bluuebunny/crossref_metadata_2025 huggingface dataset:
Dynamics of Tar Mat Formation Due to Asphaltenes Accumulation Under Gas Charge in Reservoirs
Authors: Chen Yi , Wang Kang , Zuo Julian Y. , Mullins Oliver C.
Published: April 2015

Tar mats in reservoirs can cause severe issues in oil production such as preventing aquifer pressure support and water sweep. Therefore, it's important to understand the fluid geodynamics that occur in geologic time that give rise to heavy oil gradients and to tar mats. A common event in reservoirs especially in deepwater is a late gas charge into an oil-filled reservoir. In this case, the gas can quickly migrate to the top of the reservoir through fault planes without mixing (except locally) with the existing reservoir fluid. This newly charge gas can then diffuse down into the oil column thereby significantly altering solution gas and dissolved asphaltene content and their gradients. In particular, an increase in solution gas causes a reduction of asphaltene solubility. This process can result in significant variations in asphaltene concentration throughout the column. Moreover, a density inversion can be created due to the combined effects of methane diffusion and diffusion and expulsion of asphaltenes. This results in convective flow of asphaltene-rich fluids which can yield large asphaltene concentrations and tar mats at the base of the oil column. In addition, rapid gas charge can overwhelm the ability of asphaltenes to migrate thereby leading to upstructure tar deposition. Both scenarios can be associated with Flow Assurance concerns over part or all of the field. In this paper, we discuss case studies that exhibit such potentially problematic fluid columns. Simulated cases are also modeled to provide guidance for understanding the fluid geodynamics. The ability to model density inversion and asphaltenes gravity currents is seen to help significantly in understanding of reservoir fluids dynamics.
Unbonded Flexible Pipe: Composite Reinforcement for Optimized Hybrid Design
Authors: Dodds Neville , Jha Vineet , Latto James , Finch David
Published: April 2015

The introduction of composite materials technology to unbonded flexible pipe systems is enabling solutions for the increasingly severe service conditions and logistical challenges of deepwater hydrocarbon recovery. Conventional unbonded flexible pipe is a composite structure, combining the chemical resistance of polymers with the high stiffness and strength of functionalised layers of metallic reinforcement. The pursuit of reducing pipe weight for deepwater applications is driving the adoption of fibre reinforced composite materials as structural elements. However the design of unbonded flexible pipes also demands a systems engineering approach to balance the pipe properties with the demands of the installation logistics and long-term dynamic environment; across the whole process, the introduction of composite materials can provide both enabling and optimisation tools.

The global dynamics of the flexible pipe structures are conventionally managed by using combinations of ancillary items such as tethering systems, buoyancy and/or weights. A global analysis is carried out on the whole system to ensure stability and manage interactions for all anticipated load conditions. As deeper water systems are considered, the self-weight of metallic reinforced structures becomes critical and considerable buoyancy may be required, adding to the cost and complexity of installation and system analysis. Alternatively a fully composite pipe itself may be buoyant, requiring weight to be added to achieve stability.

The introduction of high specific modulus and strength composite materials enables the designer to optimise both the pipe internal load response and the system dynamics by carefully balancing the materials selection and composite design of the interacting functional layers in a hybrid metallic/composite design; neither too heavy nor too light, but optimised for strength and dynamic response, for simple, minimal ancillary requirement installation schemes.

This paper details both thermoplastic and thermoset composite materials technologies introduced into the unbonded flexible pipe designer's toolbox, discusses qualification processes and prototype testing results, and presents case study data for optimised flexible pipe system designs for deepwater applications.
Benchmarking and Dynamic Simulation of Direct Electrical Heating (DEH) Operations in a Subsea Flowline
Authors: Rawsthorne C.E. , Norge BP , Hall A.R. , Dong H.
Published: April 2015

Direct Electrical Heating (DEH) was implemented on a 12" 13km subsea wet gas tieback flowline to assist in thermal and flow assurance management during start-up and shut-down of production. The performance of the DEH system was critical for hydrate management in the single flowline configuration. However, it was very difficult to model the DEH system for the large scale pipeline due to the constraints of computational speed. It was also difficult to determine the DEH performance due to the absence of temperature gauges within the DEH zone of the flowline. Based on the first available field data, the study was able to find a way to investigate the DEH performance using the pressure increase at the subsea template and riser top. A dynamic simulation model was then developed to match the DEH performance during both the heat-up process and heat-maintain process. This enabled further optimization of the operating procedures for the DEH system based on dynamic simulations run using the tuned and benchmarked thermohydraulic model.

The results showed that the DEH performance calculated from the pressure response was better than predicted during the design phase. The DEH heating process was well matched by the dynamic simulation in terms of pressure and temperature response in the flowline. The study demonstrated a novel way to determine the DEH performance for a subsea pipeline based on basic fluid dynamic theory. It demonstrated the applicability of dynamic thermohydraulic simulation tools to replicate the DEH heating process at the scale of the entire subsea flow line under both steady state and transient operating conditions, which is important to the development of operating guidelines. The optimization of operating procedures with the dynamic simulation results resulted in reduced heat-up times (and thereby reduced production deferment) and minimized the hydrate formation risks during system shutdown and restart. An example was provided for future projects on how to use and optimize DEH operation to assist flow assurance management.
Global Interpretation: Solving the Interpretation and Correlation Challenge
Authors: Bruno de Ribet
Published: April 2015

Even if all visible (continuous and/or fragmented) seismic events could be extracted from a single volume in an automatic, accelerated interpretation workflow, how can interpreters routinely use this information to validate the seismic interpretation and produce a geologically consistent model honoring all the stratigraphic details revealed by the seismic data, to improve the reservoir image ? How can the geologic reservoir model reproduce the complexity of the interpretation, without simplifying the input data? We propose to associate an automatic interpretation of reflectors in a seismic cube to a space/time framework to build a 3D chronostratigraphic geologic model that accurately matches the seismic data and can be used directly in a reservoir modeling workflow or in a seismic-driven reservoir characaterization.
Successful Real Time Instrumentation Of The Conductor And Surface Casing Of An Exploration Subsea Well In The North Sea To Measure The Actual Loads Experienced During Drilling Operations
Authors: Myhre Erling , Eilertsen Lasse Eskil , Russo Massimiliano , Johansen Frank , Hart Chris , Kalhovd Tore Johannes
Published: April 2015

In recent years, proper documentation of adequate wellhead fatigue capacity for a planned drilling operation became progressively more important while simultaneously challenging to achieve with traditional wellhead design and existing fatigue analyses methodologies applied. These challenges have developed as a result of the increase in size of drilling rigs and Blowout Preventers (BOPs), longer drilling campaigns on wells, and operations in harsher environments. In response, the industry started directing its efforts in two main areas:

Design side-with the fatigue enhanced well head designs

Analysis side-increasing the activities toward calibration of the analytical tools.

Aker Solutions which recently developed their Slimline Rigid Lockdown (SRLD) wellhead system and Statoil, at the forefront in well head fatigue studies and instrumentation campaigns, decided to cooperate on a pilot project. Together they sought to achieve their combined goals of assessing the SRLD performances in the field and producing a data set of full scale measurements during drilling operations which could be used to validate and calibrate the theoretical wellhead fatigue calculation methodologies.
Stochastic Incorporation of Uncertainty and Subjectivity in Deepwater Pipeline Route Optimization
Authors: Haneberg William C.
Published: April 2015

Least-cost path pipeline route optimization based upon composite geocost surfaces has proven to be an effective and practical tool in challenging deepwater projects with complicated seafloor geology. Among its strengths are the fact that least-cost path routing offers a reproducible logical framework that is well suited to sensitivity analysis and refinement as new and more detailed data become available. At least three major kinds of uncertainity enter into the calculations—bathymetric uncertainty of seafloor digital elevation models and their derivative products, locational (geologic) uncertainty regarding the sizes and locations of mapped seafloor features and hazards, and cost uncertainty regarding the weighted relative costs assigned to seafloor features and hazards. Because these different kinds of uncertainties can be difficult to quantify and they likely interact in ways that are difficult to foretell, one pragmatic approach is to use resampling-based stochastic conditional simulation of composite geocost surfaces to assess the sensitivity of calculated routes to input data uncertainties. Characteristic dimensions of seafloor features or geohazards can be used to estimate the number of random points necessary to characterize major or first-order features known with confidence; smaller features are then simulated using random distributions with the same statistical properties and spatial correlation structures of the sampled points. The final result is not a single route, but rather a cloud of routes defining a most likely route corridor for further assessment and route refinement.
Life Of Field Seismic In The Deepwater BC-10 Phase 2 Development, Brasil
Authors: Buksh G. , Farmer H.G. , Galarraga M.A. , Lydon M.T. , Mautz W.A. , Norberg D.
Published: April 2015

This paper presents the first full field ocean bottom life of field seismic system (LoFS) deployed by Shell, the deepest deployment of this technology in the world and the first installation tied back to a turret design FPSO. From final investment decision to installation was only 17 months. The system comprises 100 km of ocean bottom cable in 14 lines spaced 400 m cross line and 4 component sensors spaced 100 m inline. The cables are connected via 11 km of backbone cables to the existing umbilical termination assembly which supplies power and communication from the FPSO. The system permits the acquisition of high quality, highly repeatable seismic surveys. The topsides equipment installed on the FPSO can be operated remotely from Houston which removes the requirement for specialist staff to be located on the FPSO during surveys. Several alternative systems were considered prior to the investment decision including both electrical and optical systems.

The base survey was completed November 2013, prior to first water injection and the first monitor survey was obtained during June 2014, only 3 months after first water injection. Shell's Marine Imaging Group provides the complete processing services for LoFS data. This builds on their 4D processing experience developed for Ocean Bottom Node (OBN) surveys. Experience gained during processing of the base line survey contributed to a very rapid delivery of quick look 4D seismic volumes to the operations and development teams only 3 weeks after completion of the monitor survey acquisition.

Despite the short duration between start of injection and the first monitor survey (3 months) significant information was obtained confirming no out of zone injection, water injection along the entire length of all laterals, location of early water production in 2 wells and no water fingering observed from injectors to producers in this high viscosity oil reservoir. These observations supported the decision to operate the field at higher rates with current field production and injection rates above expectation providing early economic benefit from this novel system. The second monitor survey was acquired January 2015 with results available after the submission date of this paper.
Atlanta Field: Developing Heavy and Viscous Oil in a Challenging Environment
Authors: Marsili Marcelo Danemberg , de Góes Monteiro Gabriel G. , Pedroso Carlos Alberto , Neto Salvador J. A. , de Almeida Ferreira Igor , Rocha Paulo Sérgio , Rausis Mauro , Branco Valter
Published: April 2015

Atlanta is a post-salt oil field located in the original Block BS-4 ring fence, 185 km off the city of Rio de Janeiro, in the Santos Basin, Brazil, under water depth of approximately 1550 m. However, Atlanta Field is not just another ultra-deepwater project; for its development, several other challenges shall be overcome, such as the low burial depth, its highly unconsolidated sandstone reservoir, the heavy and viscous crude flow assurance, the need for high power artificial lift pumping system, and the complex crude treatment at topsides, among others.

The field was discovered in 2001, followed by an appraisal program with a vertical well drilled yet in the same year to test the high porosity Eocenic unconsolidated sandstones and sample its heavy and viscous oil (14°API and 228 cP in reservoir conditions). In 2006, a horizontal well proposed to test the field development concept cast a shadow in the reliability of the project after facing several drilling, completion and production problems imposed by the high challenging environment. These included poor directional control leading to phase abandonment and well sidetracking, massive fluid loss, gravel packing failure, ESP operational issues, partially conclusive drill stem test (DST), and a severe damaged wellbore (skin = 40).

After considering technology improvements and revisiting development concepts, an extensive preparation and a complete assessment of past operations were performed. During 2013 and 2014 the consortium led the drilling, completion and testing of the first two horizontal producers planned for the field development. Wells were drilled with good directional control and barely any fluid loss, reproducing with great fidelity the proposed trajectory. They were both completed with sand control screens and gravel packed throughout the 800 m near horizontal (88°) section in the reservoir. A slant section of 80 m was constructed just before reaching the reservoir for electrical submersible pump (ESP) installation. The DSTs were conducted with ESP both near the reservoir and near the seabed to test the performance of different artificial lift concepts. Results confirmed the high reservoir permeability and the great performance of the drilling and completion phases, delivering the first two producers of the field with no formation damage. Productivity indexes for both wells were in the high end of the expected performance.

This paper presents a full review of the Atlanta Field, emphasizing its main challenges and how they were overcome by the successful construction and testing of the first two production wells, recovering the reliability of the project and encouraging the consortium to move on to the next phase. Also, the updated field development plan is described, highlighting the challenges to be faced during the next phase of the project.
Evaluation of the Potential of High-Temperature, Low-Salinity Polymer Flood for the Gao-30 Reservoir in the Huabei Oilfield, China: Experimental and Reservoir Simulation Results
Authors: Zhuoyan Zhu , Quan Xie , Hanbing Xu , Jian Fan , Feng Wang , Juedu Austine , Esther C.M. Vermolen , Lingli Wei , Hon Chung Lau , Shemin Song , Dehai He
Published: April 2015

This paper summarizes the laboratory and simulation studies conducted to evaluate the potential of low-salinity polymer flood for the Gao-30 reservoir in Huabei Oilfield, China which has a high reservoir temperature of 113°C, moderate formation salinity of 9,000 ppm total dissolved solids and in-situ oil viscosity of 25 cP.

Our studies have identified GL-100, a specially designed rigid structure modified polyacrylamide, as a polymer candidate for the Gao-30 reservoir because it exhibits adequate thermal stability and acceptable injectivity. Laboratory results show that for GL-100, low-salinity brine has the dual benefits of improved thermal stability and higher viscosity compared to formation brine. Spontaneous imbibition experiments using Gao-30 core plugs show that secondary mode imbibition by softened formation brine recovers more oil than imbibition by formation brine. In addition, significant incremental oil recovery was observed with injection of low-salinity polymer into a heterogeneous Gao-30 core, compared with formation water flooding.

Corefloods in secondary mode were conducted with low-salinity and formation brines. Results were history matched to obtain the relative permeability and capillary pressure curves. These results and laboratory measured polymer rheology and adsorption were used as input into reservoir simulations to forecast benefits of low-salinity polymer flood in two pilot locations chosen from full field history matching of 20 years of waterflood in the Gao-30 reservoir.

Reservoir simulations were run to compare the incremental oil recovery resulting from injection of various slug sizes of formation-salinity polymer and low-salinity polymer. Our simulations only considered the increase in viscosity due to polymer and the improvement of thermal stability of polymer in low-salinity brine. Low-salinity chemical effects through changes in the relative permeability curves were not included. Results show that injection of 0.3 PV formation-salinity polymer and low-salinity polymer gives incremental oil recovery of 9% and 13%, respectively, compared to formation-salinity waterflood.

Preliminary economic evaluations show that formation-salinity polymer flood based on 0.3 PV of 1800 ppm GL-100 to be economical in Gao-30 reservoir based on economics of on-going polymer projects in China. The additional 4% incremental oil obtained by tuning the brine composition (the low-salinity effect) may be economical, especially if it is achieved through softened brine instead of low-salinity brine.
CFD & Basin Test Benchmarks for Subsea Lift Analaysis
Authors: Matthieu Minguez , Raghid Aljarah , Aubin Malassagne , Adel Jebali , Ange Luppi
Published: April 2015

In this paper, the authors present an alternative methodology to overcome the possible conservatism / limitations in subsea structure lifting analysis. The focus is made on the use of Computational Fluid Dynamic (CFD) to preliminary determine a full scale ‘fit-for-purpose’ hydrodynamic library (slamming, drag & added mass coefficients) of the lifted package which could be finally implemented in a complete lifting analysis.

With rigorous purpose, the CFD modelling is firstly benchmarked with scaled basin tests, detailed in Petrie et al. (2009). The comparisons illustrate the capabilities of the CFD solver for recovering the expected physics. The complementary full scale analysis underlines both (i) possible scale effects with regard to basin scale and (ii) free surface impact on the considered package hydrodynamics. Such observations underline the care with which such preliminary hydrodynamic analysis shall be investigated.

Finally, the results of the full scale hydrodynamic characterization are implemented in recommended simplified lifting analysis, DNV-RP-H103 (2009), to determine the operable window for a typical structure. Comparisons with similar analysis performed with recommended hydrodynamic parameters as detailed in DNV-RP-H103 (2009) highlight the benefits which could be taken using such coupled approach.
A Vertical Mining System Concept Using DTH for Seafloor Mining
Authors: Keisuke Watanabe , Yoshiyasu Watanabe , Fumio Yuasa , Tatsuki Nazuka
Published: April 2015

In the concept of subsea mining field development, a subsea crawler generally has a big drill and scrapes the mineral deposit horizontally. In this "Horizontal Mining System (HMS)", ores vary in size and large chunks should be crushed into transportable particles. So the Subsea Crushing and Feeding Unit (SCFU) must be required for efficient slurry transportation to use the traditional riser system. In this paper, we introduce and discuss our "Vertical Mining System (VMS)" concept, which consists of a Down-The-Hole Drill (DTH) unit mounted on a jack up platform. This vertical mining system can be used for both exploration and production of the subsea mineral deposit.

The DTH unit makes the mineral deposit into powder-like particles while it digs into the hole. We executed drilling experiments on land with a granite rock using a DTH unit. The result showed the drilled particle size were less than 1mm, which indicates that this method allows us to transport the ore slurry directly through the traditional riser/pump system.

Because the ore particle is even and small enough, the Subsea Crushing Unit (SCU) can be eliminated. So we believe the total project cost and period can be reduced compared to the HMS concept. The maximum drill length can be from 30 to 50 m. The mining speed per a DTH is determined by the drill diameter and the drilling speed depending on the rock strength. At present, in our granite experiments, the DTH drilling speed was around 3.0 cm/sec. The desired production amount is achieved by installing plural drilling units.

We deploy the jack up platform instead of a crawler considering several reasons. The priority is we need to keep the xy coordinate of the drilling unit precisely controlled for efficient field layout. The second reason is we should keep the drill stem vertically even though the seabed has a slope or it is uneven. It is a gravity type jack up with 4 legs and has a set of xy horizontally sliding actuators which enables us to position the drill units automatically on the seabed. The horizontal size of the jack up is around 15 m times 15 m. The position of the platform will be changed continuously by suspending it with the support vessel's crane after it digs the 10 meters square seabed area. A subsea ore separator will be settled near the platform to select high-grade ore from low-grade ore on the seabed, which reduces not only the transportation cost/time but also the amount of marine disposal from the surface facility.
Developments in Nanolaminated Materials to Enhance the Performance and Longevity of Metal Components in Offshore Applications
Authors: Lomasney Christina , Collinson Leslie , Burnett Timm
Published: April 2015

Nature provides many examples of the incorporation of laminated structures that have evolved over ages to enable novel classes of material that are stiffer, harder and tougher than the "Rule of Mixtures" for the same materials would otherwise predict. Modumetal has lead efforts to emulate nature's toughening mechanisms by configuring layered metal, ceramic and polymer matrices into laminated structure. This innovation has demonstrated material properties that many times to many orders of magnitude greater performance that of their constituents.

While derived from the same basic raw materials as conventional metals, Modumetal’s nanolaminated alloys can be used virtually anywhere conventional metals and alloys are used today, but they provide significant performance improvements over conventional metals, including: superior strength, corrosion resistance, wear resistance, thermal properties, fatigue performance and more. Similar in concept to the difference in structure of plywood versus homogeneous wood, Modumetal’s products are layered on the nanometer scale, a configuration which affords this significant increase in performance. Modumetal is bringing nanolaminated alloys and protective alloy coatings to the industrial marketplace through patented manufacturing techniques which deliver nanolaminated alloys at a cost that is competitive with conventional, homogeneous metal alloys. It is this combination of ultra-high performance and competitive cost that are the foundation of Modumetal’s value proposition to industrial sector users.

Since the Company’s founding in 2007, Modumetal has partnered with organizations across energy, steel manufacturing, aerospace, automotive, defense and construction sectors to develop specific nanolaminated alloy systems for these industrial markets. The performance and value of Modumetal’s nanolaminated coating products have been validated by industry leaders in the upstream oil and gas sector, which are now conducting full-scale field trials after several years of successful specification testing. This paper focuses on test results from those applications of nanolaminated materials which improve the longevity of assets and support increased efficiency over the extended life. Applications for offshore rig maintenance and downhole production lift systems are described. Due to its low-cost, low-capex manufacturing process, Modumetal can provide improvements at comparable or lower cost to conventional metals.
Frontier Deepwater Developments - The Impact on Riser Systems Design in Water Depths Greater than 3,000m
Authors: Saglar N. , Toleman B. , Thethi R.
Published: April 2015

The offshore industry anticipates the need for production riser systems in ultra-deepwater fields where water depths are between 3,000m to 4,500m. The development of ultra-deepwater fields leads to many challenges on the selection of the riser concept and in some instances such applications may require extending riser technology beyond its current limits. Consequently, there is a need to understand the feasibility of riser systems in such ultra-deepwater applications and the technology gaps that exist.

In ultra-deepwater, long suspended riser lengths will significantly increase the riser weight potentially leading to challenges with offshore installation related to laying vessel capability. High external and internal pressure on the riser will lead to the need for heavy wall pipes. Thick-wall riser pipe will bring about riser design challenges in fabrication of pipes, riser pipe welding, riser hang-off system selection, long-term fatigue design, and fabrication of specialty riser joints. By looking into these challenges, it is very important to select the most appropriate riser concept for the ultra-deepwater fields and understand the current pipe manufacturing limits, enabling technology needed for such systems, and technology gaps considering the critical points mentioned above.

This paper addresses the key riser design issues considering wall thickness sizing, top tension, axial dynamics, selection of pipe material, design of key components, and installation issues. This paper evaluates feasibility of a number of production and export riser configurations for ultra-deepwater applications based on existing technology, identifies current technology limits, and determines technology gaps that exist. Methods of advancing the current capability to meet the requirements of frontier deepwater applications are also proposed in the paper.
Case Studies of Testing at NASA's Neutral Buoyancy Laboratory (NBL) for Oil & Gas Industry Risk Mitigation
Authors: Hogan George , Bloomfield Michael , Smith Mark
Published: April 2015

Objectives/Scope

Space exploration and operations like Offshore Oil and Gas exploration and production operations is expensive, and inherently risky. NASA's operational tests, executed at the NBL facility, are critical to maintaining safe and effective human spaceflight operations. Likewise, the Oil and Gas industry is using NASA's NBL is to reduce exploration and production operations cost and risk.

Methods, Procedures, Process

The NBL, once a dedicated pool facility of the U.S. Space Program, with its unique facility, services and capabilities, including availability of a NBL-resident Millennium Work Class Remote Operated Vehicle (ROV) hosts underwater testing, training, system integration tests, tool/hardware development, factory acceptance test and verification tests, or rehearsals of processes and procedures for commercial industrial projects prior to offshore deployment, or other commercial operations.

Results, Observations, Conclusions

Benefits of utilizing the NBL by the Oil & Gas industry will be demonstrated by reviewing and presenting actual space and commercial testing case studies that have been performed at the NBL at various stages of hardware life cycle phases including: concept, design, development, production and operations.

Novel/Additive Information

This paper will present tests that the Subsea Oil and Gas Indus Industry has executed at the NBL as a means to manage exploration and production operational risks, lower overall operational costs, and improve safety at various phases of product life cycle. Use of the NASA NBL facility is mission critical to maintaining safe and effective human spaceflight operations and is now available to the Oil and Gas industry.
Ship-Based Carbon Dioxide Capture and Storage for Enhanced Oil Recovery
Authors: Ozaki Masahiko , Nakazawa Naoki , Omata Akira , Komatsu Masao , Manabe Hiroki
Published: April 2015

This report presents details of a proposed ship-based carbon dioxide capture and storage (CCS) method. CCS is one of the key technologies essential to achieve greenhouse gas reduction. This technology can also contribute to enhanced oil recovery (EOR) efforts by increasing oil production in mature fields. The liquefied CO2 (LCO2) to be sequestered is injected directly into subseabed geological formations through a flexible riser pipe using injection facilities contained onboard an LCO2 carrier ship. The primary characteristics of this LCO2 subseabed injection system are as follows: the presence of LCO2 injection equipment onboard the LCO2 carrier ship, a direct injection into subseabed geological formations through a flexible riser pipe, and the absence of any stationary sea surface structures at the offshore CO2 injection site. The advantage of ship-based transportation is flexibility in regard to i) multiple CO2 shipping locations and storage sites, ii) multiple injection sites from a large CO2 storage port, and iii) relocation of the injection site resulting from either termination of oil production or the site becoming filled with CO2. That is, ships can easily alter their shipping ports and routes to the offshore injection site(s), depending on requirements.
Multiscale Site Investigation of a Giant Mud-Volcano Offshore Azerbaijan - Impact on Subsea Field Development.
Authors: Contet J. , Unterseh S.
Published: April 2015

A 3D seismic, AUV and geotechnical data integration has been conducted in order to assess the potential impact of a large Mud Volcano (MV) activity and its related mudflows for subsea field development.

The studied area is located within the South Caspian Basin (SCB). The tectonic compression of the SCB led to the development of horizontal stresses within the sedimentary sequence and to the formation of anticlinal folds throughout the basin, pierced by large mud volcanoes affecting up to the seabed.

The potential future material expulsion and associated seabed mudflows may represent a significant threat for any subsea installation (flowlines, wellhead, templates…) of E&P activities. The 3D seismic dataset has therefore been used to identify and describe the MV complex interaction with large regional Mass Transport Complexes (MTC). AUV data were essential to provide high resolution informations regarding the geometry and succession of the different mud flows through time, associated with the MV activity.

A large pseudo-circular topographic high forming the crater of the MV at seabed is located into a wider low circular relief. In more details, within the crater, smaller steep side cones associated to seabed high seismic amplitudes are identified as gryphons (secondary small vents), from where recent seabed mud flows have been expulsed. The surrounding depression around the MV has canalized the recently expulsed mudflows southward thanks to lower relief and the present bathymetry. Five recent seabed mudflows have been clearly discriminated, indicating that the MV has been active during the last 5000 years B. P. As a consequence and since the latest catastrophic event (dated 735 years BP) exceeds the estimated mud expulsion recurrence time (500 years), the mud flow zone is considered as a hazardous area for the time being leading to a "No Go" classification for any drilling activity and subsea installation.

This study demonstrates the added value of HR geophysical (AUV) data and geotechnical ground truthing integration with the regional shallow geological understanding derived from 3D seismic data to assess geohazards in a complex and active shallow geological context.
A Critical Review of Serviceability Limit State Requirements for Monopile Foundations of Offshore Wind Turbines
Authors: Arany László , Bhattacharya Subhamoy , Macdonald John H.G. , Hogan S. John
Published: April 2015

Objective/Scope

Offshore wind turbines (OWTs) are getting taller and heavier, and medium water depths are utilized in recent and future offshore wind farms. The increasing turbine size brings with it the increasing size of monopile foundations according to current design guidelines. The increasing diameter of monopiles increases the costs of the foundation, that is material, manufacturing, transportation and installation costs. In addition, it poses engineering challenges, as well as environmental problems due to the high levels of noise emitted by pile driving. The strictest requirement on the monopile diameter is imposed by Serviceability Limit State requirements, which include allowable maximum deflection, allowable maximum initial- and accumulated rotation at the pile head (mudline). These seem to derive from manufacturer requirements for the safe operation of wind turbines and from visual concerns, and may originate from onshore wind technology. However, no obvious reasons were found by the authors for the strict requirements in offshore wind technology considering the additional costs they add. Therefore, the objective of this paper is to critically review the SLS requirements of OWT monopile foundations and investigate the possible reasons for the strict requirements. In addition, in light of the much higher allowable tilt prescribed for floating OWTs, alternative scenarios are investigated with adjusted SLS requirements on pile head deflection and rotation.

Methods, Procedures, Process

In order to confirm that the SLS requirements typically dominate design with the current guidelines, a simple framework assuming a thin walled pile is given to compare the monopile dimensions required for the Ultimate, Fatigue and Serviceability Limit States. Possible reasons for the strict requirements are investigated, and using the presented simple framework, monopile dimension requirements are recalculated for adjusted less strict SLS requirements.

Results, Observations, and Conclusions

The SLS requirements are confirmed to give the highest dimension requirements for monopiles. Slightly higher allowable tilt and deflections already show reduced dimension requirements for monopiles. The investigation into reasons for strict requirements suggest that a critical review of these requirements for design codes is necessary and would be beneficial in terms of costs and applicability of monopile foundations for large turbines and medium waters.

Novel/Additive Information

The investigation reveals possible opportunities to review design guidelines for offshore wind turbine foundations. Adjusting the design requirements in offshore environments with a cost-benefit approach in mind could save substantial costs in material, manufacturing, transportation and installation of monopiles as well as extend the applicability of this type of foundations.
Effects of BETX on the Abnormal Geopressures
Authors: Ma Qisheng , Aften Carl W. , Shuler Patrick J. , Tang Yongchun
Published: April 2015

Generation/accumulation of hydrocarbon has been considered as one of the most plausible mechanisms related to abnormal geopressures observed in many conventional and unconventional reservoirs. In this presentation, we demonstrate that hydrocarbon compositions and phase behaviors of the petroleum fluid can be closely related to the observed abnormal geopressures (either overpressure or underpressure) phenomena. Vapor-Liquid Equilibriums (VLE) of various binary hydrocarbon mixtures as functions of temperature and pressure are determined using the Peneloux Soave-Redlich-Kwong (SRK) Equation of State (EoS) method. Our results indicate that (1) Existence of aromatic hydrocarbon compounds such as Benzene, Ethylbenzene, Toluene, and Xylene (BETX) could mix with hydrocarbon gases in porous spaces under typical offshore shallow well conditions. (2) Abnormal geopressures could occur when the hydrocarbon mixture undergoes a phase transformation acrossing the bubble or dew linee, i.e., when the vapor-liquid co-existance zone disappears. And (3) whether if a geopressure is overpressure or underpressure is determined from the critical temperature (Tc) of the petroleum fluid and the reservoir temperature T. When T > Tc, the hydrocarbon mixture will be in the supercritical phase with increasing pressure and an overpressure zone can be formed, whereas for T < Tc, all hydrocarbon will go into a condensed liquid phase to form an underpressure zone. Our interpretation can be applied to both underpressure and overpressure theoretical models. Accurate knowledge of pore pressure is fundamental to any safe and economic well construction. Various interpretation/prediction models have been developed to incorporate geopressure into the reservoir and basin modeling. This work intends to demonstrate that the phase behavior of hydrocarbons plays an important role in pore pressures.
Development & Large Scale Validation of a Transient Flow Assurance Model for the Design & Monitoring of Large Particles Transportation in Two Phase (Liquid-Solid) Riser Systems
Authors: Beauchesne Claire , Parenteau Thomas , Septseault Cyril , Béal Pierre-Antoine
Published: April 2015

The flow assurance aspects of all subsea projects have a major contribution to the pipe design, field layout, choice of lifting equipment (subsea-pump or air lift), power requirement and system operability.

The context of Deep-Sea Mining pushes beyond their validation limits the existing flow model of particle transportation due to the transient flow of large particle sizes in a small diameter riser evolving in a wave shape. In order to correctly assess the pressure drop in the deep-sea mining riser using a pump lift (Solid-Liquid two-phase flow), TECHNIP has developed a new transient flow assurance model named FASST – Flow Assurance Simulation for Slurry Transportation. This software enables numerous design calculations and riser live monitoring.

This publication establishes the limitations to date of the existing large particle transportation theories before describing the novelties implemented into FASST: a lagrangian tracking of the particles coupled to classical slurry pressure drop calculations for Liquid-Solid two phase flow.

In order to extend FASST applicability, some of the numerical aspects will be highlighted to demonstrate the capacity of the model to calculate solids transportation in "real-time".

The model was validated against both small scale and large scale tests performed at GIW in Augusta. Theoretical results proved to be in agreement with experimental results allowing a very good confidence in the FASST prediction of transient flow regimes.
Verification of Fatigue Analysis Methods for Bottom Founded Offshore Wind Turbine Support Structures
Authors: Lo Tzu-Wei , Yu Qing , Kim Kunho
Published: April 2015

Fatigue analysis of offshore wind turbines (OWT) support structures could be a costly process, particularly for those having complex geometries and connections such as jacket-type support structures. This paper presents the study on the applicability of the spectral fatigue analysis method to OWT support structures and the use of the scatter diagram lumping method to accelerate the time-domain fatigue analysis.

The spectral fatigue analysis method has long been used in the design of offshore platforms in the offshore oil and gas industry. The applicability of this method to the monopile foundation of OWT was studied in the past with some success. However, few studies have been done for OWTs supported by more complex substructures such as jackets. This paper presents the results of a recent study in which systematic benchmark analyses are carried out to evaluate the applicability of the spectral fatigue analysis to OWT support structures. As part of a broader effort to evaluate alternative methods to improve the efficiency of fatigue analysis for OWT support structures, the paper also presents the verification of using various lumping schemes for the three-dimensional scatter diagram to accelerate fatigue analysis in the time domain.

A monopile and a jacket, each of which carries the NREL 5-MW Reference Wind Turbine, are selected for the benchmark study. The equivalent structural model representing the jacket in the fully-coupled aero-hydro-servo- elastic analysis using the NREL FAST program is derived based on the procedure verified through the IEA OC4 project. Load mapping procedures in both the frequency domain and the time domain are developed to allow the time series of global loads calculated using the NREL FAST program to be passed on to the detailed model of the support structure. The spectral fatigue analysis method is adapted from API RP 2A, while the benchmark results are calculated using the time-domain fatigue analysis method. The application of two different scatter diagram lumping schemes to the monopile and the jacket-supported OWTs is evaluated through the comparison with reference solutions obtained using the full scatter diagram.

Significant discrepancies are observed between the spectral fatigue analysis results and the benchmark results from the time-domain fatigue analysis. The verification of scatter diagram lumping schemes indicates that the recommended method is effective and can be applied to significantly reduce the cost of performing the timedomain fatigue analysis for OWT support structures, in particular those with complex configurations.
Lessons Learned from Offshore Fields Turning to Produce HS
Authors: Bronneberg Jos
Published: April 2015

Offshore production experience has proven that sweet oil reservoirs, in course of the production life, gradually turn sour. The main cause of the souring is the creation of the appropriate conditions for Sulphate Reduction Bacteria (SRB's) in the reservoir through (sea) water flooding operations.

This paper provides background information on the parameters driving the souring the potential mitigation methods and addresses the experience with floating production facilities that were designed for sweet crudes, but over their life time were fed with increasingly sour reservoir fluids. The sour gas content of the reservoir fluids not only affects all the systems through which it passes, but also the working environment for personnel on board. Sour Gas (H2S) has a major impact on the safety of the unit. The fact that the average project life time is becoming longer only exacerbates the importance of this subject.

Relatively simple provisions can be added to the design to allow the production facilities to operate safely during its design life.
Disconnectable Mooring Systems for Arctic Conditions
Authors: Bauduin C. , Boulard R. , Caille F. , Newport A.
Published: April 2015

This paper reviews the issues associated with mooring a ship shaped Floating Production Unit (FPU) in arctic conditions, and presents the development of a novel disconnection and reconnection system for such conditions.

The mooring systems of FPUs operating in arctic conditions must be disconnectable to allow the FPU to leave the station to avoid collision with icebergs, or to avoid overloading the mooring legs due to sea ice acting on the FPU hull. In the case of sea ice, the FPU may be required to disconnect under much higher loads than the non-arctic disconnectable systems in operation today. A recent study for the design of an arctic mooring system identified a number of key developments that are required before such systems could be deployed.

The disconnection system is a safety critical element, and requires high reliability and redundancy to ensure the FPU can always rapidly disconnect from its mooring when required. In addition, the large number of risers that may be installed for these large field developments, combined with the significant suspended weight resulting from the high capacity mooring system, leads to large buoyancy requirement for the buoy which must support the risers and mooring system when disconnected from the vessel. As a consequence the analysis of the reconnection process must account for the coupled behaviour of the large buoy body, the mooring system, and the risers and umbilicals. Such analysis has shown that using conventional disconnectable turret technology, the large buoy size coupled with the requirement to reconnect in heavy sea states, can readily generate snatch loads that would break the pull-in winch wire.

In response to the above, this paper presents two significant advances in disconnectable mooring technology. The first is the development of a new locking system to connect the buoy to the turret, which has been qualified at full scale. The second concerns the design of a new pull-in arrangement that eliminates the risk of snatch loads even in sea states in excess of 3m Hs. The system robustness has been demonstrated through model testing.