bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Validation of a Hydraulics Simulator for Estimating Subsurface Reverse Cementing Placement Pressures
Authors: Wreden C. , Simpkins D. , Sharma R. , Deshpande K. M. , Patkar V. , Fuller G. A. , Jee B. , Mercado S. 
Published: April 2017

Abstract
This paper covers the development and validation of a hydraulic simulator for subsurface reverse cementing placement in which fluids are placed down drillpipe and diverted into the annulus through a crossover tool above a liner hanger. Returns are taken up the liner inner diameter and are re-diverted through the crossover tool back to surface. Since commercially available cementing simulators are unable to model cement placement through this flow path with a crossover tool, a simulator was developed and validated using downhole pressure data collected during large-scale flow testing and a reverse cementing field trial. Development of this simulator is a major step forward to implementing a subsurface reverse cementing system in deep water. This custom simulator determines the magnitude of equivalent circulating density (ECD) reductions and identifies opportunities in which subsurface reverse cementing is advantageous with regard to pressure.
Traditionally, placement through reverse cementing results in reduced bottomhole ECDs compared to conventional cementing. This pressure reduction is not uniform throughout the annulus, and a placement simulator that takes into account wellbore geometry, a crossover tool, fluid properties, and cementing hydraulics is required to assess viability of reverse cementing for specific deepwater wells. Computational fluid dynamics (CFD) modeling was conducted using specific crossover tool geometry and various fluid properties to develop a lumped-pressure loss model mimicking local pressure drops. This lumped model was incorporated into a hydraulics system-level solver to estimate surface and downhole pressures. The hydraulics solver was initially validated by comparing model output with downhole pressure data collected from large-scale flow testing and a field trial in which a liner was cemented using the crossover tool.
The resulting subsurface reverse cementing simulator is able to simulate incompressible, multi-fluid placement through a crossover tool. Current capabilities of the simulator include incorporation of a crossover tool to divert flow into the annulus directly above the liner hanger in a deepwater well; estimation of surface pressures, bottomhole pressures, and downhole ECDs at any specified depth; and estimation of u-tubing effect from free fall of fluids. During a large-scale closed-system flow test, model output matched pressure gauge readings to within 11%. Comparisons of field trial surface and downhole pressures correlated with model output for cement placement. This paper will present comparisons of simulator pressure output and collected downhole data used for validation, along with simulator output for an example subsurface reverse cementing job for a deepwater liner.
Chemical Mapping in Marine Archaeology: Defining Site Characteristics from Passive Environmental Sensors
Authors: Swanson Eric 
Published: April 2017

Abstract
This is a discussion of using several chemical and passive environmental sensor tests on a range and variety of shipwrecks from different environments to encourage the study of fluctuations in the marine environment surrounding archaeological sites.
Comprehensive evaluation on the effect that various components of shipwrecks have on their surrounding environment can supplement recent efforts to study the environmental conditions surrounding sites. Utilizing Conductivity, Temperature, and Depth Sensors and Water Chemistry Sensors can help to create a site profile to determine what, if any, impact archaeological remains have on their surrounding environment. These profiles can be used to make comparisons across a variety of shipwreck sites in multiple conditions.
Site investigations ranging from deep saltwater to shallow freshwater show that minor fluctuations in the surrounding environment may occur near wreck sites. Biochemical and electrolytic processes occurring due to the introduction of various material components that compose these shipwreck sites produce several anomalous conditions that should be detectable by utilizing technology such as mass spectrometry and other chemical sensors in the surrounding water column. It is expected that evidence of the materials used to construct or stored within these vessels can be detected by utilizing passive and chemical sensors while surveying on or around these sites.
Employment of passive environmental sensors in the aquatic environment will help to better characterize anthropogenic material features on the seafloor, and may even help to determine specific components present on or within these sites in the future. Consideration should be made to include these types of sensors in future surveys to better profile anthropogenic sites for better knowledge of the environmental conditions in areas of investigation.
Mooring System Considerations for Renewable Energy Standards
Authors: Cribbs A. R. , Kärrsten G. R. , Shelton J. T. , Nicoll R. S. , Stewart W. P. 
Published: April 2017

Abstract
Marine renewables have made great strides in recent years. The IEC, ABS, and DNV GL continue to generate standards and recommended practices in an effort to formulate approved processes as the renewable products make their way offshore and into the market. There are many similarities in some of the processes and designs when compared to oil and gas structures, especially when it comes to moorings. However, many design areas are uniquely related to renewables, even within the same field of energy conversion (e.g. multiple types of wave energy converters). As more renewable systems are installed, the standards will continue to transition from philosophical to more prescriptive recommendations.
One area in which the lines are blurred between oil and gas and renewable industries is mooring systems. The interdependency between the mooring and power generation systems plays a crucial role early in the design phase. Modeling marine energy converters and the mooring system can be complex due the variability of moving parts, and without proper attention, it may be easy to underestimate the loads and fatigue cycles to which moorings will be exposed. Moorings for these structures should incorporate existing standards and recommended practices to ensure safety and reliability. Inspection, maintenance, repair, and replacement should also be considered.
As the renewable industry continues to move forward from scaled prototypes to farms of devices, the oil and gas supply chain will contemplate when to become involved from a financial and resource perspective. However, there are still hurdles within the US authorization bodies like BSEE, BOEM, FERC, NOAA, USCG, etc. to overcome. This paper addresses the existing mooring related standards and delineates areas that need further refinement or conservatism as the renewable industry moves forward with the installation of offshore energy converters.
A New Salinity Measurement System for Formation Water Detection - Test Results from the Qualification Process
Authors: Monge Svein Eirik 
Published: April 2017

Abstract
Many offshore oil & gas wells today are being produced over a broader range of process conditions with more liquid and water present. The mix of formation water and injected water in the reservoir alters the salinity of the produced water with a greater chance of saline formation water entering the flow and leading to a potentially negative impact on equipment (hydrates, scale and corrosion), water handling, disposal costs and hydrocarbon production. In worst-case scenarios, it can lead to well shutdowns.
To counteract these challenges, recent testing and operator verification of a new salinity measurement technology has taken place. The new system (which was developed to be an integral part of a subsea wet gas meter) provides reservoir engineers with vital information on whether formation water is entering the flow and offers an important alternative to traditional timeconsuming and costly laboratory analysis.
The design and technology elements of the salinity sensor include its ability to detect extremely small conductivity changes, with recent test results from the Colorado Experiment Engineering Station (CEESI) based on a qualification process prescribed by the operator backing this up.
Testing took place in a high-pressure flow loop using natural gas at CEESI during 2014 and 2016. The testing led to the qualification, and verification of the measurement technology according to the operator’s specifications. Testing found that the new salinity probe can perform effectively at as low as ±0,15 S/m uncertainty for water conductivity; can detect ± 0,004 S/m sensitivity in changes in water conductivity; and the subsea wet gas meter’s sensitivity can detect ± 0,00002 % (0,2 ppm) changes in water volume fraction (WVF).
The new salinity system is important in: Identifying threats to productionImproving chemical injection controlEnabling remedial action, such as scale and corrosion inhibitor injection, to be instigatedMaximizing oil & gas productionMinimizing water coning.
The Relevance of Chemistry in Deepwater Design and Operations
Authors: Joshi Nikhil B. , Li Qiwei , Kapadia Kashyap 
Published: April 2017

Abstract
Appropriate design and operations of deepwater facilities require prior knowledge of expected properties of gas, oil and water to be produced. With the subsurface uncertainty of reservoir connectivity, compositional gradients, aquifer presence and support and the extent of the reservoir to be developed, it is challenging to put bounds to the expected fluid properties. Any estimates of production rates and the fluid property variations in a field to be developed is riddled with uncertainty, as are other aspects of the development. The integrated project team consisting of reservoir, flow assurance, facilities and production disciplines is tasked to convert this uncertainty to a robust set of design basis for execution. For the team to be successful in this endeavor, the team members are expected to be aware of the potential impact of the production chemistry on the project success. This paper is a discussion of principal fluid characteristics that may compete with other uncertainties to define project risks. In this discussion, production chemistry refers to both fluid compositions and the macroscopic flow-related elements. For example, fluid compositions and flowing pressure and temperatures impact hydrate, paraffin and/or asphaltene precipitation and deposition characteristics. And kinematic properties such as viscosity and phase equilibria impact the design of flowlines, separators and ultimately operations. Specific discussions are on condensate and water properties in wet gas field developments and for oil developments, asphaltene and water properties are discussed. Intent of this discussion is to assess the influence of fluid properties on successfully developing and operating wet gas and black oil fields.
Laboratory Testing and Prediction of Asphaltene Deposition in Production Wells
Authors: Leontaritis Kosta J. , Geroulis Efstratios 
Published: April 2017

When during primary oil production the thermodynamic conditions within the well tubing lie inside the asphaltene deposition envelope (ADE) of the produced fluid, the flocculated asphaltene particles could start depositing on the tubing wall at a certain rate. The above causes a restriction in the tubing ID which results in loss of production. Higher choke settings are required to maintain the same production level until the choke is fully open and the production losses cannot be compensated by opening the choke further. Eventually, the well may ″bridge″ and stop flowing completely or continue flowing at an extremely small flow rate in a rather ″burping″ way where the flow starts and stops at different time intervals on its own volition. Understanding when and how to intervene not only diminishes the risk of unsuccessful or, even worst, detrimental operations but also may increase the well’s productivity throughout its life.
This paper presents a methodology of first determining the ADE in the lab, along with the asphaltene particle size distribution as a function of pressure and temperature. Moreover, asphaltene deposition rates for the tubing conditions can be measured using high pressure and temperature coaxial cylinder technology. Utilizing this technique allows to quantify the amount of flocculated asphaltenes that will deposit under the expected conditions. From that data, it is illustrated how a well-equipped simulator can be, initially, tuned to predict the phase behavior measured in the lab along with the deposition rates. Finally, the simulator can then run the production scenarios available into the future, predicting the impact of asphaltene deposition in the tubing and the resulting loss of production and quantify the asphaltene deposit. It is apparent that this information can prove invaluable in the design of the well completion and flowline along with the facilities and help further refine the understanding of the expected production problems. This methodology is especially important in offshore satellite tieback wells expected to undergo asphaltene deposition.
Improving Cost Efficiency in Floating Production Facilities: Semi-Submersible Design Standardization
Authors: Hodapp David , Ma Wei , Wisch David , Lee Ming-Yao 
Published: April 2017

Abstract
The cost of deepwater field developments has risen over the past decade owing to cost escalation, operator self-imposed requirements, long schedule delays, etc. High oil prices during this period made it easy to overlook these underlying inefficiencies. With the current price of oil, however, these inefficiencies result in deepwater developments which have a difficult time competing with other opportunities for the same capital. As an industry, we cannot continue on the current path and expect to be successful going forward.
The vast majority of current deepwater facilities represent ‘one-of-a-kind’ designs. The current engineering workflow effectively starts with a ‘blank-sheet-of-paper’, and after much churn, tends to produce complex designs owing to preferential engineering and sub-optimization. These ‘one-of-a-kind’ designs, while frequently nominally cheaper on paper, often give rise to increased rework, deviation requests, change orders, etc. resulting in project cost and schedule overruns. For the hull, mooring, and riser design of deepwater platforms, a strategy of standardization and repetition is viewed as a promising opportunity for improving cost efficiency going forward.
A successful strategy of standardization needs to encompass standard designs, standard procurement specifications, standard contracting strategies, standard fabrication workflows, standard QA/QC processes, etc. Current industry efforts like JIP33 and the Unified JIP focus on common procurement specifications for equipment, components, and bulk material. These efforts are an important step toward reducing cost and schedule, but are only one aspect of the solution. A first step is to move away from ‘one-of-a-kind’ design practices and replace them with scalable, standard designs which enable follow-on standardization opportunities. Often, regional differences, e.g., variations in facility requirements and metocean conditions, etc. were thought to rule out any sort of facility standardization on both a regional and worldwide basis. Based on the authors' experience, a semi-submersible platform is feasible for a wide range of payloads; the introduction of deep-draft semi-submersibles and lazy wave risers in the last decade allows target riser performance criteria to be met in many regions around the world for wet tree applications. For these reasons, a semi-submersible platform emerges as an ideal candidate for floating facility design standardization.
Cost Savings Associated with Improved VIM Prediction Accuracy
Authors: Antony A. , Parambath A. , Yue B. , Man K. , Thethi R. 
Published: April 2017

Abstract
Fatigue damage to mooring lines and riser system components due to current driven Vortex Induced Motions (VIM) governs the design of deepwater floating platforms, especially in the Gulf of Mexico (GoM). Fatigue estimations based on scaled model testing were traditionally used for VIM predictions of deepwater platforms. The excessive reliance on scaled model testing was partly due to the unavailability of reliable numerical tools for quantifying the fatigue that is induced.
Practical difficulties in VIM estimation using scaled model testing induces assumptions such as ignoring the effects of external damping, Reynolds number scaling, non-linear stiffness, and current profile. It has been observed both experimentally and numerically that the external damping of the mooring and riser system reduces the VIM amplitudes and these studies have been presented in the RPSEA5404 project reports [1].
A comparison study has been undertaken to quantify the savings in mooring and riser system cost of a deepwater platform due to the consideration of effects of external damping on the platform VIM performance. The damping levels due to mooring and riser system have been established from a numerical model, based on the methodology established in the RPSEA5404 project [11]. The VIM amplitude reductions due to external damping established from the RPSEA5404 project have been used in the study. Mooring and riser configurations that satisfy the fatigue life requirements corresponding to different damping levels have been established for the cost comparison purposes.
Recent studies involving comparison of field measured data with design predictions have shown that the VIM estimation and corresponding fatigue calculations based on scaled model testing were highly conservative. Similar conclusions have been made from recent studies involving CFD analysis and model testing.
The use of more realistic VIM amplitude curves demonstrates the design of a cost effective platform, without compromising the safety or reliability of the system. This paper discusses the study results quantifying the cost saving and safety improvements. The results show that the traditional VIM design methodology overpredicts fatigue damage and hence the mooring and riser designs were not cost efficient.
This study demonstrates the cost savings and safety improvements that can be achieved by considering the effects of external damping that have been traditionally ignored in scaled model testing approach. The study results have more significance when cost and safety concerns are important drivers in final investment decisions of deepwater field developments.
Hybrid Compression Facility: Low Cost Unmanned Gas Compression
Authors: Sage Drew , Bieganski Michael , Grant Andrew 
Published: April 2017

Abstract
Offshore pressure boosting operations are conventionally performed with pumps and compressors situated on a large and expensive platform. In addition to increased weights and costs, large offshore platforms place unnecessary risk on personnel due to higher maintenance requirements, leading to increased offshore presence and helicopter operations.
This paper provides an overview of a hybrid topsides and subsea boosting facility that reduces risk, weight and cost.
To deliver a step change in safety and realise significant cost savings, Aker Solutions has leveraged subsea design thinking to develop a hybrid, lightweight, unmanned compression facility. We have used an approach where every system has been technically justified as essential to operation and adopted new design, operating, manning and maintenance philosophies. All equipment selected for this concept has project references and the facility could be executed today without the need for further technology development.
The resulting design is comprised of three components:
▪ Subsea module: Well fluids are separated subsea, with gas being sent to the topsides facility and the liquids being boosted to export pressure via a subsea pump. ▪ Unmanned platform: Wet-gas is compressed topsides using liquid tolerant hermetically sealed electric drive compressors, before being cooled and returned subsea to be mixed with the liquids. ▪ Power, communications and controls: Provided from a nearby host facility or from shore via umbilical.
The flexible and easily scalable topsides are simplified as only compression systems, operated and powered from a host facility, are on the platform. This reduces offshore maintenance and therefore allows unmanned offshore operations where maintenance personnel are only permitted on the platform following shutdown and depressurization.
Early modelling suggests that compared to a conventional compression platform, weight savings of more than 50% and an overall cost saving of up to 50% may be achieved.
As unmanned offshore compression is novel, this paper will provide insight into how such a facility could be engineered, as well as the safety and cost benefits that can be achieved through its implementation.
Cost-Effective HPHT Design Methods Using External and Seawater Depth Pressures
Authors: Pathak Parth D. , Ponnusamy Padmanaban 
Published: April 2017

External pressures due to hydrostatic heads on subsea equipment which fall under API SC 17 can now be accounted for in the equipment design and rating as a depth-adjusted working pressure (DAWP) with design guidelines from the recently published API 17 TR 12. This can be beneficial for overcoming some challenges in designing the HPHT equipment and can also result in economically efficient and lightweight equipment. However, design guidelines of recently published API 17 TR 8 will need to be followed for designing HPHT subsea equipment. Combining the two design guidelines, it is possible to design or adjust the working pressures based on the working depths for the subsea equipment for HPHT applications.This paper suggests how to combine the design and validation guidelines of API 17 TR 8 and API 17 TR 12. It recommends the different load cases to be analyzed based on recommendations of API 17 TR 12 and applicable design methods from API 17 TR 8 to be used for those particular load cases. Validation testing requirements pose a challenge when combining these two guidelines, and this paper makes an effort to clarify them according to the component under consideration. It also addresses the fatigue screening and analysis criteria based on the components under consideration.To demonstrate these design methods and load cases, an example analysis of a 15,000-psi subsea component is presented with results for uprating the internal pressures up to 20,000-psi using external pressures due to different working seawater depths.API 17 TR 12 refers to API 17 TR 8 for a well shut-in pressure greater than 15,000-psi. In the situation in which subsea equipment requires a slightly higher operating pressure (approximately 10 to 15% of the absolute rated working pressure), the equipment can benefit in utilizing DAWP. This paper also recommends the design and validation methods for situations in which the well shut-in pressure is at or below 15,000-psi but the depth-adjusted working pressure is above 15,000-psi. This situation would typically occur during a bullheading or well kill. For this type of equipment, and in general, potential time and investment can be saved by depth adjusting the working pressures to pressures slightly higher than 15,000-psi instead of developing an absolute-rated 20,000-psi system.