bluuebunny/crossref_metadata_2025 huggingface dataset:
A Comparative Study of Pressure Vessel Design Using Two Different Asme Methodologies
Authors: Faraut Germain , Randrianarivony Liva Christian
Published: April 2017

As offshore production moves to higher pressure reservoirs, water injection, gas lift and gas injection swivel designs need to follow the trend. To accommodate these higher pressures, an internal study was launched to reassess the capacity of a 12" toroidal swivel called VHP swivel. A first attempt in this requalification was performed using the ASME Div. 3 Part 5 "elastic stress analysis" method. Even though being widely used in the pressure vessel industry, the stress linearization method rapidly showed its limitations. Indeed, above 830 barg, the deformed swivel geometry was producing highly non-linear stress profiles which invalidated the method's results. On the other hand, the "elastic plastic stress analysis" method gave higher acceptance pressure levels but required advanced modeling skills. The use of sub-models, programed failure criterion verification tools, mesh refinement and converge criteria control were mandatory for complying with the code requirements. Numerical results confirmed that the VHP maximum operation pressure could be extended from 830 barg to 1020 barg, but also gave reliance in using this methodology as it properly predicted the swivel behavior. Indeed the FE predictions were confirmed by calibrating the numerical results against the actual swivel deformations through monitoring of the deformations during live testing. Finally, the completion of the VHP swivel test program, simulating 25 years of a recent offshore North Sea yaw cycle motions, confirmed the robustness of the overall design approach.

This paper presents the analysis performed as part of the requalification of the VHP swivel at a maximum operating pressure of 1020 barg.
Data Mining the Red Sea Atlantis II Deep
Authors: Brueckmann W. , Kraetschell A. , Augustin N.
Published: April 2017

The Red Sea is a textbook case of a modern-day oceanic rift basin forming as a result of continental break-up. A characteristic feature of this setting in the central and northern Red Sea are more than two dozens of isolated bathymetric depressions, "deeps", filled with brines derived from leaching of the early-breakup Miocene salt deposits that lie beneath the entire Red Sea. The Atlantis II Deep is the largest basin of this type in the axial rift zone of the Red Sea. A topographic depression enclosing a volume of an estimated 15 km3 at water depths from 1900 to 2200 m, the Atlantis II Deep contains layered fluids with temperatures of up to 66°C and salinities of up to 27%. Beneath the brines, up to 30 m of fine-grained metalliferous sediments have been accumulating for the past 23 000 years (Anschutz, 1995). Unlike those in modern hydrothermal systems at mid-ocean ridges, where most of the metals are expelled to the open ocean in buoyant hydrothermal plumes, metals in the Atlantis II Deep are trapped and precipitated beneath a 200-m-thick brine layer. These sediments show extremely high concentrations of zinc, copper, silver, and gold (90 Mt of dry salt-free sediment at Zn>2%, Cu>0.5%, Ag>39 g/t., Au>0.5 g/t.). While the mode of metal deposition found in the Atlantis II Deep is not known from anywhere else on the seafloor today, it has yet been widely suggested as an analog for many ancient sediment-hosted ore deposits (Laurila et al. 2015). From 1975 to 1981 the German company PREUSSAG was contracted by the Saudi-Sudanese Commission for the Exploitation of the Red Sea Resources to explore the Atlantis II Deep. The project was aimed at assessing the overall technical viability of recovering and processing metalliferous muds on board of a mining vessel. The program encompassed several sampling cruises, a pre-pilot mining test (PPMT), environmental surveys, a study of pre-mining environmental conditions, as well as an economical evaluation. However, despite a highly successful PPMT, economic interest in the project waned due to declining commodity prices in the early 1980s. A substantial data set was derived from this campaign, including several kilometers of well preserved sediment cores and >20 000 pages of analog information. Utilizing this information, several GIS-based data mining efforts were carried out in recent years, driven by renewed interest in developing this unique resource. Our presentation will discuss results from these efforts and focus on the technical, economic and environmental boundary conditions of ocean mining of metalliferous sediments. Recently acquired geophysical data in the central Red Sea provide an unprecedented level of ground truth to historic data on Atlantis II.
Industry Applications for Additive Manufacturing
Authors: Imrie Andrew
Published: April 2017

Additive manufacturing (AM) is estimated to grow significantly in the next few years, the potential for AM is significant, however, AM is not the plug and play technology that it appears to be, AM works for specific applications, the first question that should always be asked is ‘does it make sense to make the product using AM compared to more traditional methods of manufacture’. The hype around AM has led many traditional manufacturers to assume that the manufacturing controls and material properties for a given material produced by AM processes are similar (if not the same) as those required and resultant from a conventional manufacturing process (such as a forging). There are many individual steps involved in the process of manufacturing a part by AM. In order to have confidence in the integrity of the part each of these individual steps must be carried out correctly and can greatly reduce production cost and time, yet there is no standardized way of proving to manufacturers and regulators that printed products are safe.

LR is working with a number of partners, to consolidate research and development efforts, alongside real-world AM practices, to create new product certification guidelines - paving the way for widespread adoption of the technology.

The purpose of the guidance document is to provide industry with goal-based certification guidelines for the manufacture of metallic parts/components using additive manufacturing (AM).
NorMoor JIP, Mooring Design Code Calibration
Authors: Hørte Torfinn , Okkenhaug Siril , Paulshus Øivind
Published: April 2017

DNV GL is currently running a Joint Industry Project, "NorMoor JIP," with participants from oil companies, engineering companies, rig-owners, manufacturers and marine authorities. It is a global study covering Northern Europe, Gulf of Mexico and Brazil waters. Our motivation for initiating a study on mooring line reliability was that all the global standards (API, ISO, DNV, others) are mostly based on work from late 1990s, when frequency domain analysis was prevalent. The reliability level implied by these regulations is not known, and we also see that the mooring standards are interpreted and applied differently.

Thus, there is a need for a mooring design code with a consistent analysis methodology and with safety factors for time domain analysis that are in line with this methodology and calibrated at an appropriate target reliability level. This is achieved through reliability-based calibration for a range of different units, mooring systems, water depths and geographical locations. The focus in the present paper is the calibration of safety factors and selection of target reliability level. The underlying structural reliability analysis results used for the calibration are reported in an accompanying paper at OTC 2017.

Structural reliability analysis has been applied to calculate the probability of mooring line failure for intact mooring systems (ULS) and damaged mooring systems where one line is removed (ALS). These results are used as input to the calibration process where the optimum safety factor is calculated as a function of target probability of failure. For ALS, empirical failure data are utilized to assess the probability that a line is missing.

Calibration for different design formats are carried out. The current format using a single safety factor is challenged with a format with two safety factors. The calibration is carried out to avoid significant under design and excessive over design.

The target reliability level is determined based on evaluations of the current mooring design practice. Final recommendations on safety factors and accompanying analysis methodology are presented. Due to the nature of the hurricanes, it is shown and discussed that a different design philosophy is needed for the Gulf of Mexico.

The present work provides a unique and comprehensive set of results, where advanced reliability methods are used to calibrate a mooring design code where the mooring line tensions are calculated in the time domain. The results provide a basis for regulators, such as ISO, to update their rules. ULS and ALS are covered here, and a potential phase 3 of the JIP will cover the fatigue limit state.
Stampede Multi-Purpose Dynamic Simulator
Authors: Puecher Leonardo , Clare Paul , Rastogi Ankur
Published: April 2017

The Stampede deepwater field is located in the Gulf of Mexico, Green Canyon block, and consists of approximately 3,500 ft of water. The Stampede project will include 10 in-service wells in a Miocene formation for a reservoir system at 28,000 – 31,000 ft. TVD. This unique reservoir has deep wells, a low gas-to-oil ratio, and a low bubble point, a combination that calls for an in-well gas lift injection design.

The Stampede project team identified dynamic simulation as a validation tool during the early design phase. High-fidelity fully compositional models were developed for Subsea to simulate heat-transfer effects in the well annulus to understand the interaction between production fluid and gas lift injection for various startup cases. After the simulation model was in place and in use, the project team identified the need to continue using the topsides and subsea integrated simulation models to validate additional phases in process design and engineering. We developed a multi-purpose dynamic simulator (MPDS) that proved to be a crucial tool for Standard Operating Procedures (SOPs) validation, Operations training and control system checkout.

The use of this integrated model provided tangible economic benefits because it led to better informed design decisions throughout the project lifecycle, minimizing workarounds. The challenges the project faced were solved by using the simulator, which connected all the systems together: the subsurface equipment and artificial lift method, the risers and production facilities, and the export pipelines pumps. Using the whole platform model, the project team was able to identify and solve potential issues before they became problems.

This paper shows how a simulator with dynamic full-facility components (subsurface, subsea, hull, and topsides) was used by the project team during each project phase (design, FEED, and construction) to benefit various disciplines (Reservoir and Flow Assurance Engineers, Operations, Automation, and Initial Startup teams). The paper refers to case studies and specific challenges faced by the project team to develop conclusions from the lessons learned and insights gained.
Testing of a Novel Autonomous ICD with Low-Viscosity Multiphase Fluids
Authors: Corona Georgina , Yin Weiqi , Fripp Michael , Coffin Maxime , Shahreyar Noman
Published: April 2017

Applying proven technology to control the production of water and gas has become necessary to extend the life of very light-oil reservoirs while optimizing economics. Traditional inflow control devices (ICDs) can help balance the flow of oil, but are not helpful once water and gas breakthrough occurs. Multiphase data and field-evaluation applications show that low-viscosity, fluidic-diode, autonomous ICDs (AICDs) support the production of very light oil while restricting gas and water.

Testing has proven that the low-viscosity, fluidic-diode AICD can differentiate oil from water and gas, even very light oils. Tool performance was characterized by measuring the pressure differential vs. the flow rate of diverse oil viscosities representing very light-oil formations in Canada, Russia, Malaysia, and Brazil. The AICD was flow tested with very light oils, water, and gas, as well as multiphase testing simulating mixtures of oil/water for different water cuts and oil/gas at diverse gas-volume fractions. The characterization of flow performance was embedded into sophisticated reservoir simulators for steady and transient evaluations.

The multiphase condition of the test fluids was achieved by increasing water cuts and gas-volume fractions. The flow performance tests indicated that the highly sensitive fluidic sensor of the low-viscosity AICD enhances the production of very light oil and restricts water and gas as the water cut and gas-volume fraction increase. The restriction process gradually increases as per the water and gas ratio in the mixture and is reversible if water and gas production recede. Comparisons of the low-viscosity, fluidic-diode AICD vs. a traditional ICD show approximately 25% less water production and 40% less gas production with the AICD. The ability of the low-viscosity AICD to produce very light oils while restricting the flow of gas and water extends the life of light-oil reservoirs by increasing the production of hydrocarbons while helping to lower costs.

For optimum reliability, this unique fluidic-sensor technology has no moving parts or control lines, but uses fluid dynamics to distinguish fluids. Multiphase-flow performance testing and field simulation of light-oil reservoirs indicate that the low-viscosity, fluidic-diode AICD favors the production of light oil (0.3 cP–1.5 cP) and restricts the flow of gas and/or water in a multiphase production-flow environment.
Reducing Subsea Technology Development Lead - Times –A Case Study
Authors: Albert J. , Bay L. , Portman L.
Published: April 2017

A new solution for subsea boosting, has been developed from concept to Technology Readiness Level 4 (TRL 4) in approximately two years. This is an accelerated timeframe for a multifaceted subsea technology, compared to other developments which historically have taken up to several years in the subsea space. Many factors contributed positively to the success of this development including: a methodical approach to product development with a system engineering perspective driven by early client engagement, re-use of field proven and standard components, and a large focus on modularization. Significant development work was required including prototype fabrication and verification testing. This paper chronicles the development of a seabed boosting system, from concept to commercialization, emphasizing the challenges involved with respect to technology development, customer acceptance and the team's experiences and lessons learned.
Qualitative Fault Tree Analysis of Blowout Preventer Control System for Real Time Availability Monitoring
Authors: Mutlu Mete , Arnold Zev , Franchek Matthew A. , Meraz Jose
Published: April 2017

This paper deals with the dynamic availability of a subsea blowout preventer (BOP) with respect to regional and industrial requirements. The study aims to reduce the non-productive time on drilling rigs due to complex propagation of failures within the BOP and BOP control system. In this development, fault tree analysis updated with near real time failure database is implemented into operational decision-making process. First, the system is defined with specifications, boundaries and assumptions. Failure modes of each component are stated. The requirements on the BOP control system are determined with respect to API Standard 53. Fault trees are constructed to address each requirement, and cut sets are produced. For dynamic analysis, a database on BOP state and failure component is created using reports from drilling contractor and operator. Upon detection of a failure, the cut sets are updated. With this application, impact of newly discovered failure in combination with the existing set of failures over BOP availability and compliance is determined in a standardized manner allowing consistent and efficient judgment.
Ultra HP/HT Removable Production Packer for Deep Water Applications
Authors: Suarez Agustin Velasco , Young Chris , Urban Larry , Anderson Gary , Bisset Stephen
Published: April 2017

Until the advent of this technology, there was no removable packer available for Ultra High Pressure (HP)/High Temperature (HT) wells. Previously, the industry was required to rely on permanently installed production packers utilizing then-available technology, which was not always a solution that was the most efficient or cost effective for end-users. Specifically, in order to remove such permanently-installed packers, end-users would have to undertake what could be a costly and time-intensive process, including milling time, fishing time and non-productive time in order to retrieve the permanently-installed packer; the end result of which could cause damage to the casing. To respond directly to this challenge and clear industry need, the Ultra HP/HT Removable Production Packer described in this paper was developed: this is the first industry Packer that can be removed after having been exposed to pressures of up to 20,000 psi (1379 bar), 450°F (232°C) temperature and loads that can reach 900,000 lbf while maintaining a gas-tight seal. This removable production packer has successfully passed the API 11D1/ISO 14310 grade V0 test.
Advances in 4D Seismic and Geophysical Monitoring of Deepwater Fields
Authors: Wang Kanglin , Hatchell Paul , Chalenski David , Lopez Jorge
Published: April 2017

Integrated surveillance is critical for producing oil and gas assets to understand reservoir dynamics and to improve field management. A key component of the surveillance is areal monitoring of subsurface changes (such as fluid movement, compaction, undrained fault blocks and bypassed hydrocarbon) using time lapse geophysical surveys such as 4D seismic. It is particularly important for deepwater fields where well control is sparse and development cost is high. In the past decade, various surveillance technologies have been demonstrated and deployed in Shell's deepwater portfolio of fields, which significantly increased the effectiveness of subsurface monitoring. In addition to production optimization and recovery improvement, great effort was also made towards frequent low-cost surveys that allows us to monitor rapid changes in our fields which is important for getting early information and monitoring injection well performance. In this paper, we will review the advances in these technologies with recent examples from Gulf of Mexico (GoM) and deepwater Brazil.
Downhole Real Time Wireless Telemetry System Applications in Deepwater Completions in the Gulf of Mexico
Authors: Aguilar Sergio , Hawthorn Andy
Published: April 2017

The scope of the paper is to introduce the application of a new wireless downhole real time telemetry tool and its applications in three different deepwater completions operations. The main method to explain the technology application is through three case histories. In two of these case histories, the availability of downhole real time data led to actions on the surface that ensure the positive outcome of the operation. In the third one, the continuous monitoring of well conditions increase the safety and efficiency aspect of the operation. Another approach used in the paper to validate the technology is the comparison of the field real time data with the expected behavior predicted by the modeling done before the operation.

In the fracpack case, pipe contraction due to cooling led to the application of unexpected additional weight on surface. The quantification of different contraction ratios versus temperature drop can help understand the relative movement during operations of downhole tools. In the second case, in the multi-zone single trip system (MZST), the downhole weight transmission monitoring was able to quantify weight transmission at different times of the operation, as expected when the inner string of the tool was inside the outer and permanent string of the system, according to the tubing movement analysis buckling was minimum.

In the fluid loss control case, fluid level drop in real time, allowed the determination of fluid loss rate in-situ and secure the well control aspect of the operation immediately after perforating gun (TCP) firing and after an acid frac job. The control of the losses by an optimum overbalance, minimize fluid control losses and reservoir damage. The case histories will show the direct benefits of the technology in well control and productivity, in the completions operations like TCP, fracpack and MZST.
Pipeline Span Assessment Lessons Learned from Numerical Simulations
Authors: Huang Shawn , Sun Jason , Abdalla Basel
Published: April 2017

Offshore pipeline on-bottom roughness analysis is generally performed to understand pipe stress and areas of free spanning. In this paper, the predicted pipeline profiles, by finite element analysis (FEA) modeling, are compared with survey data. Several case studies are presented and parametric effects are assessed.

The FEA modeling procedures are presented in this paper along with several project experiences. The pipeline on-bottom roughness analysis is conducted to determine the pipe stress and the associated fatigue damage due to internal pressure and temperature fluctuation and vortex-induced vibration (VIV) of free span sections due to seabed unevenness. The analysis presented in this paper can aid the design of pipeline free spans and mitigation, if required. The parametric effects of higher and lower bound soil stiffness, friction resistance, pipeline bottom tension, external / internal pressure, and content density are considered.

The predicted pipeline profiles by FEA modeling are compared with surveyed profiles under several loading conditions. A strong correlation between survey data and finite element analysis (FEA) is achieved. This paper shows that the FEA stress prediction is adequate, and the FEA modeling is suitable as an advanced design tool for pipeline on-bottom roughness assessment and free span behavior analysis.

A commonly used mitigation method for VIV fatigue is to install VIV suppression strakes. For overstresses due to pipeline bending effect, the common mitigation methods are to install mechanical supports, use heavy wall pipe and correct the seabed unevenness among others. It is important to reliably predict the pipeline profiles in order to precisely assess the pipeline free span response and to provide guidance to determine a proper free span mitigation strategy. The FEA method can be utilized to realistically simulate the pipeline on-bottom roughness behavior affected by the pipe properties, pipe-soil interaction including penetration and soil friction resistance, the internal and external pressure, product content, temperature profile, and the bottom tension from pipe-lay. An accurately built FEA model can provide a reliable prediction for the pipeline profile, free spanning length and gap under all conditions, which are crucial for the stress and fatigue assessment as well as for the design of free span mitigation.
Topsides Engineering by Modular Simulation Models
Authors: Felorzabihi Neda , Feng Jeffrey , Shariat Hoss , Wilson Michael
Published: April 2017

In recent years as the offshore industry strives for alternate ways to lower price and increase project efficiency, topsides are often designed and built based on modular design due to the compact process layout, lack of personnel accessibility for site fabrication and also similarity in design of process units involved in most of offshore projects. The modularization process requires a robust simulation model that can quickly perform screening exercises at early stages of the project and be able to validate the detail design from module sub-contractors as the project progresses. This article presents the application and benefits of a modularized, off-the-shelf dynamic simulation tool to support the modular design of an offshore platform during the whole lifecycle of the project, from conceptual design (Pre-FEED), to Front End Engineering (FEED), to EPC, to commissioning and start-up and to post-start-up (normal operation).

Modular-off-the-shelf dynamic simulation tools will support the modular design of the offshore project by modeling each individual modular section of the plant using standard off-the-shelf template models that have been built to meet project requirements. The off-the-shelf models can also be replaced with customized models according to modular design of the plant and based on the data available at each phase of the project.

The dynamic simulation tool has supported various projects for life cycle analysis, for verification of design, testing and verification of control strategy, for operation support during start-up, and troubleshooting and debottlenecking of operation of the plant with proven cost savings. This methodology was originally developed for installations in the United States and later was adopted for the design and engineering in other part of the world. In this article, case studies will be presented as well as the benefit achieved in the application of the modular simulation tools for topsides engineering.

Based on the project scope, the modular simulation domain may vary from a single compression module to an entire topside facility for any floater with modular design such as an FPSO, semi or FLNG, associated wells and flowlines as well as linkage to third party software.
Neptune Spar Life Extension Assessments
Authors: Hua David , Paradkar Mayuresh , Garcia Sharon , Young Sam , Hogelin Pat , Webb Tyler , Farmakakis Kim
Published: April 2017

Oil and natural gas producers continuously strive to control costs, and that goal becomes even more important when market conditions are challenging. To maximize the return on their capital investment and continue to extract reserves on legacy fields, many owners and operators are looking for ways to extend the service lives of aging assets.

The Neptune Spar was the first production spar platform in the world, when it was installed in 1996. Currently owned and operated by Noble Energy, the unit continues producing at Viosca Knoll 826 in the Gulf of Mexico. As the platform ages, there is an interest in extending its service life to allow continued operation in the field. As requested by Noble Energy, ABS Group initiated a life extension assessment project.

This paper describes the process of the Neptune Spar life extension assessments and challenges encountered during the process. One of the critical aspects of the life extension process is regulatory approval. Since the life extension for floating production platforms is a relatively new trend in the offshore industry, the regulatory compliance process is still under development, and this project is providing a significant contribution to the development of guidance and criteria.

The purpose of a life extension assessment is to understand the history of the facility and its current physical condition to determine its structural integrity and outline what is needed for the unit to be maintained for safe and responsible extended service. The life extension project began with a roadmap for life extension assessments that included conducting baseline inspections, reviewing historic inspection and repairs records, undergoing gap analyses that compared the spar's current condition with the original design premise and calculations, and performing additional engineering analyses.

As part of the regulatory approval process, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) and the U.S. Coast Guard (USCG) require that a Certified Verification Agent (CVA) verify the entire process of life extension and submit reports that document findings and recommendations. ABS served as the CVA. During the life extension assessment process, ABS Group and Noble Energy consistently coordinated with ABS, BSEE and USCG.

Based on the life extension assessments, ABS has granted class certificate for the life extension of this platform. The process of the spar's life extension assessment provides industry with a better understanding of the technical requirements for life extension of other floating production assets, which will have a long-term impact on future asset integrity management for these types of facilities in deep water.
Mooring Integrity and Machine Learning
Authors: Prislin Igor , Maroju Soma
Published: April 2017

Maintaining the expected position is critical to the overall safe operation of a floating oil platform. Mooring systems are critical to the integrity of the platform. Relying on instrumentation for monitoring the mooring line tensions represents multi-faceted challenges. Therefore, alternative methods have been introduced across the industry to reduce the costs and complexities of maintaining these systems.

The paper discusses implementation of the Position Response Learning System (PRLS), a novel concept for addressing the integrity of mooring systems. PRLS is based on emerging data technologies and particularly machine learning that bridges the gap between a variety of global position measurements of the oil-platform and the mooring integrity paradigm. Machine learning enables learning from large amount of data without explicit programming. The PRLS concept does not require expensive line-tension measurement systems, but rather the global motion systems enhanced with the metocean monitoring. The global motion systems that include DGPS and MRU are typically already installed on oil platforms. In addition to measured data, PRLS can utilize a plethora of other data sources, including numerical simulations, model test data, and most importantly, the real-time and archived field data other than the line tensions. When the data are coupled with machine learning methods, they provide reliable, robust, and cost-effective solutions to address the integrity of the mooring system in real time of the oil platform.

The article illustrates how the PRLS can identify a mooring line failure and even indicate which of the mooring line fails. Preliminary results based on the simulated data show that the accuracy of such predictions is better than 98%. The PRLS runs in the background independent of other integrity monitoring systems. It requires retraining periodically with new field data to improve the prediction robustness and accuracy. PRLS may be deployed on all types of floating platforms under a relatively moderate capital expense, and with very low operational costs when compared to high capital and operational expenses of a subsea mooring line monitoring system.
Chemical Injection Optimization: How Leverage of Flow Assurance, Materials Science and Production Chemistry Knowledge Can Reduce Uncontrolled Expenses in Production Chemicals Utilization
Authors: Osorio N. F. , Chipuk T. A. , Anderson L.
Published: April 2017

Corrosion, scale, asphaltenes, wax, sand, hydrates, and emulsions are common problems encountered in oil and gas production. Production chemicals have been developed to mitigate their effects, but many operators are not aware of the value of a systematic approach utilizing flow assurance, materials science, and production chemistry to create an optimized production chemical management program (PCMP). The effect of unoptimized production chemical expenses on operational expenditures can shorten the economic life of an asset; Therefore the necessity of implementing an effective PCMP is of paramount importance given the persistence of the low cost environment in oil and gas production nowadays. This paper focuses on the analysis of diverse field experiences from projects where the authors have been involved for several years, and the lessons learned in the process of developing and managing effective PCMPs. It aims to be a guideline on the necessary information and practices that are essential when developing a management program for efficient chemical utilization in offshore projects.
Field Test Results for a Subsea Wireless Annulus Monitoring System
Authors: Rodriguez F.J. , Mat Isa S. , Forness A.
Published: April 2017

The objective of this paper is to present the field test results of a subsea casing annulus monitoring system utilizing wireless through-wall communication technology which recorded and transmitted pressure and temperature data from a casing annulus in real-time during the drilling, logging, and capping phases of a subsea well.

The annulus monitoring system used off-the-shelf sensors to acquire pressure and temperature data in the casing annulus. The data was communicated from inside the casing annulus to the outside of the subsea wellhead system using a novel wireless telemetry technique through solid casing layers instead of traditional bulkhead connected equipment to avoid penetrations to the high pressure housing. The sensor module was attached to a 13-3/8" casing joint below the casing hanger and was configured to fit into the annular space between the 13-3/8" casing string and a 20" casing string. Additional telemetry equipment was adapted to the outside of the low pressure wellhead housing and a 30" conductor casing string which received and processed the transmitted data.

Once installed, the monitoring system continuously transmitted temperature and pressure data throughout the rest of the drilling program until the well was plugged and abandoned. The annulus data revealed how high the annulus pressure increased due to thermal effects while drilling and circulating fluids in the wellbore bottoms-up. Upon completion, the system confirmed that the trapped annulus pressure below the 13-3/8" casing hanger annulus seal assembly was low enough that the wellhead and casing could be safely cut and retrieved. The field test confirmed that the monitoring system is suitable to survive drilling operations and communicate data from the wellhead casing annulus to the end user in real-time. This marks a first for a drilling-centric wirelessly transmitted annulus monitoring product that takes the guesswork out of annulus pressure well-control or remediation concerns. It allowed the drilling group to see live data on the fluid pressure and temperature in the annulus of a wellhead system without any type of penetration while drilling the remaining critical sections of the well and did not require any modification to existing subsea wellhead components or operating procedures.
Using a Cognitive Analytic Approach to Enhance Cybersecurity on Oil and Gas OT Systems
Authors: Rosner M. , Herve P. , Moore K.
Published: April 2017

In the days before the "digital oilfield" and the Internet of Things, companies struggled to find ways to centralize their operational information. It was extremely difficult to efficiently monitor all assets, provide support, and solve problems in real time for better decision-making. Companies that have been able to do this now are staying competitive and cutting their costs.

More recently, organizations have started to implement IoT solutions onto their systems. Countless hours and human resources are saved, processes are improved tremendously, and failures are minimized. All the data from almost every system available can now be accessed, measured, and managed in one place. This is a remarkable advancement, yet it is also the reason why cyber-attacks are getting more dangerous than ever before. Since systems are now connected, they can be attacked and compromised, even if these controlled systems are dispersed in decentralized locations.

To sufficiently combat the growth of threats in both number and sophistication, combined with the scarcity of security talent, the oil and gas industry needs a stronger approach to cybersecurity. AI-based solutions for cybersecurity can monitor and protect not only the IT infrastructure, but also the OT network. These solutions can inform analysts where to look in order to identify the exact location of a potential attack, and provide evidence as to the validity and severity of the threat.
PYRO-Accumulator: Rocket Motor Powered Hydraulic Power Source
Authors: Bedrossian Nazareth , Welker Joseph , Coppedge Charles , Hernandez Jorge
Published: April 2017

This paper describes the PYRO-Accumulator, a piston accumulator which uses a solid propellant rocket motor instead of compressed gas. The rocket motor is used as a gas generator to pressurize hydraulic fluid inside the piston accumulator. PYRO-Accumulator is a self-contained, unpressurized dormant device, much like an airbag system for automobiles, which provides pressurized hydraulic fluid on demand. It is particularly suited for emergency single-use applications such as closing of subsea BOP shear rams, or applications requiring finite number of operating cycles. PYRO-Accumulator is a conventional piston accumulator that is retrofitted with a PYRO Kit in the space that would normally contain the nitrogen gas. Only minor cap modifications are required and which do not change the piston accumulator pressure vessel certification. Replacing the nitrogen gas with a PYRO Kit increases the accumulator usable fluid by more than 5X for the same working pressure resulting in significantly reduced weight and footprint. Additionally, the PYRO equipped accumulator requires essentially no maintenance and has a service life of more than 10 years, and offers quantifiably and scalable high reliability. Results from a pipe shearing demonstration are also provided.
Novel Degradable Polymeric Composite Balls for Hydraulic Fracturing
Authors: Garza Ramon , Sadana Anil , Khatiwada Suman , Duan Ping
Published: April 2017

Degradable polymeric balls are becoming popular in well completions especially for hydraulic fracturing applications. Commercial degradable polymeric frac balls, however, are not suitable for high-temperature plug-and-perf applications due to the low glass transition (Tg) temperature of the base polymer. At the application temperature above Tg these commercial degradable polymeric frac balls become too soft and their mechanical integrity is compromised. This paper describes the application of a new degradable polymer composite frac ball made from a thermosetting polymer with (Tg) >500°F for use in hydraulic fracturing applications. This degradable polymer composite is good for a temperature envelope of 200°F to 350°F and differential pressures up to 10,000 psi for fracturing applications.

Multiple Pressure and impact tests were performed on the frac balls made from this material to demonstrate that the material had mechanical properties that would withstand the application requirements. Differential pressure tests were conducted on two types of ball seats at different temperatures. Frac balls were tested for plug-and-perf application on ball seats with a conical engagement.
The Shallow Water Enigma: Optimizing Conventional Logging for Identification of Deep Sea Dynamic Formations
Authors: Schexnayder Peter , Guillory Gordon , Hodges Claire , Carroll Landon , Wilson Matthew
Published: April 2017

The objective of this paper is to discern a manner in which the petroleum industry might determine the existence of shallow water flows, or subsea regions of pressurized water and sand, prior to drilling into said formations. Since 2001, a dozen wells have been lost to this phenomenon and millions of dollars have been spent in damages in the Gulf of Mexico alone. Research and analysis of current methods led to the discovery of three additional methods of determining shallow water flows through logging and above-ground tools. These methods were cross-referenced and compiled to produce a four-marker logging indicator which definitively characterizes shallow water formations in the wellbore. When these markers are manifested, this paper offers an updated version of the FKB (flow-kill-breakdown) Cycle in order to stop the kick before it occurs. Furthermore, it offers an opportunity to survey existing wells to create a geological profile which includes these dynamic formations. Familiarity with shallow water flows from a petrophysical perspective has become essential to save time and money, promote safety, and to further the industry's knowledge of shallow water flows. The vast majority of wells drilled in the Gulf of Mexico reside in a high profit area beyond the Late Pleistocene deltaic depocenter, which is a high-risk area for these formations. This research paper has assembled four major indicators for these shallow water formations. From Shaker's research, it has been determined that the pressure profile of any sand formation will be linear. Furthermore, porosity will spike at shallow water flow locations due to their hyperpressurized condition. Ostermeier and his team assembled indicators by observation, noting that pressure would spike and gamma ray results would decrease when encountering such a formation. When depth is restricted to the 1,000 to 3,500-foot range, these indicators offer a narrow and specific profile to locate shallow water flows before drilling into them. At an average cost per well of $1.6 million in damages due to these formations, those are savings worth pursuing. The drilling of offshore oil and natural gas will be safer with the implementation of shallow logging and the incorporation of these identifiers. Though the components of this research have existed for decades, this paper uses fundamental analysis of the issues involved to uncover a previously unknown formula which acts as a preventative measure against kicks, blowouts, and loss of hole due to shallow water flows. Furthermore, an amendment to an existing API document is proposed, which would alter practices in the region by implementing the proposed solution across the country.
A Novel Hydrate Strategy in a High Risk Hydrate Environment for a Fast Track Tie-in GoM Development
Authors: Uribe Oscar , McDermott Chris , Hudson Adam
Published: April 2017

Under the current market environment, deep water projects are required to evolve a more robust cost solution to remain competitive within the industry portfolio, ensuring safety as priority. With such market drivers in place, this paper details the engineering behind the development of a single flowline concept that ties-in to an existing production system for a GoM deep water development and the associated challenging flow assurance aspects of that design.

The development is a fast track project (approximately 1.5 year from concept to first-oil) that leverages existing subsea infrastructure. The flowline length is over 10,000 ft at water depths exceeding 5,000 ft and will tie-in to a current flow loop dead leg of more than 7 miles in length. Success of the project will set a trend and allow development for future projects, i.e. infrastructure led solutions utilizing single flowlines with rapid delivery and increased financial returns.

To meet economics and schedule, the tie-in is a flexible flowline, which implies limitation in the amount of insulation that can be added to the system; in addition the reservoir temperature is relatively low. These challenges constrain the operating envelop, limited by thermal performance.

Traditional hydrate strategies such as dead oil displacement are not possible for a single leg spur line and continuous hydrate inhibition is not feasible from an OPEX aspect. Therefore a novel hydrate management strategy leveraging existing infrastructure is deployed. The development behind the hydrate and other flow assurance strategies is presented in this paper, as well as the realization of those strategies through to operation.
DeepStar Global Offshore Technology Development Program: New Generation Computational Capabilities in Nonlinear Dynamic Simulations of Flexible Riser Systems
Authors: Majed Arya , Yiu Flora , Chinello Luca , Cooke Nathan , Gomes Joseph , Kusinski Greg
Published: April 2017

A method for accurate prediction of flexible riser behavior and component stress computations under irregular wave inputs is a subject of major interest to offshore oil and gas operators. The initial full field procurement for flexible risers can be upwards of 500M USD, with replacement costs of a single flexible riser often approaching 40M USD. The reliability of fatigue life estimates is therefore critical to the successful long term operation of flexible risers. Computational constraints, however, continue to prevent realistic simulations and meaningful fatigue life predictions.

To address this challenge, a next generation computational capability for nonlinear dynamic simulations of flexible risers has been developed. The FLEXAS solver overcomes computational constraints which limit conventional flexible riser analysis methods by implementing Nonlinear Dynamic Substructuring (NDS). This advanced multibody framework enables the incorporation of detailed finite element models into global nonlinear dynamic simulations under realistic environmental and system loads. Prior to this development, simulating these complex models for spans greater than a few pitch lengths was computationally not feasible even in static cases. The purpose of this DeepStar project is to validate the FLEXAS solver for nonlinear dynamic simulations of flexible risers against numerical and experimental references, and includes extensive local and global benchmarking.

The local benchmarking scope involves comparing FLEXAS simulations against numerical and experimental references of pitch-length and bench test configurations. These benchmarks comprise a wide array of tensile armor stress and strain comparisons made against both a commercial solver and strain gauge measurements. The global benchmarking scope involves the comparison of FLEXAS simulations of a full length flexible riser configuration against the industry accepted numerical benchmarks, which includes large displacement nonlinear statics, vessel motion nonlinear dynamics and regular wave motion nonlinear dynamics. Results from all nonlinear simulations were in excellent agreement with their respective benchmarks.

This work was initiated, technically guided and funded by DeepStar Global Deepwater Technology Development Program as part of Phase XII projects in the DeepStar X400 Floating Systems Committee. The successful completion of the project, established herein, is to build confidence within the industry, which will benefit from the validated FLEXAS simulation technology by improving decision making associated with flexible riser integrity management and continued service, with major cost savings realized across the entire flexible riser life-cycle.