bluuebunny/crossref_metadata_2025 huggingface dataset:
Tethered Catenary Riser: A Novel Concept for Ultradeep Water
Authors: Legras Jean-Luc
Published: May 2013

A new riser concept is proposed by Subsea 7 for field development in deep and ultradeep waters: the Tethered Catenary Riser (TCR)-patent pending. The concept consists of a number of steel catenary risers supported by a subsurface buoy which is tethered down to sea-bed by means of a single pipe tendon and anchored by means of a suction pile; flexible jumpers are used to make the connection between the Floating production Unit (FPU) and the buoy. Umbilicals run without interruption from the FPU to their subsea end while being supported by the buoy.

The system has all the advantages of de-coupled riser arrangements: flexible jumpers effectively absorb platform motions, thereby the rigid risers and tendon have very small dynamic excitation. The system can be installed before FPU arrival on site, which improves the time before first oil. Analyses have shown that, with adequate geometry of the buoy, the latter is sufficient stable to induce acceptable tilt and twist when different arrangements of SCRs and flexible jumpers are installed, and under accidental scenarios during the in-place life.

The riser system is best designed for a number of risers between 4 and 8, in addition to a number of umbilicals, thus convenient for one or two drilling centers.

Results of the basic engineering work on the TCR clearly indicate that it is possible to have a robust design using presently qualified materials and technology. The components used in the TCR are all field proven as they are commonly used in existing riser systems.

As a result of installation studies, a method very similar to the one commonly used by Subea7 for Single Hybrid Risers (SHRs) has been selected for the buoy and tether system. Placement of rigid risers, jumpers and umbilicals is as done by Subsea 7 for the BSRs. This method is well adapted for installation by the new Subsea 7 flagship vessel Seven Borealis which is able to perform heavy lift and pipe laying.

The Tether Catenary Riser is a credible option for use in deep water developments all over the world. Since all the components, design methods and installation procedures are fully qualified and familiar to Subsea 7, the concept is cost effective and ready for project application.

Introduction

A lot of well proven riser concepts have been used in deepwater for different environments, in particular, steel or flexible risers in catenary or lazy-wave shape, and single or bundle Hybrid Riser Towers (HRTs). Nevertheless, for some application new concepts are deemed more attractive and selected, as the Buoy Supporting Riser (BSR) for ultra-deep water offshore Brazil. But other ideas of riser concept emerge from the review and comparison of pros and cons of existing riser systems, trying to take the better of each one. The TCR is an adaptation of the BSR, but with a simpler tether arrangement and easier installation method. It can also be seen as a SHR with a number of SCRs attached to the buoyancy tank. The concept is described below as well as design methodology, application example and installation outline procedures.
A Risk-Based Approach To Managing the Integrity of an Ageing FPSO Hull
Authors: MacLean Calum , Hagood Scott
Published: May 2013

The hull of any FPSO not only provides the platform for the production facilities and accommodation, but also incorporates the storage and offloading facilities for the field (and potentially other fields). As such the hull acts as a vital "hub", critical to both the operation and export chain.

For FPSO's (like ships) there already exists an "experience based" prescriptive regime for integrity management of the hull structure (Class). This, however is based upon maintaining a minimum standard for a forecast window of only 2.5 to 5 years as per a trading oil tanker where opportunities to drydock the hull to carry out inspections and any required maintenance can easily be accommodated.

Adopting this approach without due consideration of the constraints of FPSO operations imports a significant risk to the viability of an asset and does not guarantee the avoidance of having to go to dry-dock.

Understanding the potential dangers of unquestioningly following Class rules and requirements, Hess have sought to adopt an alternative risk based approach to mitigate the risks to both integrity and operational functionality by proactively understanding the condition and limitations of the hull structure, putting in place an appropriate level of inspection, having robust assessment criteria and implementing increased inspection regimes or undertaking appropriate repairs to deficiencies identified in the hull structure.

This paper presents the journey travelled by Hess from prescriptive Class rules to a risk based Class regime from the period 2006 to present. It will describe the asset; discuss Class rules and a risk based approach to integrity; and then describe how these are applied to the FPSO Sendje Ceiba.

Hess Equatorial Guinea Overview

Hess Equatorial Guinea operates the Ceiba and Okume Field developments. The Ceiba Field is comprised of subsea well clusters producing to FPSO Sendje Ceiba where the production is processed, stored and then offloaded through a CALM buoy. This field commenced production in 2000 and the license to operate expires in 2029.

The Okume Field consists of 4 bottom founded platforms and 2 mini-TLP's. Okume production is fully processed prior to being exported via a 20 km pipeline to FPSO Sendje Ceiba for storage and offloading. This field commenced production in 2006 and the operating license will expire in 2032.

Combined production from the two developments peaked at approximately 120,000 BPD and is currently in the range of 90,000 BPD. The FPSO serves as the storage and export terminal for both the Ceiba and Okume developments with an effective crude oil storage capacity of 1.78 million barrels. Liftings (sales) are made in 1 million barrel parcels.

These developments are located offshore of the city of Bata which is located on the West African mainland just north of the equator as shown in Figure 1 below. The equatorial location of the developments results in a very benign operating environment devoid of named storms.
Evaluation of Wellhead Fatigue Using In-Service Structural Monitoring Data
Authors: Rimmer Alex , Howells Hugh , Ward Phil
Published: May 2013

To conduct offshore drilling activities safely there is an increasing requirement to understand the strength and durability of subsea wellheads and conductors. The use of modern drilling rigs, with larger BOP stacks and drill-through trees, combined with longer well durations and multiple intervention operations is now producing far greater levels of fatigue loading on subsea wellheads.

The prediction of the fatigue response using numerical analysis has traditionally taken a conservative approach to mitigate against the risk of fatigue failure of the drilling riser and wellhead equipment. However, using this conservative approach, the allowable fatigue design limits are often predicted to be exceeded before the target operation durations are achieved. This can lead to costly last-minute design changes, the necessity for which often remains unproven.

To improve the understanding of the fatigue behaviour of these systems, 2H has utilised in-situ monitoring of the drilling riser and wellhead response on recent projects in the Gulf of Mexico and the North Sea for a number of Operators. Wellhead fatigue life predictions, for which minimal in-service validation has traditionally been available, have been found to be conservative by factors of 10 or greater based on the field measurement data collected. Understanding the root causes of these levels of conservatism allows a critical view to be taken of analytical models and fatigue results. This in turn facilitates the safe removal of conservatisms from the analytical approach and associated cost savings for field operators. Further, in-situ monitoring allows management of fatigue during drilling with real-time tracking of fatigue accumulation providing feedback for safer planning of operations.

This paper describes the use of wellhead response monitoring programmes on a recent drilling campaign in the North Sea. Comparisons are drawn between the measured response and the analytically predicted wellhead fatigue results. Where differences are identified, the back-analysis activities conducted to identify the causes of those differences are discussed. Finally, the applicability and limitations of those findings for the refinement of wellhead fatigue predictions in other applications are outlined.
Minimizing the Risk of Coating Failure
Authors: Kattan Raouf
Published: May 2013

Through life costs are often dictated by the ability to minimise corrosion, in particular in splash zones or ballast tanks. Coating system failures on some offshore structures/vessels are not only expensive but have created concerns for through life maintenance and repair as they could possibly increase the risk of assets coming off-stream as a result of failure as well as having an adverse impact on the cost of any life extension programme.

The proper selection of a coating system is critical to the effective operation of the structure/vessel and should therefore be engineered as an integral solution, rather than left to chance. Owners/operators are often misled by considering only the total thickness of steel rather than the corrosion allowance that is built in. it is this corrosion allowance that the coating system must be engineered to protect.

All owners of offshore structures want a structure/vessel that meets requirements for through life performance. Coatings play an increasingly important role not only in maintaining asset value but also ensuring in service performance sustaining the income stream by preventing corrosion, fouling, enabling various chemicals to be handled and keeping the cosmetic appearance of the structure in line with corporate image requirements.

Vessel design if considered at an early stage, could contribute significantly to increasing the throughlife performance of coatings while the proper selection of coatings whether for anti-corrosion, fouling prevention, cosmetic appearance and specialist tanks, is critical to the effective a low cost operation of the structure through life.
Combining Contemporary and Tested Technologies to Achieve Successful Deepwater Extended Reach Completions
Authors: McCarty R. Andrew , Broderick Mike , Brister Ray , Stewart Mike
Published: May 2013

Many technologies on the market today are considered contemporary or modern such as Inflow and Injection Control Devices (ICDs), especially when used with screens, tracers, and swell packers. Tested technologies include extended reach drilling in deepwater environments.

This paper details the design, planning, and execution of completions from a tension leg platform in just such an environment. A baseline completion consisting of ICDs, stand-alone screens (SAS) and swell packers was initially selected. The selection process involved technical evaluations on types of ICDs, injection vs production screens, filter medias, length, type, and materials for swellable packers, all of which were not only evaluated in combination with each other but also their feasibility and utilization in deepwater extended reach applications.

Managing ECDs and riser vibrations, torque and drag, uniform inflow and outflow distribution, effective sand control, tracer tracking, etc., are all good technical search topics unto themselves. But this Indonesian deepwater project combines them all resulting in positive design, cost, time, production, and execution metrics in multiple production well projects.

Lessons Learned Registers were carried from well to well resulting in significant Non-Productive Time (NPT) reductions of initially 30–40% from baseline benchmarks and acknowledged international databases with further reductions resulting from the applications of the lessons learned and best practices implemented.

Introduction

This field was the first deepwater development in Indonesia. It lies at a water depth of approximately 3,000 ft offshore of East Kalimantan. The field development, on production since 2003, consists of a Tension Leg Platform (TLP) with 28 dry tree wells, a floating production unit (FPU), and two 60 km export pipelines (12 " oil and 12 " gas) to shore. The Extended Reach Drilling (ERD) Project comprises four producers reaching outlying reservoirs that have proven undeveloped reserves from previous delineation penetrations. The reserves lie at extended reach drilling ratios of 1.5 to 2.5, just beyond conventional drilling envelopes used to drill the 28 existing development wells. Actual well names were changed for this paper to Wells A, B, C, and D.
Evaluation of the Hydrolysis Behaviour of PA in High-Pressure CO2 Environments
Authors: Buchner Stefan , Clevelario Judimar , Sheldrake Terry , Pires Fabio
Published: May 2013

In the latest offshore developments to be carried out in Brazil, supercritical CO2 (scCO2) injection into the fields is being considered as a potential application. This injection operation will gradually lead to high levels of CO2 in the produced fluids, creating additional challenges for the materials used in riser systems specifically designed for such applications. Upcoming developments are being carried out in ultra-deep waters which can reach 2500 m. Flexible pipes are considered one of the options for both production and CO2 injection pipes due to performance in such scenarios and fast implementation when compared with conventional rigid riser systems. However, the high levels of CO2 and the presence of water in the conveyed fluids has raised some questions about the utilization of polyamides in such applications, and the applicability of API 17 TR2 to properly predict the hydrolysis of polyamides in such extreme environments. Based on this new scenario, GE Oil & Gas has implemented a specific R&D program to evaluate the hydrolysis behavior of polyamides within environments containing high CO2 partial pressure, exceeding 400 bar. This paper summarizes the experimental results assessed during the test program carried out and discusses the applicability of polyamides in both oil/gas production and CO2 injection flexible pipes.

Introduction

Though CO2 reinjection into geological formations is not a new subject, in recent years its importance has gradually increased within the offshore industry, due mainly to adoption of carbon capture and storage (CCS) and enhanced oil recovery (EOR). The feasibility of offshore reinjection operations was demonstrated in 1996 with the development of the Sleipner field in Norway as part of a CCS project [1], and again in 2004 in Algeria with the development of the In Salah natural gas field [2] with approximately one million tons of CO2 per year being separated from the produced natural gas and then reinjected into the geological formation. In order to make CCS cost effective and economically feasible, the CO2 reinjection may be used as part of an EOR process to improve production and fight reservoir depletion [3]. The need for CCS is even greater in the development of offshore projects in the Brazilian pre-salt cluster in ultra-deep water, an environment with several technological challenges. According to Nakano [4] the produced oil in this new exploratory province will present a high gas : oil ratio (GOR) and the dissolved gas will present a CO2 concentration ranging from 8 to 12% during the first years of production. Based on this scenario, CCS and EOR programs will be put in place [4] [5] to comply with environmental regulations and make the project more cost effective.
Comparison of Seafloor and Shallow Stratigraphic Conditions Mapped From 3D Seismic and AUV Data at Two Deepwater Areas, Keathley Canyon, Gulf of Mexico
Authors: Scherschel Craig , Thomson James A.
Published: May 2013

This paper presents results of an integrated interpretation effort to understand seafloor and shallow stratigraphic conditions at drill sites within two prospective areas in a deepwater portion of the northern Gulf of Mexico. Datasets of different resolution were utilized, including AUV multibeam echo sounder data. These highest resolution AUV data were collected early in the life of the two projects to assess seafloor conditions. In one instance, the AUV data were acquired to comply with newly issued governmental regulations for archaeological clearance studies. As an added benefit, the required AUV data also provided a clear view of potential seafloor geological constraints giving BP and co-owners early insight into factors such as chemosynthetic community indicators, seafloor expulsion features and hardgrounds. These insights will be used and further developed throughout the life of the projects, affecting work not only during early exploration, but also in an exploration success case, through appraisal, development and into production phases as a baseline survey.

The primary purpose of this case study was to learn how geophysical data collected at different resolutions during subsequent project phases could be leveraged to efficiently discern potential constraints to operations resulting from geological processes affecting seabed and near-surface stratigraphy. Additional insight came from a comparison of geological conditions at the two sites. These conditions were similar at the nearby sites but key differences were noted.

The steps followed may define a multiphase approach that efficiently uses site survey results and supports early acquisition of detailed site investigation data. In addition to obtaining detailed site investigation data early on, it is shown that obtaining more than the minimum coverage area needed to clear the initial exploration locations in a prospect has the added benefit of providing broader geographic understanding of seafloor conditions away from the prospect center, revealing potential constraints that would affect appraisal and development locations while reducing or eliminating the need for subsequent surveys.

A comparison of conditions at the two prospects showed similar geological settings and highlights the different needs for high-resolution site investigation data at different stages of a field development, not just during the development phase, as has been practiced previously. Results of the site investigation evaluation have been incorporated into planning of wellbore trajectories at prospects in the Keathley Canyon protraction area and in documents submitted to comply with regulatory requirements of the Bureau of Ocean Energy Management.
Analyses of SCR with Pull-Tube Using ABAQUS and Flexcom
Authors: Liu Hugh Y , Wang Kevin , Yiu Flora
Published: May 2013

Pipe-in-pipe analyses of in-place SCR (Steel Catenary Riser) within pull-tube (PT) or pull-in analyses of SCR through PT are computationally complicated problems in offshore development in the application of SCR hanging off through PT from a platform such as Spar. In the past, those analyses have been done primarily using ABAQUS, an advanced nonlinear FEA commercial tool. A benchmark study of pipe-in-pipe analysis, i.e. SCR through PT, was conducted to compare the performance of ABAQUS and Flexcom, a package popular in the offshore oil and gas industry dedicated to flexible structures like risers or mooring lines. Both static and dynamic loading conditions, as well as the pull-in process were included in the paper. Bending moment, tension, shear force, and von Mises stress of both SCR and PT were compared.

The comparison shows that Flexcom pipe-in-pipe analysis of in-place SCR within PT or pull-in analysis of SCR through PT can obtain satisfactory results in bending moment and stress for both static and dynamic simulations with close agreement with ABAQUS. While the friction between SCR and PT is not accounted for in Flexcom, its effect is mainly on tension especially of PT, and insignificant for bending moment and bending stress, which governs the strength and fatigue performance of both PT and SCR at the upper hang-off region.

This study indicates that it could be adequate to use Flexcom to conduct pipe-in-pipe analysis with much better efficiency for analysis of in-place SCR within PT or pull-in analysis of SCR through PT.
Determining the Cause of Osmotic Activity in Paint Films and Its Role in Substrate Corrosion
Authors: Mills George
Published: May 2013

The process of osmosis is a natural phenomenon involving the movement of SINGLE small molecules through a " porous or simi-permible " film. The skin of tomatoes will crack after swelling from moisture ingress. Pickles will shrink as moisture is lost from a cucumber soaking in brine. ALL polymeric organic films are subject to small molecule migration within the film. This WILL occur to varying degrees dependent on factors such as the polarity of the migrating specie, degree of cross-linking of the polymer matrix, temperature, amount of formulated inert mineral fillers, and a myriad of other factors. Osmotic activity in polymeric paint films is a common coating failure mode. Corrosion of the metal substrate, typically, will follow if not protected by an active cathodic electrical potential, chemical additives, or other means.

Osmosis involves the transmission of single molecules through the matrix. As such, since the definition of a gas is " a collection of single molecules ", osmosis is a gas phase transmission and follows the General Gas Laws. An understanding of the process of osmotic activity in paint films will assist the practitioner in determining the source that drives the osmosis and in analyzing the paint failure.

Osmotic activity in paint films is explained and the analytical procedures and instruments used to identify its driving source(s) are discussed. Osmotic activity requires a solvent and solute. Not all solutes are introduced during application or manufacturer of the coating. While some are present at or during application, some are generated insitu from chemical reactions during service. The source and chemistry of some of these are discussed. Cathodic protection (CP) generates hydroxyl ions that cause additional osmotic activity. Fermentation of sugars generates acetic acid that can lead to osmotic activity in tank linings.
Empreinte: New Horizons for Pipelines Integrity Assessment
Authors: BERNARD Michel , FONTANABONA Julien , GAFFARD Vincent , POPINEAU Dominique , WIET Paul
Published: May 2013

Integrity assessment of pipelines exhibiting defects becomes more and more an issue in the oil and gas industry in particular because of field lifetime extension. Three levels of defects assessments can be distinguished:" Level 1 " assessments are based on very simplified acceptance criteria such as a dent depth. They are very conservative and their main advantage is to allow assessments in very short time period." Level 2 " assessments are based on analytical/empirical models supported by full scale testing. In principle, they cannot be used outside the conditions covered by full scale tests." Level 3 " assessments are based on advanced calculations such as finite elements. They allow reducing conservatisms but they need detailed material data and are, in general, very time consuming.

The goal of " Empreinte " is to perform reasonably conservative " level 3 " assessments in a very short time period (typically within 48 hours from defect discovery to assessment).

" Empreinte " is basically a pre and post processor to Abaqus finite element calculations. It was originally developed to assess the integrity of pipelines exhibiting severe dents with taking into account that when a dent is discovered, the only available information is, most of the time, the actual pipe geometry (defect profile and remaining wall thickness).

The principle of " Empreinte " is to use the final pipe profile to design back a " virtual tool " from which the damaging process is modeled. Then, the burst strength of the damaged pipe is determined from finite element calculations. This actual burst strength is used to derive a safe operating pressure.

" Empreinte " validation is supported by full scale tests in various conditions. It includes criteria to capture failure by plastic collapse and by ductile fracture after significant damage development. " Empreinte " has been recently extended to the assessment of dents submitted to cyclic loading conditions using the Dang Van criterion.

The enlargement of " Empreinte " validation tests database has to be a continuous effort. Updating materials data requirements for next pipeline projects is also a target.

" Empreinte " has already been successfully used. " Empreinte " can be used for design purposes (risk assessments) or for integrity assessments.
Qualification of New Polyamide for Flexible Flowlines and Risers at Elevated Pressure and Temperature
Authors: Chollet Camille , Do Anh Tuan
Published: May 2013

The thermoplastic layer which provides containment for the conveyed fluid in a flexible pipe is designed according to two main parameters: internal pressure and temperature. Up to now, for moderate and high pressure (typically above 5000 psi), only two main grades of polymer are used: PVDF and Polyamide 11. This last one has a maximal using-temperature limited by its resistance to hydrolysis when in contact with water: for example, this ageing issue decreases the maximum accepted operating temperature down to 60°C in the presence of acidic water for 20 year usage. Thus, until now, for this kind of application and a required temperature higher than 60°C, only PVDF could be chosen as pressure sheath.

In order to propose a material, more cost-competitive than PVDF in this temperature range, Technip has qualified a new thermoplastic polyamide for pressure sheath application. Beyond its excellent ductility at low temperature, its blistering behavior up to 15000 psi and its good chemical resistance peculiar to polyamides, it presents a great improvement in terms of hydrolysis resistance; this has been made possible thanks to a special chemistry enabling its use up to 90°C in presence of water. This temperature limit has been established thanks to an extensive experimental ageing study.

The qualification work of this innovative polyamide has covered several large scale industrial extrusion trials as well as a full set of laboratory tests (including those required by API 17J) and different tests on prototype flexible pipes. The paper will present the technical advantages of this new high-performance polymer and the work performed to qualify it for both static and dynamic pressure sheath applications.
A Historical Review on Integrity Issues of Permanent Mooring Systems
Authors: Ma Kai-tung , Shu Hongbo , Smedley Philip , L'Hostis Didier , Duggal Arun
Published: May 2013

With several incidents occurring between 2001 and 2011, the relatively high failure rate of permanent mooring systems is raising a concern in the offshore industry. As a response to this, the paper summarizes various incidents and reviews their failure mechanisms and associated integrity issues. In summary, at least eight (8) incidents involved multiple line breaks; some of them leading to vessel drift. Many more with a single-line breakage were accompanied by similar damage in other lines. Many line failures occurred in their early lives, showing a trend of " infant mortality." Chain, connector and wire rope appear to be the top three components that caused most incidents. Several incidents came as a surprise to industry experts. One particularly surprising finding is the novel nature of the failure mechanisms of some incidents, such as out-of-plane bending, chain hockling/twisting, flawed flash welds, low metal toughness, pitting corrosion, etc. Unknown or new failure mechanisms are troubling because, since they are unanticipated, they cannot be easily detected and prevented with existing integrity practices. This paper critically examines the practices, discusses their limitations and identifies possible improvements, while also highlighting future challenges. To raise the bar for the future reliability of mooring systems, some planned improvements on design codes, taking API Standards as a model, are proposed. A key advocate from the authors is to build a healthier industry by more formally sharing lessons learned, so similar failures can be prevented and mooring integrity can be improved.

Introduction

In the past decade, mooring incidents have been occurring at a high rate. More than twenty (20) incidents have happened to production vessels that are moored on-site for prolonged duration (typically 15–25 years). Among those, at least eight (8) had multiple line damages, or system failure. Some of them led to vessel drifting. Furthermore, the incidents with single-line breakage often have additional lines that sustained damage and could have also failed prematurely if their degradation went undetected. Some of the incidents were of high consequence, causing the vessel to drift a short distance, riser ruptures, production shutdown and small amount of hydrocarbon release. Some were of substantial consequence, requiring effort to repair or replace damaged lines. These incidents are raising concerns for owners and operators. It is important for the industry to better manage mooring integrity and reduce the number of incidents.
Biofouling in Marine and Offshore
Authors: Wei Chao
Published: May 2013

This presentation will provide an introduction into internationally and nationally regulated biofouling issues. The risk for spread of invasive aquatic species (IAS) via fouling from ship's hulls / other under water structures or ballast water is being focused upon more and more. IMO issued guidelines in MEPC.207(62) for the control and management of ships' biofouling to minimize the transfer of invasive aquatic species (IAS). The U.S. Coast Guard requires a Biofouling Management Plan be incorporated into, or referenced in, the Ballast Water Management Plan. California is planning to regulate biofouling on ships. Adding to this IAS issue the resistance attributed to biofouling and hull roughness are other important aspects to consider for improving the energy efficiency of a ship's operation and reducing CO2 emissions, which has been reflected in the IMO Marine Environment Protection Committee (MEPC.213(63)) recommendation for a ship energy efficiency management plan (SEEMP).

Considering the above recommendations and requirements, ABS is developing Biofouling Guidance Notes and a Biofouling Management Plan Advisory to assist the shipping industry in dealing with these issues and in complying with the related requirements. ABS Nautical Systems also provides solutions that assist owners and operators in capturing data for demonstrating SEEMP compliance.

Introduction

The issue of hull biofouling has been of concern since floating vessels were first put into the water. In the 1900's many scientists studied the effect of biofouling on ships. Kempf reported in 1937 with an 85% increase in resistance of the ship. In the past few decades of research from R. Townsin, Goeff Swain, M. P. Schultz, and many others on the biofouling effect on ships, have provided enlightening data concerning roughness and bio-fouling contribution to total hull resistance.

Studies by Townsin et al have provided the industry with a scientific understanding of the relationship between hull roughness and resistance. When this relationship is applied in a simplified manner to various types of ships it provides us with good " approximate" values. Because increased resistance is so significant in accounting for the margin of error for each specific ship, such an approximation provides good guidance for how the hull resistance may be better managed.

Many studies have found that a significant portion of coastal invasive aquatic species (IAS) have been introduced via ship hull fouling in addition to those introduced via vessels' ballast water discharges. Consequently the International Maritime Organization (IMO) has developed voluntary guidelines, IMO MEPC.207(62), to minimize the risk of further spread of IAS. In line with the IMO guidelines, some US states have also started the process of making similar guidelines mandatory through laws. The State of California is one such example.
Rigless Intervention: Barriers and Misperceptions About Using Lightweight Intervention Solutions To Increase Oil Recovery from Deepwater, Subsea Wells
Authors: Morrison Bevan , Karlsen Ole Eddie
Published: May 2013

In recent years, the number of subsea wells has increased steadily; a 2011 report estimated more than 5,500 worldwide. One of the key challenges the industry faces with subsea wells is generally lower recovery factors compared to wells with surface access. A key reason for this difference is because workover activities to improve recovery rates in subsea wells has traditionally required use of large rigs, risers, jointed pipe or coiled tubing (CT), with high operating rates. The high costs of these operations can make it difficult to achieve the necessary increases in production rates and revenue to justify the workover investment, even with increasing oil prices; therefore, operators often forgo production-improvement workovers. However, a growing global population and soaring energy demand means that operators are facing increasing pressure to maximize production and value from mature assets.

These challenges have spurred development of alternative, lighter weight, more cost-effective intervention methods to enhance recovery rates in deepwater, subsurface wells. These alternative technologies include electric-line tools that can be run from smaller, dynamically positioned light well intervention vessels, instead of large workover ships with risers. These rigless and riserless light well interventions (RLWI) improve scheduling flexibility and reduce costs, thereby reducing barriers to performing subsurface well interventions and enabling subsea operators to realize oil recovery rates of 50% or more.

Today many industry companies have a clear tendency to migrate towards lightweight, more cost-effective alternative solutions. But for some, misperceptions still exist and skepticism remains for using RLWI for deepwater subsea wells. However, over the past decade, RLWI has achieved a solid track record of demonstrated value and is an inherently safer method for subsea well interventions, compared to conventional heavier methods.

This paper describes the opportunities to improve recovery rates in subsea wells using the lighter, more efficient and ultimately more productive RLWI methods. Using these techniques has enabled operators to conduct routine planned access to subsea producing assets, improve surveillance and management of interventions, and, ultimately, increase recovery rates. Several case histories and examples are presented.

Introduction

Challenge: The Need to Increase Production from Existing Assets to Meet Growing Global Demand for Energy. Looking at peak oil production from a number of the major oil producers shows that many of them have reached peak oil production over the last ten years (Table 1) the industry is striving to find new resources to replace diminishing reserves and to meet increasing global demand; these factors are moving exploration and development into deeper water offshore, where currently more new fields are being developed subsea than from platforms (Strategic Offshore Research Ltd. 2012).
Better Well Control Through Safe Drilling Margin Identification, Influx Analysis and Direct Measurement Method for Deepwater
Authors: Veeningen Daan M
Published: May 2013

Currently, well control events are almost exclusively detected by using surface measurements. Especially in deepwater, where the riser comprises a substantial section of the wellbore, early kick detection is paramount for limiting the severity of a wellbore influx and improves the ability to regain well control.

While downhole data is presently available from downhole tools nearby the bit, available data rates are sparse as wireless telemetry bandwidth is limited and wellbore measurements compete with transmission of other subsurface data. High-bandwidth downhole data transmission system, via a wired or networked drillstring system, has the unique capability to acquire real-time pressure measurement at a number of locations along the drillstring.

The paper describes the four processes to improve well control for deepwater operations through the use of downhole data independent from surface measurements. First, networked drillstring provide efficient kick detection and the identification of ballooning zones. Gas inside the riser is also detected and decision support is offered between using the mud-gas separator or diverter. Second, a methodology is proposed using direct measurement of downhole real-time pressure for maintaining constant bottomhole pressure during well kills in deepwater. Third, downhole surge and swab pressures are available through measurement while tripping system. Fourth, well control barriers are verified using downhole information, independently from surface data. All of these workflows allow for higher levels of automation, supporting wellsite personnel and improving the safety of operations. The paper presents examples of field data that illustrate these cases.
Response and Simulation of the Pipe-in-Pipe System in Free Spans
Authors: Giagmouris Theofilos , Tang Andy , Qi Xinhai , Zhong Jianxia
Published: May 2013

The interest in the numerical modeling of a deepwater pipe-in-pipe system (PiP) at a free span location is growing. In a free span, the inner pipe bends substantially due to internal pressure and temperature and possibly contacts the outer pipe. Concerns arise how the interaction between them affects the PiP behavior under thermal expansion and contraction. The study is motivated by the need to understand how a PiP at a free span can be modeled adequately. Different finite element (FE) approaches using Abaqus have been practiced. The pipes were simulated with pipe, elbow, and shell elements. The interaction between the inner and outer pipes was simulated with multi-point constraints (MPC), tube-to-tube contact elements (ITT), and contact surfaces. FE model accuracy and cost effectiveness were compared in a case study. The conclusions in this paper would also be applied for PiP sections with bending, such as for lateral buckling of a PiP laid on the seabed and upheaval buckling of a buried PiP.

Introduction

A PiP insulates the inner pipe using an outer pipe as shown in Figure 1(a). In a free span, Figure 1(b), the pipes bend and the gap between them allow for relative displacement due to different effective tension and weight of the pipes. A shell FE model of a PiP at a span was developed to investigate the behavior during operating and cool down conditions. In addition, pipe FE models were developed and evaluated against the shell element model. It is shown that while the shell FE model simulates the motion of the inner pipe relative to the outer pipe and the contact between them, it requires a lot of computational effort. Contrary, a pipe FE model provides global deformation and pipe stresses close to those of the shell FE model and is cost effective. Table 1 and Table 2 summarize the PiP properties, span under investigation, and loading conditions for each pipe.
Practical Experience Gained Operating a Compact Ultradeepwater Drill Ship
Authors: Deul Hans , van den Broek Leon , Wijning Dieter , MacKinlay Walter Malcolm , Roodenburg Joop
Published: May 2013

This paper describes the practical experiences gained during the first year of operation of a new Panamax-size ultra deepwater drill ship. The vessel started operations in the Gulf of Mexico in July 2012. The practical experience is offset against the vessel's design expectations: improved safety, an increased drilling efficiency and reduced operational costs.

The drill ship is of an integrated design covering vessel, drill tower and equipment handling. The drill ship offers an equal payload compared to other ultra deepwater drill ships but at half the displacement. This paper details the effects of the highly automated onboard material and equipment handling on the vessel's drilling efficiency and on the operational cost

The material and equipment handling is designed around the box girder drill tower that has no V-door limitation and features a drilling side and a construction side, thus minimising flat time. Stands built on one side of the tower can be stored in two set back drums, one on each side of the tower, and taken out when needed. Four pipe handlers are available for handling purposes.

This paper covers the field experience with all features of the drill tower that are designed to save time and/or increase efficiency and/or enhance onboard safety. These include the drill tower's dual drawworks eliminating slip-cut procedures, the passive and active heave compensation on the drawworks, and the splittable blocks. The latter allow increasing the block speed for lighter loads.
Dry Tree Semisubmersibles for Gulf of Mexico
Authors: Rijken Oriol , Leverette Steven J , Bian Xiaoqiang
Published: May 2013

The offshore industry has expressed a desire for combining production activities with drilling activities on semisubmersible platforms with the wellheads on the platform. This combination of activities allows for an earlier start of production while the drilling program is ongoing and/or allows well maintenance to be performed during production. These systems are typically referred to as dry tree semisubmersibles. Drilling semisubmersibles are successfully operational around the world and production semisubmersibles with subsea wells are operational in the Gulf of Mexico, the North Sea, and offshore Brazil. However, a dry tree semisubmersible solution for hurricane environments that is both technically and economically viable is in various stages of maturity. The challenge for these structures in hurricane environments is the magnitude of the stroke of the top tensioned risers (TTR) which is significant, and but is now within proven technology used on deepwater semisubmersible drilling rigs.

This issue can be resolved technically by either reducing the vertical motion of the semisubmersible, by increasing the allowable tensioner stroke, or by a combination of both. An evaluation and discussion is provided on both solution paths with a focus not only on the technical challenges but also on the cost aspects of the proposed solution paths. Cost is affected by the tensioners, construction, integration, transportation, and installation issues. This paper will present one solution to the design challenge of a dry tree semisubmersible in hurricane conditions, and the resulting compromises will be discussed.

The dry tree semisubmersible has promise to be more cost effective than spar or TLP solutions in many development scenarios, and will be an important component in developing ultra-deepwater reservoirs.

Introduction

The offshore industry has approached deep water oil and gas production with a mix of wet tree (subsea) and dry tree systems. Wet tree solutions typically have remote subsea wellheads/trees which are located away from the vessel and which are connected to the vessel by means of steel or flexible catenary riser systems, while the dry tree systems typically are positioned directly over the well locations so that the well is extended to the surface with a top-tensioned riser. The wet tree systems include all variations of floating vessels, including FPSO's, semisubmersibles, TLP's, and simple barges. The currently installed dry tree solutions are limited to TLP's and spars.
Simulation Technology To Assess ROV Operations at an Early Planning Phase
Authors: Laroche Sylvain , Dawes Daniel , Cohan Steve , Moore Brian , Rodsand Espen
Published: May 2013

This paper documents the use of Vortex simulation technology and vSIT methodology used for the design of the subsea production system (SPS) for the Laggan-Tormore gas condensate fields west of Shetland. Subsea operations in these extreme weather conditions are very technically challenging, and simulation tools have been developed for verifying full and safe ROV access and operability throughout SPS development.

Introduction

This paper documents the use of Vortex real-time dynamics simulation as part of the detailed design of the subsea production system (SPS) for the Laggan-Tormore gas condensate fields west of Shetland. The two fields are developed and operated by Total E&P UK Limited along with its joint venture partner DONG E&P (UK) Limited. The SPS, situated at 600 m (1,968 ft) water depth, is designed and procured by FMC Technologies. It includes two 6-slot Template Manifolds, one Satellite Well Protection Structure and 9 Subsea Trees (XT), and is very technically challenging due to extreme weather conditions. To be able to verify full and safe ROV access and operability throughout SPS development, Total commissioned the use of a ROV simulator. This resulted in CM Labs, FMC Technologies Schilling Robotics and FMC Technologies combining to develop a desktop software ROV simulation tool. Examples of simulated operations include umbilical end termination and well jumper installation, XT installation and subsea control module change-out. Thirty-seven operations have been simulated on two working sites of the Laggan-Tormore fields (one Template and one Satellite) in order to verify planned operations from an engineering perspective, including analysis of custom equipment design.

By simulating interventions using state-of-the-art simulation software, we were able to allow ROV operators to interact with the simulated environment (as opposed to preset motion planning). Simulating the dynamic interactions between the ROV, ROV tooling and the subsea equipment enables understanding of operations beyond what is achievable with purely kinematic animation. This has the considerable benefit of giving the project team an early opportunity to assess any issues that may be encountered as part of the offshore installation campaign. This approach allows the ROV operator to evaluate the potential for unforeseen impediments that may cause unnecessary delay, or at worst render the operation unfeasible. Being able to assess the installation operations before the physical interface check is completed during the traditional Site Integration Testing (SIT) also allows the equipment provider time to make any required design changes before manufacturing is completed. In order to support this process, a workflow has been implemented, encompassing procedure descriptions, storyboards, mission recordings, and reporting of discovered issues. This workflow enables iterative refinement of the simulation results and a pipeline of work output.