bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advancements in Extreme Pressure Rotary Sealing
Authors: Dietle Lannie , Richie Aaron 
Published: April 2016

Polymeric rotary seals used in various oilfield equipment face challenging demands, including rotation for extended periods of time while sealing high differential pressure (?P). Such seals are typically mounted in a housing and compressed radially against a rotatable shaft, and prevent fluid from escaping through the clearance between the shaft and housing.
One of the damage mechanisms that limits seal life is extrusion. High ?P forces seal material to extrude into the shaft-to-housing clearance. Factors such as shaft defection and runout overstress the extruded material, causing pieces to break away. Another damage mechanism is the accelerated adhesive wear that occurs when the PV (pressure times velocity) capacity of the seal material is exceeded for conventional rotary seals, or as hydrodynamic rotary seals transition toward boundary lubrication. In static sealing, extrusion is minimized by reducing shaft-to-housing clearance. In rotary sealing, the clearance has to be large enough to accommodate shaft deflection, runout, etc. Failure to provide adequate clearance results in heavily loaded metal-to-metal contact that damages the shaft, the seal, and the housing.
This paper describes an innovative sealing arrangement that dramatically increases the PV capability of rotary seals, and summarizes key results from an extensive laboratory test program. Test conditions that were varied include shaft diameter, velocity, ?P, temperature, seal material, and lubricant. In the most extreme tests, each seal was exposed to a ?P of 7,500 psi and a velocity of 240 ft/minute for 1,000 hours, and survived in excellent condition. Potential applications for the new technology include rotating control devices (RCDs), washpipe assemblies, cementing heads, and hydraulic swivels.
The new high ?P sealing arrangement is based on three technical advances:
The seal is lined with a plastic having excellent high pressure extrusion resistance.
The seal incorporates an advanced hydrodynamic inlet geometry that is sufficiently aggressive to produce hydrodynamic interfacial lubrication when plastic seal materials are used. Hydrodynamic lubrication with plastic seals significantly increases the PV capability of the seals beyond what is achievable with elastomer seals.
An axially force balanced, radially pressure balanced backup ring having a very small clearance with the shaft is interposed between the rotary seal and the shaft-to-seal housing clearance.

The extrusion resistance of the hydrodynamic plastic seal, combined with the axially and radially balanced backup ring, allows this rotary sealing arrangement to reliably operate at ~5 times the PV value of conventional high pressure polymeric seals for durations in excess of 1,000 hours.
StressCage and Frac Pack: Drilling the Conventionally Undrillable Without Creating the Unfraccable
Authors: Rylance M. , Mahadev K. 
Published: April 2016

Abstract
There is little doubt that the success and reliability of frac-pack completions in the Gulf of Mexico has become the yard-stick by which Gulf of Mexico sand control completions are currently measured. Simultaneously, StressCage has become common practice as a method to overcome challenges drilling through depleted zones, in order to cope with complex mud-window constraints for new developments and infill wells. The success of these drilling and completion approaches and their rapid widespread application has resulted in ever more depletion. This has potentially created a vicious circle in terms of drilling the well to desired depth vs. the ability to install a low-skin frac-pack completion.
While these two techniques in isolation represent uniquely optimal solutions to their individual challenges, there is growing evidence that their application within the same wellbore has the potential to create conflicting ideals. The StressCage application is associated with the plugging of small fractures which have been induced in the wellbore wall, thereby increasing the effective fracture gradient, which allows for the drilling of substantial depletion. However, the presence of a range of widely distributed particle sizes in the mud system, as well as increased general solids loading, may result in deep and invasive plugging of the permeable formations and any smaller fractures within the same open-hole sections. When these plugged formations are then the target for subsequent fracturing operations, there is a significant potential to create near wellbore problems that complicate or bring into question the ability to install a frac-pack completion.
This paper will provide a number of examples of the application of StressCage, where resulting frac operations appear to have been hampered or complicated by the use of the StressCage approach and/or associated mud conditions. These examples will provide some evidence of such interactions but, more importantly, demonstrate the contradiction that these two techniques potentially represent. The paper will also outline a scenario resulting from a sand-control lower completion assembly in place, in a new borehole drilled with StressCage method, that could be resistant to any form of frac breakdown (or simple mechanical intervention), and, thereby, compromise the frac and well completion itself.
In addition to the case histories, the paper will outline various engineering approaches that should be considered, including geo-mechanical analysis of well placement, identification of near wellbore issues prior to and during the fracturing operations, careful management of stress caged solids makeup, mud management and frac-pack design in order to avoid or overcome such challenges. All of this helps ensure that we do not create the paradox of being able to drill through the undrillable but then creating the unfraccable as a result.
Functionalized Nanosilicas as Shale Inhibitors in Water-Based Drilling Fluids
Authors: Boul Peter J. , Reddy B. R. , Hillfiger Matt , O'Connell T. Pete , Thaemlitz Carl 
Published: April 2016

Abstract
Water-based mud formulations inclusive of nanosilicas offer the possibility for improved shale inhibition with reduced environmental impact over conventional shale inhibitors. These additives may be effective in maintaining well stability and in preventing equipment problems, such as bit balling, which may be experienced in the absence of good shale inhibition.
A series of different nanosilicas have been tested as shale inhibitors in water-based muds. Differences in shale inhibition are observed depending on the kind of nanosilica that is used. The Nanosilicas described in this article are tested in fresh water and sea water to determine their applicability in both on-shore and off-shore scenarios. In sea water, nanosilica muds appear to be more powerful inhibitors than silicate/KCl muds. The data presented in this report indicate that a nanosilica mud achieves less shale erosion in sea water than a conventional silicate/KCl mud. This increased performance of nanosilica is accompanied with greater ease in handling the lower pH fluid (which can range from pH 8.5 to 10.0) compared to silicate muds which often exceed pH 12. In addition to being more potent inhibitors and more safe to handle, nanosilicas offer the possibility of lower environmental cost. High concentrations of potassium chloride are not necessarily required when nanosilicas are included in a mud design for shale inhibition.
A New Subsea Large Load Deployment System
Authors: Krasin T. , Lee B. , Newlin P. , Brennan K. , Nicoll R. , Wilson C. , Noseworthy N. , Chitwood J. , Schroeder A. , Gay T. , Cercone D. , Pappas J. M. 
Published: April 2016

Abstract
This study is part of a public-private partnership / industry sponsored project developing a detailed design of a qualified subsea 3,000+ barrel chemical storage and injection system, that requires maturing an innovative subsea facilities deployment and recovery technique for large and heavy loads. This paper describes the innovative Anchor Handling Tug Supply (AHTS) based method that was developed to provide this installation capability which is readily adaptable for accurate, safe, and cost effective subsea placement of a wide range of subsea systems and components.
Design and simulation studies, supplemented with an industry Subject Matter Expert (SME) populated Qualitative Risk Assessment (QRA), have validated the features and functional performance for installing and recovering the chemical and injection facilities, which have a projected mass of around 1,000mT. The initial application is to install the 3,000 useable barrel chemical storage and injection system, after which with minor engineering and procedure updates, will be suitable for the cost effective installation and recovery of other large and heavy subsea facilities.
The business driver to mature this technology is the operational cost savings that is achieved by using two anchor handling vessels of opportunity for operational support. In addition, the same installation spread is capable of recovering the installed facilities should facility repair, maintenance, or refurbishment be required. The recovery procedure is essentially the reverse of the installation operations.
Thus the potential exists for this deployment technology to create an environment for game changing conditions impacting the architecture, installation, and maintenance of major subsea installations as the technology is matured and field utilized. This significant developmental project is being monitored and advised by industry representatives through the active representation of operators, service companies, and OEMs participating in the project's technical advisory committee and through the significant contribution of data and expertise.
Hull, Mooring and Riser Concept Selection for Deepwater Field Development in Offshore Northwest Australia
Authors: Wu Yongyan , Lu Roger , Wang Tao , Vijayaraghavan Vishnu , Eide Rolf 
Published: April 2016

Abstract
Several recent large natural gas discoveries in offshore northwest Australia make the area one of the hottest regions for offshore energy activities. Selection of a field development option in early phase will significantly affect overall project economics, schedule and risk, and is complicated by uncertainties in metocean, topsides, subsea layout, and flow assurance. This paper presents a rational screening process for deepwater gas field development in offshore Northwest Australia.
The screening starts with a fair number of potential alternatives using Field Options Generator. Invalid or obviously inferior combinations were eliminated and this yields a "longlist". The next step of screening involves a method called Analytic Hierarchy Process (AHP) to rigorously filter the longlist options. Based on pairwise comparisons, AHP is a multi-criteria decision-making methodology which improves the qualitative and quantitative aspects of the decision-making process. The results are "shortlisted" options. Finally, an Even Swaps Analysis (ESA), which focuses on improving alternatives instead of eliminating, is applied to reach final concept selection for the definition phase.
The field is located in deep water offshore Australia. The region is known for long-period Southern Ocean swells, strong trade winds, monsoonal flow interactions, and high plasticity calcareous soil. The "Field Options Generator" generates thousands of concepts. All concepts are grouped into "families" based on "Substructure" building blocks: Deep Draft Semi, Conventional Draft Semi, TLP, Spar, Round-Shaped FPU, and Ship-Shaped FPU. Removing the obviously invalid combinations gives a reasonable number of "Long List" options. The AHP method is thereafter applied to give weights of eight criteria, which yields a short-list of five concepts including Semi and Spar-based solutions. As both hull concepts have advantages and disadvantages, instead of passively viewing alternatives as monolithic ideas, Even Swaps Analysis provides an opportunity to focus on how to improve the alternatives in terms of criteria for a rational trade-off, and finally the concept of Semi with lazy wave riser is recommended.
As offshore industry moving toward deep-water with more technical / financial risks and uncertainties involved, rigorous field option selection is necessary. This paper uses a novel process combing AHP with ESA which decreases subjectivity and increases rationality during an early phase concept selection. The paper is of particular interest as a reference for selecting field development options suitable for the offshore northwest Australia area and other challenging locations.
Further Weight and Cost Saving of Fire and Blast Resistant Walls on Offshore Installations, Through the New, 4th Type and a Comprehensive Decision Making Model
Authors: Groeneveld A. B. 
Published: April 2016

Abstract
This paper presents an overview of 50 years of development of fire and blast resistant walls for offshore installations and introduces the fourth generation or "Type" of wall. This thoroughly tested and certified 4th Type was developed as a response to the continuous quest to further optimise the cost and weight of offshore topsides, thus allowing operators and designers to accommodate more equipment and higher field yield.
Inductive research indicates that the selection of a fire and blast resistant wall design amongst the available Types is very often biased and predominantly based on past experience. As such, the traditionally selected option has been a monocoque structural design incorporating load bearing walls instead of framed construction designs with non-load bearing infill walls. This bias can lead to sub-optimal design and execution of offshore installations.
This paper reflects on 4 Types of offshore fire and blast walls. From the 1st Type, derived from the shipbuilding industry up to the 4th Type, initially used on recent offshore wind HVDC transformer platforms and more recently also on the oil and gas platforms as a response to the continuous need to reduce weight and improve on safety. This 4th Type, with a weight of just 25 kg/m2, is certified as capable of withstanding up to 2 hour hydrocarbon fires and has been tested with a considerable free span.
In this paper, all 4 Types of walls are assessed against a limited series of hard and soft performance criteria, according to a decision making model which can be used to select the fittest-for-purpose Type of wall system. This model includes the distinction between internal fire walls, external fire walls and external fire and blast walls.Table 1Offshore fire wall comparison table – core criteriaOffshore fire wall comparison tableCriteria:Wall Type:Type IStressed skinType IICorrugated skinType IIIBuilt-up wallType IVPrefabricated sandwich constructionWeight100%60%45%35%Installation time100%70%60%15%Overall cost100%80%60%40%Installation time for wall penetrations100%100%40%30%
Metal Seal Technologies in Subsea Applications
Authors: Krishna Cindy , Lefrancois Michel 
Published: April 2016

As the environment for the oil and gas industry has become increasingly demanding, so has the need for reliable sealing solutions and related standards.
Traditionally, metal seals and gaskets had been considered of interest because of their high temperature resistance and mechanical properties. However, their obvious downside of limited ductility and elasticity, compared to non-metallic materials, remained difficult to overcome. Soft, compressible elastomers provide good sealing performance, but are porous and cannot reliably withstand temperatures in excess of 482°F (250°C). They also become hard and brittle in cryogenic service. Metal seals have much greater temperature capabilities, high mechanical properties, lack of porosity and long shelf life, but as mentioned, ductility and elasticity have always been the limiting factor. Understanding application requirements and design criteria is critical to selecting the proper sealing solution in challenging applications such as subsea oil & gas production.
Wax Deposition Modeling with Considerations of Non-Newtonian Fluid Characteristics
Authors: Zheng Sheng , Saidoun Mohamed , Mateen Khalid , Palermo Thierry , Ren Yiyu , Fogler H. Scott 
Published: April 2016

AbstractWax deposition poses severe risks to crude oil production systems. In order to remediate wax deposition, pigging operation is performed routinely to scrape wax deposits from the pipe wall. Proper determination of the pigging frequency is crucial to estimating the operating costs associated with the pigging operations as well as the risks of pipeline blockage by wax deposit. In order to predict the wax deposition rate and the deposit thickness to be pigged, existing wax deposition models simulate the hydrodynamics, heat and mass transfer of oil pipe flows based on Newtonian fluid mechanics. However, when temperature of the oil drops below the wax appearance temperature (WAT), wax molecules precipitate to form a suspension of wax crystals in oil, resulting in non-Newtonian fluid characteristics. In order to generate more reliable wax deposition predictions, the methodology to model the hydrodynamics, heat and mass transfer as well as deposit growth considering the non-Newtonian fluid characteristics needs to be developed.In this study, we present an improvement of the existing university-developed wax prediction model1 by incorporating the non-Newtonian fluid characteristics of waxy crude oil described by the suspension of fractal aggregates (SoFA) model. This enhancement is first presented for laminar flow regime. This improved model is then applied to provide insights on 1) the impacts of non-Newtonian characteristics on the heat and mass transfer aspects of wax deposition, 2) the effect of shear on wax deposition and 3) the role of wax inhibitors on wax deposition.
Designing for Turbidity Currents in the Congo Canyon
Authors: Cooper C. , Wood J. , Imran J. , Islam A. , Wright P. , Faria R. , Tati A. , Casey Z. , Casey R. T. 
Published: April 2016

AbstractThis paper describes the measurement and modeling of turbidity currents (TC) in the Congo Canyon and the application of that data to design of a telecommunications cable. There are few direct measurements of TCs largely because the measurement instruments are often damaged. Indeed, this is only the second set of measurements ever recorded in the Congo Canyon, and the only set that shows the propagation of TCs through multiple sites. Four moorings were deployed in 2013 along a 500 km stretch of the Canyon and measured roughly a dozen TCs during a 5-month period. The largest event reached 150 cm/s. Two-D and 3-D numerical models were set up and calibrated using the measurements. The 3-D model shows significant along- and cross-channel variations and these results were used to select optimal crossing locations. The models were then integrated with cable data to permit stress and fatigue analysis at selected cable installation locations, permitting both cable route and cable type to be evaluated.
Analysis of Physico-Chemical Constraints on Surfactant Blends for Offshore Reservoirs
Authors: Garcia-Olvera Griselda , Reilly Teresa M. , Lehmann Teresa E. , Alvarado Vladimir 
Published: April 2016

Chemical enhanced-oil recovery has been applied successfully in reservoirs with mild salinity and temperature conditions. Offshore reservoirs challenge chemical flooding, e.g. low-tension and foam flooding, because of the combined hardness and salinity of seawater along with characteristics of the reservoir connate brine. These physico-chemical conditions impose severe limitations to adequate phase behavior for most commercial surfactants. The purpose of the research described herein is to analyze surfactant phase behavior for scenarios with seawater as the main carrying fluid for surfactant systems.
Thermal stability and solubility were analyzed for a number of surfactants provided by two companies. Tests were conducted using a range of simulated connate brines and seawater compositions. Critical Micelle Concentration (CMC) values were estimated using a Nuclear Magnetic Resonance (NMR) protocol developed in our laboratory, recently published (Garcia-Olvera et al., 2016). NMR data were taken from solvents and co-solvents to analyze individual components in chemical blends. Phase behavior experiments were run to determine which blend composition and brine salinity would enable the desired phase behavior. A medium-gravity oil thoroughly studied in our lab was selected for phase behavior studies. Finally, a coreflood was conducted on a subset of surfactants to evaluate the additional oil recovery for one of the evaluated scenarios.
Some surfactants were disregarded for further analysis, due to their lack of thermal stability (dropout from solution was observed). In some cases, co-solvents were added to increase solubility in surfactant blends with a high divalent ion content, which in some cases was insufficient to stabilize the blends. Phase behavior experiments show that some surfactants did not yield Type III microemulsions, and therefore were disregarded for low-tension flooding applications. NMR data for surfactants and co-surfactants yielded good results even when the NMR spectra for different blend components overlaid significantly. Softening of high-salinity brines indeed improved micro-emulsion volume in the phase behavior tests, as demonstrated in the coreflood. However, this strategy is shown through geochemical analysis to be risky for more reactive lithologies, where dissolution and precipitation events are prompted by reduction in hardness in the injection brine.
Our use of an advanced spectroscopic technique (NMR) provides a more quantitative way of determining constraints associated with solubility limits and poor phase behavior under physico-chemical conditions of harsher environments. Geochemical considerations are important for mitigation strategies in reactive lithologies.