in these ultra deep water fields, complying with Regulatory Agencies requirements that did not necessarily have language in the regulations that were specifically applicable for an FPSO in U.S. waters and to install an EPS FPSO to produce in gulf of Mexico where no FPSO had ever produced before.

FPSO technology for use as a production facility was considered state-of-the-art worldwide but was not yet accepted in the U.S. Gulf of Mexico (USGoM), when Petrobras embarked on the project to install the first FPSO in USGoM, realizing it would be a challenge. Petrobras development strategy was to produce C&C fields from a common facility. Petrobras successfully achieve their goal of producing the C&C fields with the first FPSO in the USGoM. The EPS FPSO, BW Pioneer, is currently producing from both these fields.

This paper will provide insights into the path taken to successfully complete this challenging project that included; close cooperation with US Regulatory Agencies to accept FPSO production facilities, changes in ownership of the fields, submission for approval of concept to the MMS and USCG, steps in the project to get the leased EPS FPSO to the field and tools to assist operations and production.

Subsequent to completion of the C&C project, the US Regulatory Agencies preference has shifted from a permanently moored FPSO (as evaluated in the EIS) to a disconnectable FPSO (as approved for C&C fields).
GTL FPSO: An Alternative Solution to Offshore Stranded Gas
Authors: Ahn Sung-Il , Park Taeshin , Choi Dong-Kyu , Denholm Douglas , Lim Hye-Won , Kwon Hyuk , Zhang Lifeng , Kim Hyun-Jin
Published: May 2013

The sustained, increasing world energy demands have led to very high oil prices. In parallel, there has been a significant increase in interest in economic and environmentally sensitive solutions for the monetization of remote, stranded gas offshore. Current global natural gas reserves total approximately 6,100 tcf, according to EIA estimates. Roughly half of these are considered to be stranded gas that is uneconomical for market delivery due to the remote location of potential markets, lack of economic transportation and infrastructure, or lack of conversion technology. Such regions with significant stranded gas reserves include Northern Australia, Vietnam, and Indonesia.

GTL (Gas-to-Liquids) FPSO (Floating Production Storage and Offloading) offers an attractive new solution to monetize these remote, offshore, stranded gas fields. Products of the GTL process are clean transportation fuels ranging from diesel to jet fuel that can be readily used in the existing energy infrastructure. Although this option has been considered in the past by Syntroleum and Statoil in mid-2000, a reexamination of this option is warranted due to recent advances in both GTL and FPSO technology. New GTL commercial plants have recently begun production in Qatar, utilizing technologies by Sasol and Shell with the latest advances in the process technologies and catalysts. Membrane and Process Intensification technologies show considerable promise in making GTL an attractive option in the future. The newly built Oil FPSOs (Pazflor and Agbami) instill confidence that large oil and gas processing operations can be safely and economically performed on an FPSO.

DSME has recently completed a feasibility study as part of a multi-year development program to acquire the basic technology and engineering for GTL FPSO. An assessment was made on the technical feasibility of commercial and near-commercial-scale technologies, and a preliminary design concept of the GTL process was produced for the topside. This study utilized technologies that best met the needs of the FPSO application and the corresponding preliminary design concept of the hull to support the topside GTL process. Additionally, preliminary market analysis was performed to better define the scope of GTL products to be produced. Economic analysis was performed to identify the major cost factors and understand their sensitivity on Project economics.

The results of this feasibility study to date suggest that this GTL FPSO design concept is technically feasible. Its clean fuel and chemical feedstock would be attractive to the market, and the design concept is economically competitive within the range of the current Project cost factors. Future work will be directed to develop a more definitive process, hull design, and Project economics, and will bring commercial realization of this innovative approach of monetizing offshore stranded gas fields.
Liuhua 11-1 FPS Life Extension: Classification Society
Authors: QIAN WEI
Published: May 2013

The FPS, " NANHAI TIAO ZHAN", is a major component of the Liuhua 11–1 project. It is a converted from a Sedco 700 series mobile offshore drilling unit (MODU) into a floating production system. This FPS hull and mooring system are designed to maintain station in 100 years return typhoon environment.

The Semi-submersible FPS " Liuhua 11–1" registered ABS class. The latest request from the client was a comprehensive assessment for 15 years life-extension. According to the contract between the client and ABS, ABS surveyor should do multiple survey to this unit, including on-site inspection for the unit structure (welding and corrosion), steel plates thickness measuring, etc. In addition, ABS engineer should do strength re-assessment to the structure when received the submissions of Global Strength Analysis and Global Fatigue Analysis from the client, then make comments about structure reinforcement according to the re-assessment result. This paper is to list the related requirements from related ABS rules and guides, including ABS Guide for Building and Classing Floating Production Installations, ABS Rules for Building and Classing Mobile Offshore Drilling Units, ABS Guide for Fatigue Assessment of Offshore Structures, and other regulations, such as IMO Code for The Construction and Equipment of Mobile Offshore Drilling Units, etc., other industrial standards for reference during analysis.

Introduction

The Liuhua 11–1 oil field is the largest oil field in the South China Sea so far. It was originally developed by a consortium of Amoco, CNOOC and Kerr-McGee in 1995. The main components include a floating production system " NANHAI TIAO ZHAN", and a floating production, storage and offloading vessel " NANHAI SHENG LI" which is located about 3000 m northwest of the " NANHAI TIAO ZHAN" FPS.

The original Liuhua 11–1 project was the first deepwater development project in China with in more than 1000 ft water depth. Liuhua 11–1 project was one of the major deepwater developments adopting new technologies with unique features in early 1990's for the whole offshore industry. This oil field is still in production. A new oil field Liuhua 4–1, about 11km away from Liuhua 11–1, was planned to be processed by the Liuhua 11–1 FPS facilities via subsea tieback. In this regard, additional topsides capacities and life extension for the aged semi-submersible FPS " NANHAI TIAO ZHAN" were requested. Significant technical challenges were imposed to the project team for the life extension and dry docking upgrade of the FPS. The FPS upgrade project started in 2010, and riser and mooring offshore reconnection was completed in 2012. The upgraded Liuhua 11–1 FPS is now back to the oil field and in production again successfully.
Slug Response in Subsea Piping: Advancements in Analytical Methods
Authors: Kavanagh William Kieran , Connaire Adrian , Payne Jason , Connolly Aengus , McLoughlin Jonathan
Published: May 2013

During the life of certain offshore fields, slug flow can lead to alternating internal fluid conditions and irregular flow characteristics in subsea pipelines, risers and spools. These conditions generate time-varying fluid forces at locations of change in flow direction which can lead to significant vibration, fatigue damage and in some cases push structural utilizations above allowable limits. In recent years, slugging related problems have resulted in the change-out of critical subsea equipment.

Difficulties exist in predicting and characterizing slug flow in a representative manner due to the complexity of the loading. As a result, the current state of practice with regard to predicting response to slug flow is not considered mature technology and is not dealt with consistently across the industry. Furthermore, subsea design practice and analysis approaches, where they exist, lack sufficient validation. Widespread industry interest in the topic has lead to the requirement to develop enhanced analytical methods, full scale validation and industry guidelines.

This paper deals specifically with the mechanics of combining the various slug load contributors, including centrifugal, bend impact and fluid inertial loads in structural models and their effects on stress distributions in pipeline systems. The paper illustrates how enhancements in analytical methods now allow convenient definition of slug flow inputs and automatic generation of dynamic load time histories. Results are presented for a generic subsea piping configuration which is considered particularly susceptible to slug load response. A comparison of responses from different structural software packages is presented for representative design conditions and parameter variations.