bluuebunny/crossref_metadata_2025_split 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

AbstractTar 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

Abstract
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

Abstract
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

AbstractEven 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

Abstract
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

Abstract
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

Abstract
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

AbstractThis 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

Abstract
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

Abstract
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.