bluuebunny/crossref_metadata_2025 huggingface dataset:
Geomagnetic Storms in Marine Magnetometer Data at Low Latitudes
Authors: Carrier B. M. , Heinz M.
Published: April 2017

In 2016, the authors published evidence demonstrating that strong magnetic field perturbations resulting from Earth-directed solar events can adversely affect marine archaeological survey. Based on a 95% confidence level, it was estimated that 89.7 to 100 percent of geomagnetic storms occurring on days of Kp 5 or greater will generate marine magnetometer signatures that may be misinterpreted as archaeological sites. Aggressive processing, analysis, and comparison of single instrument, total field marine magnetometer datasets were unable to isolate and remove the storm sudden onset signature. These findings, however, only demonstrated the phenomena in data collected at mid-latitudes (Carrier et al. 2016).

This paper builds on that work by presenting analysis of additional survey data collected from a low latitude region in the Gulf of Mexico. Although it is understood that geomagnetic storms affect Earth's magnetic field to a greater degree at high latitudes – that is, near the poles – and to a lesser degree at low latitudes – closer to the equator – the prevailing assumption that geomagnetic storms are not a problem in the Gulf of Mexico is unsubstantiated by the empirical evidence. Observatory datasets analyzed in this paper plainly reveal that geomagnetic storms affect Earth's magnetic field at low latitudes and external source artifacts remain in professionally-collected survey data, even after aggressive processing. Recommendations are made for marine magnetic data collection and processing methods that adequately account for geomagnetic storms, allowing for improved precision in analytical interpretation and thus improved identification of archaeological resources.
Wave Forces and Low Frequency Drift Motions in Extreme Seas: Benchmark Studies
Authors: Fonseca N. , Ommani B. , Stansberg C. T. , Bøckmann A. , Birknes-Berg J. , Nestegård A. , Hauteclocque G. de , Baarholm R.
Published: April 2017

The paper identifies the wave drift forces and low frequency damping induced by a wide range of extreme sea conditions on two floating units based on model test data, assesses the limitations of today's numerical procedures and proposes solutions to overcome the limitations. Since wave current interaction effects are of utmost importance, a benchmark study is carried out with several state of the art potential flow codes. CFD studies complement the numerical investigations.

Empirical wave drift force coefficients are identified by a second order signal analysis technique and the results compared with potential flow predictions and with predictions from a semi-empirical formula. The low frequency damping is a result of the identification procedure as well. On a second stage, time domain simulations are systematically performed for all tested conditions and the results compared in terms of wave frequency and low frequency motion responses. The systematic comparison between calculated responses and model test data identifies the numerical methods limitations with regard to increasing seastates and increasing current velocity.

A benchmark study with four wave-current interaction diffraction codes is presented for a Semi-submersible and, given the good agreement of results, it is concluded that the codes may be considered ready for use by the industry. CFD studies are also performed with the aim of demonstrating the present status with regard to this methodology and identify the challenges in terms of numerical modelling.
Development of Low-Corrosivity Scale Inhibitors for Low Alloys Steels
Authors: Bhandari Manojkumar , Littlehales Ian , Linares-Samaniego Sandra , Christmas Renaldo , Mancuso Sebastian
Published: April 2017

Continous injection scale inhibitors are routinely used to control the formation of mineral scales, such as calcium carbonate and barium sulfate, within topside or subsea applications. The development of chemical injection systems to deploy scale inhibitors deep into production wells presents further challenges due to the higher temperature of the injection point. While phosphate esters, phosphonates and polymers constitute the major types of scale inhibitors applied to control scale in oilfield applications, all are known to be corrosive to Low Alloy Steels (LAS). This paper will detail the development of low corrosivity scale inhibitors for downhole systems containing LAS components within the scale inhibitor's flow path.

A number of subsea fields have been developed in recent years with wellhead trees containing LAS components, in particular F22 carbon steel. F22 carbon steel has been found to be very susceptible to corrosion attack by scale inhibitors typically used in the oil field. To quantify the problem and work towards a solution, existing products covering all major generic types of inhibitors were evaluated using static immersion corrosion tests at test temperatures ranging from 180°F to 300°F; these tests revealed corrosion rates in excess of 30 mpy for these inhibitors against F22 carbon steel.

Initial work involved changes to inhibitor formulations by adjustment of pH or changes to neutralization agents. Unfortunately these changes failed to reduce the corrosion rate to acceptable values. Based on the initial screening work new formulations were developed resulting in very low corrosion rates (<1-4 mpy) in the presence of LAS such as F22, AISI8630 and 1018 carbon steel. Data will be shared which shows that the new scale inhibitor formulations have very similar performance compared to a typical, more corrosive subsea applied scale inhibitor.

The new formulations have been qualified for downhole chemical injection through an umbilical and are currently being applied or approved for use at Gulf of Mexico and West Africa fields. Development of these low corrosivity scale inhibitors will allow operators to prevent scale issues in subsea fields without impacting the material integrity of delivery systems containing LAS components.
API 6A and 17D Bolting Stress Analysis and Fatigue Consideration
Authors: Lim J. I. , Bunch P. , Han Y.
Published: April 2017

API 6A and 17D, specifications provide the design basis for surface and subsea production equipment bolting in the oil and gas industry. These documents provide both design stress allowables and material requirements for bolting. API defined bolt preload requirements are 0.5 times the material minimum yield strength and 0.67 times the minimum yield strength for API 6A and 17D, respectively. The maximum allowable stress in the bolt due to pressure, thermal and external loading is defined to be 0.83 times the minimum yield strength based on the nominal stress in the bolt at the minimum root diameter.

Given these design criteria this paper evaluates the peak stresses in the threads for both principal stresses and combined component stresses and correlates them to the nominal stress in the bolt to define a stress concentration factor (SCF) value based on bolt size. Three bolt sizes, 1", 2" and 3" were evaluated where each bolt was modeled as a single bolt assembly simulating a nut to bolt connection, a flange thickness and a threaded API body. Each design was evaluated using B7 bolt, 2H nut and API 75K body material properties. The finite element analysis (FEA) considered both elastic and elastic-plastic material properties for comparison of results. Using the results of the FEA, stress range vs. cycles, S-N, and fatigue characteristics of the bolt assembly were evaluated based on the nominal bolt stress range vs. the root radius stress range in the highest stressed threads. The S-N fatigue life predictions for bolting are evaluated based on mean stress and peak stress ranges in the bolt threads. As an alternate to S-N evaluation, the stress distribution at the root radius of the thread was input into the fracture mechanics analysis as a weight function for calculating crack tip stress intensity. The analysis is based on elastic stress distribution in the threads and an assumed intial defect size based on nondestructive examination (NDE) inspection. Issues of defining material fatigue properties for loading conditions of bolt threads and the environment of saltwater with cathodic protection (CP) are addressed.
Cyclic Ratcheting Resistance of Buried Pipelines
Authors: Thusyanthan N. I , Wang J. , Haigh S. K. , Robert D. J.
Published: April 2017

Upheaval buckling (UHB) is a common issue for high pressure and high temperature (HPHT) pipelines. The out-of-straightness (OOS) of the buried pipelines combined with the high axial compressive forces induced by the extreme operating conditions causes the pipeline to move upwards till the downward soil resistance is sufficient to resist any further movement. As the pipeline mobilise upwards, the gap underneath is soon filled up by soil particles from around the pipe. As a result, when pipelines cool down during temporary suspension in operation, they cannot return to their original position. As pipelines undergo many thermal cycles of start-up and shout-down during the lifetime, a pipeline OOS feature can progressively move upwards and eventually lead to failure even if it was designed safely against UHB in the original profile. This phenomenon of cyclic pipe movements upwards is known as pipeline ratcheting, which is the driving mechanism behind many UHB pipeline failure cases. This paper presents insight into ratcheting and results of small scale experiments that were conducted at the Schofield Centre, University of Cambridge, to model the ratcheting response of pipelines buried in saturated sands. The results obtained have shown that the critical upward mobilization at which ratcheting is initiated is a function of soil critical state friction angle and pipeline diameter. The pipeline downwards force on the soil during shut-down is the other parameter affecting the initiation of ratcheting. This paper presents valuable insight on ratcheting and mitigating upheaval buckling of pipelines to the design engineers.
Asphaltene Onset Pressure Uncertainty and Other Asphaltene Issues in Field Development Planning
Authors: Dumont Hadrien , Garcia German , Mullins Oliver C. , Nighswander John , Mishra Vinay K. , El-Khoury Jules , Chen Li , Lake Patrick
Published: April 2017

Deepwater fields, such as those encountered in the Gulf of Mexico (GoM), often exhibit reservoir tar deposits and asphaltene instability (Dumont et al, 2012, Mullins et al, 2016). This instability may manifest itself within the reservoir in the form of out of equilibrium asphaltene gradients and tar deposits. These tar deposits can present drilling hazards which are a major nuisance for drilling operations, and can force operators to drill multiple sidetracks or bypass wells. This of course leads to increase well spend and rig time usage. For instance, the last two years showed that approximately 5% of the wells drilled in the GoM encountered severe drilling issues related to asphaltenes/tar deposits. Even more critical and concerning, is that asphaltene instability can have major implications for field developments, stretching expenditure risks beyond a single well to that of an entire field.

From a flow assurance point of view, comingling incompatible oil produced from different zones or reservoirs can precipitate, and worse, deposit asphaltenes in the production path even when the unmixed oils are individually stable. Thus for reservoir management and field development plan, tar deposits can seal off aquifer support and have a detrimental impact on the productivity index of the field. During field development planning, it is essential to know the Asphaltene Onset Pressure (AOP) of the produced oils at reservoir conditions and its change with pressure and temperature along the wellpath. In addition, for unstable oils, AOP gradients variations across the field should be evaluated as AOP can vary largely as a result of Reservoir Fluid Geodynamics (RFG) processes occurring within the reservoir. For instance, fluid mixing due to a secondary charge into a reservoir after trap filling increases the AOP of the resulting oil. In addition, the non-homogeneity of AOP can then be mislabeled as AOP laboratory uncertainty. As AOP field variability can impact all aspects of the journey of the oil to surface, (well placement, completion, recovery factor, injection for pressure support, surface facility, and subsea equipment) and because no model exist to predict AOP gradients, the measurement and the evaluation of these AOP gradients, coupled with simple chemistry understanding are key inputs to a successful field development plan. This paper discuss AOP gradients within a reservoir, their impact on Field Development Plan (FDP), their origin, and proposes a methodology to characterize them.
Assessing the Variability in Intensity and Width of the Loop Current Eddy High Speed Band from Airborne Ocean Surface Current Measurements
Authors: Schiller R. V. , Zhang M , Smith R. , Medina M. , Williams B.
Published: April 2017

The specific position and variability in width and intensity of the high speed band of currents associated with Loop Current Eddies (LCEs) is of significant interest to offshore operators in the Gulf of Mexico. This is particularly the case when undertaking drilling or offshore development operations and the activities may be located close to or inside the LCE. A study of the Remote Ocean Current Imaging System (ROCIS) data from May 2015 has been undertaken to provide further insight into the variability in intensity and width of the LCE high speed band. We defined the band to be limited by the 0.75 m/s (~1.5 knots) threshold, a typical limit for offshore operations in the Gulf of Mexico. Preliminary results show relevant spatial and temporal variability. The width of the high speed band ranged between ~40–100 km, depending on the state of the LCE, interactions with surrounding eddies and the geopgraphical location of the measurements. Peak speeds ranged from about 1m/s to 1.9 m/s. The shape of the speed profile across the band was also variable. Some cases presented a strong correlation with the Sea Surface Temperature (SST) front of the LCE, where speeds dropped significantly outside of the front. The identification of a few patterns of the high speed band was a promising result within the ongoing effort to derive expected relationships between LCE metrics such as high speed band witdth, intensity, LCE area and strength of the SST front.
Ultra-Deepwater Production System: Model Test Study of Cylindrical FPSO in GoM Hurricane Conditions
Authors: Vidic-Perunovic J. , Lee L. , Glomnes E. B. , Mercier R. S. , Head W. J.
Published: April 2017

To address the challenges of Gulf of Mexico (GoM) Lower Tertiary exploitation, alternative FPSO concepts are studied by the industry. This paper documents Phase 2 of a UDW RPSEA study which had as its main objective the validation of a production concept based on a permanently moored cylindrical FPSO designed by Sevan Marine with steel catenary risers (SCR). The present work focuses on model testing of the cylindrical FPSO hull design, performed at the Offshore Technology Research Center (OTRC) at Texas A&M University in College Station, in May 2016. The experiments were performed at a scale of 1:64. The model was subjected to the Central GoM Hurricane environmental conditions. The process of analysis includes extreme hurricane waves, wind, and currents, combined with ultra deep water, to demonstrate the feasibility of the concept in the GoM. This combination implicates complex hydrodynamic behavior of the hull, mooring and riser system. Thus, the model test provides better understanding of the new concept performance. Model test results, including motions and mooring loads, are compared with numerical predictions for a series of test cases. The importance of viscous effects on motions of the cylindrical unit and of the green water effect is discussed. Finally, to assess the feasibility of the hull and riser system, the numerical results of a hybrid approach, full scale, coupled riser analysis are presented, as based on measured hull motions and environmental conditions. This is finally followed by a discussion of the implications of technical and regulatory aspects of the FPSO concept. Following the project criteria, the present system based on SCR configuration seems feasible; however optimization of hull and mooring system is necessary to improve green water and viscous effects on hull motions in extreme current.

The paper represents one sub-scope of the RPSEA study "Low Cost Flexible Production System for Remote Ultra-Deepwater Gulf of Mexico Field Development.", Project No. 10121-4404-03.
Risk-Based Asset Management: Global Implementation
Authors: Supry J. , Schwartz T.
Published: April 2017

The pressure to operate safely in risk-sensitive industries such as oil and gas is always present, with many offshore drillers still struggling to define and practice effective safety-driven maintenance principles on a routine basis, given the dynamic and inherently dangerous nature of drilling. This has given rise to the concept of establishing line of sight between health, safety and environmental (HSE) assessments in the form of critical asset performance standards (CAPS) to link preventive maintenance to safety while aligning with global and regulatory standards.

Working with leading offshore oil and gas drilling contractors, performance standards are created to reference the systems and controls in place used to mitigate the risk of major accident events (MAEs), monitor asset performance with critical operating parameters (COPs) and ensure compliance with regulatory driven requirements.

Performance standards serve as the "Line of Sight" to link HSE cases and preventive maintenance (PM) procedures for safety and environmental critical equipment (SECE) on offshore oil and gas drilling units. Acceptance criteria and COPs are then referenced in the standards to designate which MAE control measures are in place with the goal to reduce the risk of a MAE to as low as reasonably practicable (ALARP). The maintenance tasks are then optimized to capture the key COPs for real-time operational analysis.

Each performance standard provides the link between a comprehensive HSE case and applicable maintenance plans providing clearly defined acceptance standards allowing measuring, monitoring, trending, and appropriate corrective actions as necessary. Global variation can be effectively resolved and managed using the performance standards.

Leveraging the pertinent information captured within a safety case, performance standards are developed and then implemented within preventive maintenance tasks through a computerized maintenance management system (CMMS). Combined with a formalized best practice review process, the CMMS is utilized to quantitatively analyze the effectiveness of the implementation of the performance standards.

This paper will review actual global implementation efforts with leading drilling contractors for the oil and gas industry to show how the development of performance standards provides the baseline for operational excellence. By making this information accessible, the process can be continuously refined and applied throughout the drilling community to provide a safer and more productive environment.
Determining and Optimizing Design Loads for Mobile Offshore Drilling Units Using Fuel Air Explosion Modeling Scenarios
Authors: Weinberg Michael
Published: April 2017

A study was performed to provide develop guidance regarding design basis blast loads for mobile offshore drilling units (MODU). Release of flammable materials may result in a vapor cloud explosion (VCE) which can apply damaging blast loads to critical areas of the MODU. Computational Fluid Dynamic (CFD) modeling was used to perform a dispersion and explosion analysis. This analytical technique is ideally suited to account for offshore geometries and wind patterns. The analysis showed that the controlling loads for the critical areas were from releases on the main deck. The screening level load developed from this study will assist MODU design by providing a defined load case at the initiation of the design process.
Seabed Scour Considerations for Marine Renewable Energy Facilities
Authors: Stevens Robert F. , Smith Kevin , Soosainathan Lawrence , Fisher James , Mekkawy Mohamed M. , Rahim Amir , O'Connell Daniel P.
Published: April 2017

The Geotechnics Sub-Committee of the American Society of Civil Engineers (ASCE) Coasts, Oceans, Ports, and Rivers Institute (COPRI) Marine Renewable Energy (MRE) Committee is preparing a guide document for marine renewable energy foundations. That guide would use standard design codes for fixed foundations and mooring anchors in API RP 2GEO and DNV. This paper focuses on seabed scour.

Seabed scour can affect the siting, design, installation and operations of marine renewable energy facilities. The Bureau of Ocean Energy Management (BOEM) specifically requires an assessment of seabed scour in the Construction Operations Plan (COP) that must be submitted and approved by BOEM before construction of renewable energy facilities in the US Outer Continental Shelf (OCS). This paper discusses why scour is an important consideration for marine renewable energy facilities, what factors can contribute to scour, how the severity of sediment mobility depends on the interrelationship between the ocean bottom and the seafloor, and how the installation of marine renewable energy facilities can alter the dynamic equilibrium among the many factors that contribute to the dynamic morphology of the seafloor. Options available for avoiding, protecting against, or mitigating scour are also discussed.
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

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

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

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

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

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

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

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

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.
A Low Motion FPSO Design Hosting SCR and TTR in Harsh Environment
Authors: Mansour Alaa , Wu Chunfa , Peng Cheng , Zuccolo Ricardo , Bagaria Ashish , Bhat Shankar , Yu Jim , Sung Hong Gun
Published: April 2017

In the development of remote offshore oil and gas fields with minimal or no infra-structure, the Floating Production Storage and Offloading (FPSO) unit is the preferred solution. The FPSO has the advantage of providing the required storage in the hull and direct offloading to tankers of opportunity. Steel Catenary Risers (SCRs) are the preferred solution in wet-tree applications due to their simplicity, robustness and low Capital cost (CAPEX) and Operational cost (OPEX) compared to other riser options. Also, Top Tensioned Risers (TTRs) have their well-known advantages in allowing direct vertical access to production wells and hence enhanced recovery. However, due to its relatively high dynamic motion, conventional FPSO is not a feasible host for TTRs or SCRs in most environments.

In this paper, a Low Motion FPSO (LM-FPSO) design with the ability to host SCRs and TTRs is presented and evaluated for applications in deepwater field developments. A case study is prepared to compare the technical and commercial aspects of a field development in 250m water depth using a conventional FPSO to those using a wet-tree LM-FPSO supporting SCRs and a dry-tree LM-FPSO hosting TTRs. The constructability, transportability and installability of the new design along with its performance verification through physical scale model testing are discussed and presented in this paper.