bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Baffling Seen by Disequilibrium of DFA Fluid Gradients and by Wireline Pressure Transients and DSTs
Authors: Pfeiffer Thomas , Achourov Vladislav V. , Kollien Terje , Foyn Sven-Erik , Betancourt Soraya S. , Zuo Julian Y. , Di Primio Rolando , Mullins Oliver C. 
Published: April 2016

Abstract
In this reservoir study, three adjacent structures have been subject to largely the same fluid charge with an original oil charge and a very recent light hydrocarbon charge (all indicated by petreolum systems modeling and organic geochemical analyses). In addition, all wells have an oil-water contact (OWC) and two have a gas-oil contact (GOC), while the GOC in the third well is not far away. Thus, all depth-dependent in-reservoir fluid geodynamic processes are visible within each well; no extrapolation away from the wells is required. Moreover, the ~30 meter oil columns in evidently connected sands are amenable to simple dynamic modeling thereby aiding in understanding. All three structures are found to have very different reservoir realizations, particualry regarding the dispositions of asphaltenes in spite of nominally similar initiation conditions after the secondary charge. That is, different reservoir fluid geodynamic processes took place producing different constraints on production in each of the structures. One well showed a light oil underlain by a tar mat. A second well showed large, disequilibrium gradients of gas-oil ratio (GOR) and asphaltene content without phase separated asphaltenes in core. The third well showed a tar mat on a shale break in the oil column not far form the GOC. There were no asphaltenes in core above the shale break and tar mat. However, below the shale break there was asphaltene throughout the core while retaining permeability, but no tar mat on the OWC. These differences were not ascribed to any paleo-OWC nor are they related to differing biodegradation. In addition, these differences are not consistent with any depressurization expalanation.
To resolve the differences, a variety of data streams were used including downhole fluid analysis coupled with thermodynamic analysis from the Flory-Huggins-Zuo Equation of State (FHZ EoS) and its reliance on the Yen-Mullins model of asphaltenes. In addition, well test results provide key production information and are corroborated by vertical intereference testing on wireline. Petroleum system modeling and organic geochemical analysis of oil and core extract samples have also been very useful. The differences seen in the different wells relate to several important parameters such as the different extent of baffling which impacts both production rates as well as equilibration rates of reservoir fluids. Another key parameter is the extent of density stacking versus a lateral fluid front for the secondary light hydrocarbon charge. Proximity to the charge point enhances the lateral nature of the charge yielding rapid asphaltene instability precluding tar mat formation in sections of the well. This information is very useful when projecting reservoir properties away form wellbore.
Development and Qualification of an Innovative and Cost Efficient Heat Traced Flowline Optimized for J-Laying
Authors: Lirola F. , Pionetti F-R. , Agoumi J. , Sundermann A. 
Published: April 2016

As more complex oil reservoirs are discovered, innovative flow assurance solutions are required to make the development of new discoveries both technically and economically feasible. Indeed, depending on the size of the field, a long distance tie-back might be relevant to avoid the economic impact of a dedicated production platform. If the tie-back is too long, the water depth too deep and/or the fluid temperature at the wellhead too low, conventional flow assurance solutions might not be applicable. In addition, the size of the reservoir might not justify the installation of a service line or a second production line to generate a loop to allow preservation by mean of flushing the line with dead oil in order to avoid the formation of wax and or hydrates during shutdown. Active heating of the flowlines efficiently covers this gap. Among the available technologies, Heat Tracing appears as being an interesting technology as it features very high efficiency when compared to other solutions. To this date, this solution was limited to reel lay. This paper will present a design suitable for J-laying installation methods thus enabling the technology for larger diameters and remote locations, removing the need for a spool base.
This new solution is based on a sliding pipe in pipe concept that has been adapted and improved in order to include a heat tracing capability while optimizing laying rates and offering enhanced monitoring capability including both temperature and stress surveillance. As in any other heat traced pipe in pipe concept, the electrical cables are spirally winded around the inner pipe and, covered with insulating material and enclosed in an outer pipe. Optical fibers are added in order to monitor stress and temperature. In the case of this technology, several innovations aiming at improving the concept have been implemented and tested.
The concept mainly relies on a specific connector designed for the simultaneous connection of all electrical wires and fiber optic cables in a single and reliable operation. The concept of sliding pipe in pipe has also been improved, relying on packers and specific pipe end design that simplify the handling of quad joints.
The performed qualification testing includes:
Full scale fabrication;
Testing of the connection system;
Testing of the fiber optics;
Testing of the packers to validate their holding capacity.
All tests have been performed at full scale and included deformation and temperature testing. They allowed to demonstrate that all components can be easily integrated with a conventional Pipe in Pipe design while significantly facilitating offshore operations. The present paper will provide insight on the main features of the technology in addition to details on the performed qualification campaign.
Better Foam Cement with a Liquid Stabilizer: Offshore Case Histories
Authors: Doan Angela Anh , Ejike Mosunmola Omuwunmi , Li Li 
Published: April 2016

Abstract
Foam cementing has been widely used for offshore applications where the formation has low fracture gradients, and shallow water flow may occur. One challenge of foam cementing is to ensure that the foamed slurry is stable at the desired foam qualities with low permeability. Therefore, stabilizers are commonly applied along with the foaming agent. This paper describes the comparison testing and several offshore applications of a new liquid foam stabilizer that improves logistics and flexibility on the rig, and prevents excessive viscosity and foaming during mixing.
The new liquid foam stabilizer was tested in the laboratory to compare its performance with that of a dry stabilizer used previously in the field. The stabilizer was then used in several offshore wells to assess its performance in real-world operations. In particular, one problem with dry foam stabilizers is that they can promote excessive foaming during mixing, which leads to pump cavitation if not controlled with a defoaming agent. The field operations were arranged to test a new operational procedure for use with the liquid foam stabilizer to avoid cavitation without a defoamer.
The laboratory testing determined that the new solids-free liquid foam stabilizer disperses easily in the cement slurry. The new stabilizer was also found to improve the stability of the foam and the density distribution of the set foam cement compared with no stabilizer. Furthermore, several case histories will demonstrate that the combination of the liquid additive and the new operational procedure improved the slurry mixability without any pump cavitation issues.
The new liquid foam stabilizer has more predictable and reliable response than conventional dry stabilizers, and the case histories will demonstrate how its use improves cementing flexibility and logistics.
Safe Hydrate Plug Dissociation in Active Heating Flowlines and Risers - Full Scale Test
Authors: Tzotzi Christina , Parenteau Thomas , Kaye David , Turner Douglas J. , Bass Ronald , Morgan Julie E. P. , Zakarian Erich , Rolland Julien , Decrin Marie-Kathleen 
Published: April 2016

Electrically Traced Heated Pipe in Pipe (ETH-PiP) technology has been developed to overcome some of the challenges associated with deeper and more remote offshore oil and gas production. This active heating technology applies power to achieve a production fluid temperature above the wax or hydrate appearance temperature either continuously, during normal production, or intermittently, during shutdown periods. Concerning hydrate management, the contractor Company in collaboration with Major Operators conducting experimental and modelling studies to investigate hydrate dissociation in heated flowlines through a Joint Industry Project (JIP) kicked-off in 2012. The main objective of these investigations is to demonstrate that a long, non-permeable hydrate plug can be dissociated in a safe and controlled manner with the ETH-PiP technology.
Large hydrate plugs (approximately 200 kg each) are formed in an 18m ETH-PiP 6? OD prototype, using a water and gas system equipped with DTS fiber optics systems for temperature monitoring, pressure and temperature sensors, and high accuracy gas flow meters. Different heating strategies are tested to investigate the best active heating procedure for safe hydrate plug dissociation, using temperature, pressure and released gas flow rate monitoring along the entire length of the prototype. Hydrate plug dissociations are performed in open or closed volumes for various conditions during the 2nd phase of the experimental campaign, which started at the end of 2013. High pressure differentials are applied across the hydrate plugs; non-uniform longitudinal heating profiles are applied to reproduce operating conditions similar to direct electrical heating; and three-phase dissociation experiments are conducted to simulate the influence of oil present in the hydrate pores on the plug dissociation.
The paper gives an overview of the experimental set-up and measuring techniques used. It describes the hydrate plug formation, location, and characterization, as well as the successful dissociation of hydrate plugs. Preliminary simulation results based on a specifically developed "in-house" simulator are presented, as well as extrapolation of the results to real subsea conditions. This test program demonstrated that large non-permeable hydrate blockages in single line field architectures could be dissociated without local pressure build-up or plug run-away using ETH-PiP technology.
FPSO Conversions – Fast Track & Cost Effective? Some Lessons Learnt
Authors: Roosmalen Kees van , Strien Hubert van , Kautz Rigardo 
Published: April 2016

Abstract
In recent years the authors company was involved in engineering for FPSO conversions, both tanker to FPSO and for FPSO redeployment, as well as similar engineering works for the life extension programme of naval surface vessels and submarines. The objective of the paper is to share the primary lessons learned in such projects.
The paper describes the generic difficulties encountered in such "brownfield" projects, with an emphasis on technical and engineering aspects of FPSO projects, and some advice for future projects. Examples are given from the authors experience in practical situations on the issues mentioned above and how these might or might not have been avoided.
The paper concludes with a review of some lessons learnt and an overview of practical constraints on the extent to which the ideal approach might be achieved in reality.
Wave Energy Converter Arrays for Power Absorption from Ocean Waves with Time Domain Predictions
Authors: Kara Fuat 
Published: April 2016

AbstractA three-dimensional in-house transient computational code ITU-WAVE based on panel method, potential theory and Neumann-Kelvin linearization is extended to take into account wave interaction in an array system using two and four truncated vertical cylinder arrays. ITU-WAVE transient fluid-structure interaction panel code is validated against analytical array results before applied to power absorption from ocean waves for different array configurations. The effects of the separation distances between array system and heading angles on energy absorption in both sway and heave modes are studied by the support of numerical simulations which show sway mode has wider bandwidth than heave mode for energy absorption. It is also shown wave interactions are stronger when the array systems are close and these wave interactions are reduced significantly and shifted to larger times when the separation distance is increased. The wave interaction is much stronger at the same separation distance and heading angle in heave mode than in sway mode. Numerical experience also shows that more power is absorbed in sway mode than heave mode in both two and four array systems at any separation distances and heading angles when the bodies in array system have the same displacement in both sway and heave modes.
Major Advancement in Pipeline Integrity Management Through an Integrated Quantitative Risk Assessment Approach
Authors: Azouz A. , Hakim M. Abdel , Soliman Y. , Awda H. 
Published: April 2016

The requirement to establish, implement and maintain an Integrity Management System (IMS) is crucial for safe guarding the pipeline assets of any Operator. Risk assessment represents a key element of such a system and requires evaluating the risk for all potential threats jeopardizing the integrity of the pipeline system. A key challenge which typically faces the Operator is how to combine the risk assessment of different threats in order to quantify the overall risk level for the entire pipeline system.
This paper presents a new approach that was developed for risk assessment and risk ranking of subsea pipeline systems. It describes the methodology used to evaluate the risk for each threat quantitatively and to integrate the individual risk assessments to arrive at an overall risk level for the entire pipeline system.
The new approach is used to carry out an integrated risk assessment for all threats jeopardizing the integrity of a pipeline system. The approach is valid for subsea pipeline systems and the calculations were calibrated based on in-house experience from historical inspection data. However, the approach can also be applied to other assets with due consideration of the nature of the relevant threats and re-calibration of the calculations based on the in-house experience of the Operator.
The standardization of the risk assessment methodology for the different threats allows for seamless integration of the individual risk assessments into an overall risk level for the entire pipeline system. The approach is therefore capable of risk ranking a fleet of subsea pipeline assets based on the calculated overall risk level for each pipeline. It also offsets the inherent uncertainty in the quantitative risk assessment to a large extent since the calculated overall risk level for a pipeline is relative to other lines in the network.
The presented approach represents a novel method for quantitative risk assessment of all threats jeopardizing the integrity of a pipeline system in a standardized way. The risk ranking of the Operator's pipeline network based on this approach provides a consistent and technically sound basis for prioritizing the pipelines inspection and mitigation plans.
Disconnectable Turret Mooring System for Arctic Drilling
Authors: Efraimsson Fredrik , Ahlstrand Martin , Clegg Rosemary 
Published: April 2016

When drilling in shallow waters a pure Dynamic Positioning (DP) station keeping solution may not be sufficient for the small offset requirements, hence to increase the station keeping capacity a mooring system is required. In ice infested waters, with extreme ice conditions, the ability to quickly disconnect the mooring system and leave the location, as well as a short reconnection time, is of great importance for safety and productivity.
To meet the industry need for exploration drilling in shallow water in the Arctic, an attachable turret mooring system for drillships, ATMOS (attachable mooring system), has been developed. Combining the ATMOS with a drillship´s DP system creates a thruster assisted mooring system and significantly increases the station keeping capacity of the drillship.
This paper presents a drillship mooring system that has been designed specifically to meet the challenges of drilling in Arctic regions but also for operation in open water and/or harsh environment in both deep and shallow waters. Stena has spent a number of years developing and refining the ATMOS concept for use with an Arctic 6th Generation drillship. The development process has included engineering, concept approval by Class, and both open water and ice model testing.
Comprehensive Modeling of Scale Deposition Using a Coupled Geochemical and Compositional Wellbore Simulator
Authors: Abouie Ali , Kazemi Nia Korrani Aboulghasem , Shirdel Mahdy , Sepehrnoori Kamy 
Published: April 2016

Abstract
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, we present a detailed procedure through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow regimes to accurately monitor multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated and validated against experimental data to study the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module (i.e. IPhreeqc) is integrated into the wellbore model to handle homogenous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonates and sulfates scales in the wellbore are predicted for several realistic case studies. Significant effects of physiochemical properties (i.e. pressure, temperature, salinity, and pH) on the scale deposition in the wellbore are discussed. In addition, comparing simulation results with experimental data reveals that hydrocarbon dissolution has a significant impact on geochemical calculations compared to the temperature/pressure variation effects. Finally, the results indicate that combined effects of solid particle concentration and transportation in the flow stream affect the solid deposition rate.
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this work, by including 1) the interaction of the hydrocarbon phases on the aqueous-scale geochemistry (by using a compositional wellbore simulator) 2) effects of parameters that vary greatly in the wellbore (i.e. pressure, temperature, and pH) and 3) comprehensive geochemical databases (provided through coupling of the wellbore simulator with IPhreeqc), scale deposition profile in the wellbore is estimated. The results of this study will help evaluate scale deposition risk and planning the work-over for scale prevention in the production and injection wells.
Improvements and Capabilities of the CRD100 Subsea Robotic Drilling Platform
Authors: Hampton P. J. , Soylu S. , Crees T. , Jackson E. 
Published: April 2016

Abstract
This paper is focused primarily on the current capabilities of the CRD100 subsea robotic drilling platform. An overview is given of the available hardware and interface approach. Time analysis of our wireline system over conventional drilling is included. Reasoning for several design decisions are provided. Aspects of the interface and its semi-automated hierarchical control system of Ethernet distributed pressure tolerant electronics (PTE) I/O modules are presented.
The discussion includes explanation of several ‘lessons learned’ that have been encountered over several years of off-shore drilling experience. From these we have determined that the method of human control of the remote subsea robotic drill should be performed by two operators simultaneously. A pilot chooses what they want to control, be it the drill, its arms, the thrusters or the legs and their co-pilot chooses a complementary set of controls. Data from factory acceptance tests are used to demonstrate how well two operators expedite the procedure.
Although we strive to automate as many aspects of the drilling operation as practical, we show that at present two competent operators (assisted by automated processes) drive the system more efficiently than one. The wireline system has greatly reduced the time to acquire core samples compared to conventional drilling techniques. Further, we have developed this system so that core barrels may be exchanged for scientific probes, such as the cone penetration test (CPT), without the need for conventional trip out.
Our system was implemented with the first subsea PTE that operates over Ethernet. Using distributed PTE has reduced the costs of controlling subsea robotic equipment, both in cost of the electronics housings and cabling, while improving data collection. The paper discusses the use of several of these PTE in a hierarchical control system. The applications of our drill to the petroleum industry is primarily in the exploration and ground analysis for off-shore construction. The approach of using robotic sea floor drills is a means to avoid the expense of employing drill ships for geotechnical exploration.
Large Module Installation and Intervention System at Aasgard
Authors: Dahle Mikal , Meignan Loic , Rossi Rafael , Ludvigsen Andreas 
Published: April 2016

With the vision of a "Subsea Factory" the maintenance and repair work on process equipment is moved from topside to subsea. Operators will still have a high regularity requirement for their process plants, meaning that they need to be prepared to perform such complex subsea operations at any time of the year and with a minimum of time spent waiting on weather (WoW).
This paper will explain the solutions chosen for the world’s first subsea compression system at the Åsgard field in the Haltenbanken area in Norway.
To meet the regularity requirements for the plant the process modules had to be replaceable in weather conditions up to significant wave heights (Hs) of 4.5m. With module dimensions exceeding vessel moonpool sizes and weights well exceeding 300t, the traditional method for overboarding and retrieval would be to use a large capacity crane. However, crane lifts of large, heavy and complex structures will normally have a weather limitation in the order Hs 1.0m – 2.5m.
The requirement for reaching Hs 4.5m for these large and heavy modules called for new solutions to overboarding and retrieval of subsea structures from an installation vessel.