bluuebunny/crossref_metadata_2025 huggingface dataset:
Horizontal Wave Impact Loads for Column-Stabilized Units Operating in Harsh Environment
Authors: Szalewski Piotr , Lu Jenny Yan , Johannessen Thomas B.
Published: April 2017

The objective of this paper is to share lessons learned with the industry from a recent accident and provide a recommended procedure for evaluating airgap and possible horizontal wave impact loads for column-stabilized units operating in harsh environments.

On 30 December 2015, when operating on the Troll field, a column-stabilized drilling unit, COSL Innovator, was hit by a steep wave that impacted directly on the forward port side of the deck box. This resulted in several damaged windows, one fatality, four injuries and structural damages to the front of the deck box.

Following the accident, there is increased attention and concerns raised by some regulatory bodies for safe operation of semi-submersibles in harsh environment. In order to evaluate the adequacy of Class rule requirements and pertinent industrial design practices, DNV GL has investigated and analyzed the circumstances surrounding the accident. The conclusion from this work is that there is a need for improved guidelines for calculating horizontal wave impact loads on deck box structure if a column-stabilized unit is designed to operate with a negative airgap, together with improved methods for calculating the airgap with a prescribed annual probability of occurrence. DNV GL has developed "Offshore Technical Guidelines" (OTGs) that can be used to document compliance with classification rules stipulated in DNVGL-OS-C103 [1]. Development of these guidelines has brought a deeper understanding with respect to airgap and associated horizontal wave impact loads on column-stabilized units.

This paper discusses the technical challenges related to airgap prediction and wave impact load calculation, provides the technical background and insight of recently released Offshore Technology Guidance OTG-13 [2] and OTG-14 [3], and suggests a way forward.
The Use of Motion-Based Technology in Oil and Gas Supply Chain Logistics
Authors: Ulrich Matt
Published: April 2017

Objectives / Scope

The objective of this paper is to ascertain if motion-based GPS technology can replace the complex RFID infrastructure for the automated logistical control over consignment stock movement globally. This shall be demonstrated through field data results and benefits of using motion-based GPS technology in oil and gas supply chain logistics to monitor the movement and location of offshore equipment and materials through findings of a pilot project.

Over the past few years, the adoption of asset tracking technology in oilfield operations has provided operators and service companies with increased visibility of the supply chain leading to a reduction in operational costs.

New motion-based GPS technology is more advanced than a time based locator (traditional GPS technology provides one-way communication every 12-24 hours) to a movement based locator providing two-way communication.

This has the potential to provide an overview of when materials are transported and has the ability to accurately illustrate events such as arrival at an offshore platform, vessel movement or onshore at quayside/ remote locations which triggers customer billing.

Methods, Procedures, Process

100 cargo carrying units (CCUs) were tagged for a pilot project to test this technology. Each of the CCUs processed through a cycle of leaving customer site onshore, being transported to port/quayside, shipped offshore and returned to the original onshore site. The GPS unit reports based on motion of the unit progressing through the cycle, as opposed to daily pre-set time scheduled reporting, providing customers with a complete overview of their CCU movement cycle. The accuracy of this turnaround was compared to results gained using current RFID infrastructure which is generally accepted as being a more accurate technology.

Results, Observations, Conclusions

The pilot confirmed that motion-based GPS is more accurate and can replace RFID for the automated logistical control over consignment stock movement globally.

The following results were obtained from the 205 entry and exit events: RFID reported 75% accuracy, reporting 164 events and missing 41Motion-based GPS reported 99.01% accuracy, reporting 203 events and missing 2

Novel, Additive Information

Motion-based GPS technology has been illustrated to be a consistent, viable approach to controlling consignment stock on a global basis providing two-way communication, greater control and oversight to the customer as conveyed through our pilot project. The adoption of this new technology is also cost-effective to implement compared with the current complex infrastructure set up required through RFID.
New Criteria of Hydrate Inhibitor Requirements in Tropical Shallow Waters
Authors: Meng Weihong , Kak Ashutosh
Published: April 2017

For oil and gas development projects in shallow waters in the tropic areas the water temperature is usually high (above 16°C all year around). Low fluid temperature is possible during operations due to Joule-Thompson cooling in early life when reservoir pressure is high. The nature of hydrate plug formation risk in the tropical shallow waters is very different than that in the deepwater projects (where ambient temperature is about 4°C). In tropical shallow waters the low temperature is mainly created by gas expansion or significant choking. Heat will be transferred continuously from the pipe wall toward the bulk fluid stream. At certain pressure and temperature hydrates may form, but the low thermal conductivity of a hydrate layer makes it difficult for hydrate particles/aggregates to stick to the pipe wall and form plug. Understanding this phenomenon will significantly reduce the hydrate inhibitor requirements and ease operations of the production system.

In this paper hydrate physical properties were collected from literature. Based on these properties the heat transfer rates and hydrate layer dissociation rate is estimated. The results show that at 10°C of sub-cooling, hydrate layer will not adhere to the wall in a tropical flowline, therefore, a hydrate plug could not form. If this concept is applied to operations of an existing asset, hydrate inhibitor usage can be significantly reduced whilst improving operation efficiency and flexibility. For a new facility design hydrate inhibition injection rate and storage volume can be significantly reduced, which will result in CAPX and OPEX savings. Application of this philosophy will significantly reduce the weight requirements and extending supply period of the hydrate inhibitor for a production platform, lower the hydrate inhibitor consumption over the field life, ease the operation of the asset, and increase the chance for successful offshore projects.
Digitalization of Oil and Gas Facilities Reduce Cost and Improve Maintenance Operations
Authors: Devold H. , Graven T. , Halvorsrød S. O.
Published: April 2017

Objectives/Scope

The digitalization of oil and gas facilities is becoming a new theater of operations. Effective solutions can be employed to convert data into information and knowledge, which can then be used to improve maintenance operations. Wear and tear can be discovered before faults occur, which enables cost reductions and safety improvements. All relevant data can be made securely available in cloud repositories, and big data techniques can be used to analyze failure patterns and failure modes for equipment categories, and identify the performance characteristics associated with particular manufacturer or equipment types.

Methods, Procedures, Process

This paper describes some technologies employed in digitalization, ranging from the basic connectivity infrastructure to data-gathering and storage and techniques for extracting new information from big data. We also discuss how organizational form affects the ability to realize value from integrated operations and digitized assets.

Results, Observations, Conclusions

One main issue for these facilities is data "lock in", in the sense that data availability across departments, to other systems and external experts is limited by proprietary data models and systems. However even if a cloud type repository is desirable, this also gives challenges in cyber security and protection of proprietary data. A second challenge in the implementation and deployment phase is to underestimate or even neglect the need to change work processes, including operation model. We present the "8 steps to a maintenance plan including CBM and PBM" developed as a result of these experiences.

Novel/Additive Information

In normal situations, even fractional improvements in plant uptime is by far the largest contributor to improved earnings. About 40% of production loss is related to preventable operator errors. In a normal plant, this could account for 1-2 % of total plant production capacity. The second contribution to plant uptime comes from elimination of unplanned shutdown. Condition based maintenance systems assist the operator in correct response to possible malfunction e.g. by shifting to redundant equipment or reduce load on equipment until maintenance action can be performed. In-operation failures can be reduced by over 90% and contribute an additional 2-3 % points to plant availability. Critical safety events are often the result of multiple maintenance safety issues, each non-critical, developing into an unmanageable situation. Finally, the actual cost of maintenance is reduced by 15-40%. In typical projects the total cost of maintenance operations is equivalent to half the EBITDA of the plant and so is a significant contributor to financial performance.
Quantification and Modelling of the Dynamic Wake Effect for Floating Offshore Wind Turbines
Authors: Singapore Wala Abdulqadir Aziz , Ng Eddie Yin-Kwee , Bahuguni Anand , Srikanth Narasimalu
Published: April 2017

Modelling the aerodynamic forces on floating offshore wind turbines (FOWTs) is a challenging task due to the motion of the floating platform, which result in flow transients and associated aerodynamic effects. Each of these needs to be modelled and implemented, before a complete aerodynamic model of the FOWT can be presented. Of special interest is the dynamic wake effect, a result of the time lag between rotor forces and the air flow deceleration within the wake. The dynamic wake effect may present itself significantly in several scenarios including gust loads, changing wind speeds and direction, and the oscillatory motion of the rotor due to platform motion from wave forces. The complexity of the problem is substantiated by the added mass effect, which must be accounted for when considering rotor motions through the air. Computational fluid dynamics (CFD) simulations and blade element momentum (BEM) computations have been performed for the NREL 5MW virtual wind turbine in axial flow and surge motions at different frequencies and amplitudes, to quantify and model the dynamic wake effect, including the added mass effect for rotor motion. This dynamic wake model is then implemented in an unsteady blade element momentum (uBEM) code, for a more complete model of wind turbine aerodynamics.
The Value of Pressure Relief in Hydraulic Fracturing Operations
Authors: House Ryan , Pry Mike , Pitcher Jason
Published: April 2017

In hydraulic fracturing operations, pressure pumping companies have long required a mechanism to relieve overpressure events prior to damage occurring to the systems. Traditionally, pressure pumpers have used mechanical or hydro-mechanical devices that are either one-time use, such as burst disc, or springs under compression. Both systems have fundamental disadvantages in the context of efficient and cost effective operations. There is also the case that if the well requires pressure operations within the setting tolerances of these systems, they are not employed at all, risking overpressure damage to frac iron or wellhead equipment.

This paper introduces a new method of pressure threshold assurance, with a pressure monitoring system that is responsive enough to control a new design of rapid acting hydraulic valve actuator. In this application, this is mated with a standard gate valve that is installed on a bleed off leg from the frac flow lines. This allows very fast acting pressure relief, proactively protecting the system against costly over pressure events and potentially averting screen outs.

A discussion of the design and function of the new solution, with due regard to limitations, best practices and workflows will be demonstrated, providing an examination of the results of operational case histories. Some of the benefits that have already been realized, and the potential for further implementation are proposed, as well as highlighting operational differences vs current technology that deliver value to pressure pumpers and operators.

With a proven ability to relieve pressure within very tight tolerances, this new system allows for operational gains associated with resetting the system and retaining system integrity, but also allows operators to pump jobs in a much tighter pressure window than before. Unexpected benefits are that lower pressure wellhead equipment can be safely used without risk of costly integrity issues. Other examples of how this system provides surety to pressure pumping operations are examined.
A More Holistic Approach to Oilfield Technology Development
Authors: Sequeira M. , Elshahawi H. , Ormerod L.
Published: April 2017

The latest oil industry downturn has had a dramatic impact on innovation in the oil and gas industry. Staff and budgets have been cut dramatically, large field developments have been deferred, and new technology initiatives have been severely cut or entirely cancelled. As a result, most oil and gas companies and their supply chain have radically downsized. Some have simply right-sized, and others have completely capsized. Finally, new oil & gas discoveries around the world dropped the last couple of years to their lowest levels since the 1940s after companies sharply cut back in their search for new resources amid falling oil prices. This makes offsetting natural depletion of existing fields even more challenging and can lead to potential supply shortages by the end of the decade. This type of implosion is symptomatic of dramatic commodity price collapses. Remaining competitive in this challenging environment requires a more strategic and holistic approach to oilfield technology development.

Experience shows that the vast majority of R&D and technology initiatives fail to reach commercial deployment. Success is often measured as the ability to progress through a mostly technical stage-gating process, with little consideration given to the commercial validity of continuing to invest time and resource. This results in far too many projects tenaciously marching into the classic "Valley of Death" - the virtual chasm that separates innovation from commercial demonstration. Yet technology and innovation will still be needed to safely find, develop and operate especially with the operating conditions and overall business environment becoming ever more challenging. Service companies must also remain technically and commercially competitive as a matter of urgency, if not survival. Thus, while technology leaders must be prepared to intervene by cutting, stopping, or divesting programs that are off track, they must also continue to replenish and rationalize their technology portfolios to differentiate their companies.

The approach described in this paper takes a holistic view of technology maturation which addresses both technical and non-technical risks, which is by design more concurrent than serial. The definition of success is expanded to include the establishment of successful, commercially viable, and sustainable solutions that meet end user needs and requirements. Improving the efficiency and effectiveness of technology development and investing smarter allows operators and service providers to leverage new technologies to address existing and evolving challenges and to remain competitive now and in the future.
We're Stuck: Efficient Casing Removal for Well Abandonment Applications
Authors: Joppe Lambertus C. , Nelson Jonathan F. , Kelman Gary L.
Published: April 2017

Well abandonment operations represent pure cost to the operator without return on their expenditure. However, to manage future liability, these activities are critically important. Performing them correctly involves detailed planning. Good practice places a permanent barrier across the wellbore in competent cap rock and embeds all tubulars in the cement. Herein lies the main challenge for well abandonment; annular isolation is sometimes compromised or wasn't there from the start (e.g., subsea wells). Addressing these annular isolation issues results in extra steps in the well abandonment process, translating into extra time and money for the operator.

This paper will discuss field-proven, cost-effective solutions for casing removal including reducing the surface footprint or providing a single-trip solution that lowers the overall cost of operation.

Multiple case histories will highlight different challenges, solved by novel ideas and a combination of surface systems and downhole equipment.

Case History 1: 13⅜-in. casing partially stuck in the well needs to be removed, a single cut-and-pull operation was not successful and milling was not an option due to shallow/weak formation and equivalent circulating density (ECD) issues. Advanced milling technology enabled 30 casing cuts in a single trip in short sections, allowing each section to be pulled free using the rig's pulling capacity while minimizing surface handling.

Case Study 2: Platform load capacity or pulling capacity limitations often lead to challenging casing removal operations for slot recoveries and/or permanent well abandonment. Exercising downhole pulling force by anchoring in a larger casing size and utilizing pump pressure instead of overpull enables freeing of pipe with limited surface capabilities. Multiple examples will be shown, including time saved.

Case Study 3: Platform conductor removal operations can be very challenging when the type of connectors cannot carry the full conductor load with inner casing strings. A Rigless solution performing simultaneous operations with the main platform rig, using a sacrificial casing string to pull from the bottom provided a cost-effective solution.

Case Study 4: Platform conductor removal where the conductors have been previously cut and now stand in the water column present challenges of a different kind. The limited platform size led to a casing jacking solution with guide wires that safely and cost-effectively remove the conductors from below the mudline without bringing in a jack-up rig.

A "now what" selection guide at the end of the paper provides an overview of different solutions available, depending on downhole scope of work and the surface capabilities.
Validation of Global Riser/Wellhead Analysis Using Data from a Full-Scale Measurement Campaign
Authors: Agarwal Puneet , McNeill Scot , Bhalla Kenneth , Walker Karen
Published: April 2017

Fatigue damage predictions of risers and wellhead/casing systems due to drilling operations require predictive modeling techniques for load calculation/estimation. This work attempts to address the uncertainty as to whether the global riser analyses are overly conservative due to model idealizations, analytical assumptions, the use of time- or frequency-domain techniques, and incorporation of certain linear or non-linear behavior. To address these questions, a field measurement program was executed to obtain vessel, riser and stack motions data, which were used to validate analytical models and procedures.

A real-time monitoring system was deployed on a 6th generation semi-submersible mobile offshore drilling unit operating in a shallow water, harsh environment region. Accelerations and angular rates were captured on the Lower Marine Riser Package (LMRP), drilling riser and vessel. The metocean data consisting of measured seastates and full-depth current profiles, as well as riser tensions, mud weights, and vessel offsets were also concurrently recorded. The global models of the riser, wellhead, stack, casing and soils were created using two in-house software, DERP (frequency-domain) and RAMS (both frequency- and time-domain), using "as-designed" input information.

Analytically predicted motions (displacements and rotations) of the LMRP, riser, and vessel were compared with the measured motions. It was found that the frequency-domain analytical results match the measured data well over all the measured significant wave heights, which ranged from 6.5-ft to 26-ft. Since the riser and LMRP RMS motions are well predicted by models, it follows that wellhead loads are well estimated from analytical models. The frequency-domain analytical results were further verified for a few cases by time-domain analyses. Both measured and analytical spectra generally exhibit peaks at similar frequencies. While the first analytical riser mode is clearly identified in the measured data, the analytical blow out preventer (BOP) stack/riser mode is not as evident in the measured data. Further, the measured peak close to the analytical stack/riser frequency is very broad. These observations and additional sensitivity studies showed that further investigation for sources of damping due to soil and/or stack hydrodynamics is required.

This work shows that the modeling techniques used presently for analyzing the global riser/stack response in frequency- domain are reasonably accurate for the analyzed conditions.
Case Studies of Industrial Standardizing and Cost Efficient Offshore Concept
Authors: Wang Aimin , DaSilva Otto , Tredennick Owen
Published: April 2017

Low cost and high efficiency is a necessity for the offshore industry in response to the current low oil price. This paper presents case studies investigating the key factors of standardization and cost efficiency from the EPCI perspective for deep water offshore projects based on two semisubmersible floating production systems (FPS) recently installed and currently operating in the GOM. The philosophies used and methodologies applied in the engineering design, construction, and installation of both units will be reviewed through different stages of the projects.

The paper presents how safety, standardization, operability and constructability were considered and prioritized in the projects from the concept through detail design resulting in cost and schedule efficiencies. Some special considerations and methods utilized during different design stages which facilitate ease of construction and installation are discussed.
Pipe-Clamping Mattress to Stop Flowline Walking
Authors: Frankenmolen Sebastiaan , Ang Sze-Yu , Peek Ralf , Carr Malcolm , MacRae Ian , White David , Rimmer Jeffrey
Published: April 2017

Thermal gradients from a heating front travelling down a flowline at start-up can cause a flowline to walk much like a worm creeps by repeated contractions and expansions of its body. To stop this for the Malampaya flowline, pipe-clamping mattresses (PCMs) were invented, developed, and deployed within a period of 12 months. The objective of this paper is to share the knowledge and experience from this novel but effective solution to mitigate pipeline walking.

PCMs provide a cost-effective alternative to rockdump or conventional mattresses to axially restrain a pipeline at a location chosen so that the required restraint capacity is minimized. They are inspired by conventional mattresses and bear some similarity to them, but they are designed so that the weight of the mattress acts to clamp the pipeline with a high leverage. Thus 100% of the weight of the mattress is effective in generating axial friction with the seabed. This solution can be applied at any point along the line (chosen to minimize the required resistance) without requiring flanges or collars on the pipeline.

From the most recent survey results 15 PCMs with a dry weight of around 9 tons per PCM, plus 7 tons for the logmat installed over every PCM appear to be effective to stop the walking of the Malampaya flowline. This performance is as expected from extensive analysis (FE and otherwise) to reproduce the observed walking behavior prior to restraining, to estimate the required restraint capacity, and to estimate the resistance provided by the PCMs.

This paper describes the PCM, the clamping forces they generate by leveraging the weight of the PCM and logmats installed over them, and how the friction generated with the soil is estimated from interface shear tests on samples collected from the site, considering cyclic pore pressure generation and dissipation effects. It also briefly covers FE analyses to reproduce the observed walking behavior, and determine the required restraint capacity, the PCM fabrication, installation, and monitoring of the post-installation performance.
Bow-tie Analysis of Underwater Robots in Offshore Oil and Gas Operations
Authors: Yu M. , Venkidasalapathy J. A. , Shen Y. , Quddus N. , Mannan S. M.
Published: April 2017

Deepwater drilling exploration takes place in cold, distant, and extremely high-pressure environments. It poses a great threat to human life and environment, and incurs higher cost of production than conventional drilling operations. To improve efficiency with increased production, offshore oil and gas industry introduced robotics technology in many underwater drilling and production operations. Implementation of robots also introduced complexity and added risks to the processes. The present study aims at identifying hazards and assessing risks associated with using underwater robots in offshore oil and gas production. Once potential scenarios caused by robotic failures are identified, consequences could be developed, and risk assessment could be done by traditional methods. The specific objectives of the current research are: to study robotics technologies used in offshore platforms primarily, autonomous underwater vehicles (AUV); to understand their roles and limitations in oil and gas production; to study potential threats leading to underwater robot-robot collision or robot-structure collision; to evaluate all possible consequences due to collision; to recommend necessary safety barriers for identified threats.
New Generation of Ultrasonic Technology for Cement Evaluation in Complex Environments
Authors: Shaposhnikov Pavel , Thierry Sylvain , Lake Patrick
Published: April 2017

Now, more than ever, the integrity of the wellbore before the recommencement of drilling operations or production of reservoir fluids, is fundamental to safe operations. Stricter well control policies have been instated in recent years, so it is critical to perform casing inspection, and cement evaluation measurement surveys to ensure adherence to regulatory codes.

As exploration and development drilling activity breach new horizons, it brings new challenges to cementing operations and subsequent cement evaluation surveys. Heavy drilling muds, extra-large casing sizes, and narrow drilling windows: cement to mud weight ratios which can led to cement contamination are just a few. Until recently these constraints limited the usefulness and reliability of ultrasonic measurements under the said conditions.

This paper describes a new generation of ultrasonic sensors and technology that fills the gaps left by predecessor technologies and allows operators to feel confident and at ease with the integrity of their wellbores, even under the most taxing conditions. The advantages and associated cost savings enabled through the utilization of this technology are illustrated in the case studies at the end of the paper.
Water Column Velocity Function for the Gulf of Mexico
Authors: Pryne Daniel , Kucera Michael , Gharib Jamshid
Published: April 2017

Water column velocities derived from deep water Gulf of Mexico conductivity, temperature, and depth data has been modeled into a seventh-order polynomial to provide a function for seismic time to depth conversions. This model is most accurate in Gulf of Mexico water depths ranging from about 1,500 to 13,000 ft, away from anomalous areas of higher temperatures and salinity. The utility of this equation extends from geohazard assessments to augmenting incomplete velocity profiles for geophysical surveys.
Integrated Study of a Complex Seabed For the Stones FPSO
Authors: Hadley C. , Bradford K. , Young A. , Trandafir A. C. , Bruce B.
Published: April 2017

Shell's Stones field is located below the Sigsbee escarpment on the continental rise in the Walker Ridge area of the Gulf of Mexico, in a water depth of approximately 9,500-ft. The seafloor is irregular due to the presence of furrows, which have been eroded by bottom currents. These features, combined with positioning uncertainties associated with surveys in this extreme water depth, posed a unique challenge to characterization of the seabed and to siting of infrastructure.

Design soil properties were selected by integrating Autonomous Underwater Vehicle survey data with data from two geotechnical investigations. These data sets are typically correlated by using the seafloor as the vertical reference datum. This was not possible in the Stones field, so the data was instead correlated to a marker horizon, which was common to both the shallow seismic and the geotechnical data sets. Additionally, seafloor bathymetry data were screened using pre-determined criteria to optimize FPSO mooring anchor locations.

This paper presents sample geophysical and geotechnical data from the Stones field and describes the process used to integrate the data and develop design information. The selection of FPSO mooring anchor locations within the variable bathymetry is also described. Finally, installation records from the FPSO mooring system are presented, which demonstrate the value of the integrated approach to site characterization. The process for data integration at Stones can serve as a model for future developments, with complex seafloors.
Driver Selection for Refrigerant Compressor for Small Scale FLNG
Authors: Kumar Balesh , Jang Jungmoon
Published: April 2017

Recently the demand of LNG has increased and will continue to increase in near future. To meet this demand exploration has gone into offshore with the Development of FLNG, with one of them having completed his first off take to an LNGC and several of them under Construction at the time this Technical paper is prepared.

One of the challenges lies in the correct selection of the driver for LNG refrigeration compressor on FLNG. Although both mechanical drive as well as electrical drive is applied on land based LNG plant, the situation is quite different in offshore as very limited experience is available and no electrical drive has been selected so far for FLNG facility.

The findings on drive selection and their economic and operational advantages are discussed in this paper.

Power generation system and refrigerant compressor system are very important systems to be evaluated together for the FLNG facility to achieve optimum solution.

FLNG has limited space, sensitive to motion, standalone power generation, inherent difficulty for providing maintenance support and limited operating staff. These factors are well known to FPSO/ FLNG providers and all of them will agree that driver should be simple, robust, reliable and cost effective.

We have three types of choices available for such large compressor i.e. steam turbine, gas turbine (GT) and Electric Motor (EM). Comparison focuses on the GT and EM along with their characteristics

FLNG facility does require standalone electric power generation on board. The electric power generation can be achieved either by GT generator set, steam turbine generator sets or gas engine sets. The power generation has impact on driver selection in terms of improving thermal efficiency, availability, inventory control and use of fuel.

There are several parameters which need to be considered for evaluation before finalizing the driver selection for Refrigeration compressor on FLNG. A case study previously developed under OTC-27731 (Associated Gas FLNG with One or Two Liquefaction Trains) is used to map these parameters to depict the reality of driver on small to mid-scale FLNG facility

Therefore, this paper will evaluate how to select correct driver system for refrigeration compressor considering all the factors. It will also provide useful guidelines for owners, field operators, designers and EPC contractors to arrive at right solution for their specific application.
Hydrate Formation and Transportability Investigations in a High-Pressure Flowloop During Transient Shut-in / Restart Operations
Authors: Srivastava Vishal , Majid Ahmad A. A. , Warrier Pramod , Grasso Giovanny , Chaudhari Piyush , Dendy Sloan E. , Koh Carolyn A. , Wu David T. , Zerpa Luis E.
Published: April 2017

The presence of gas hydrates in subsea production is identified as a major flow assurance challenge due to the rapid formation of hydrates and their risk of causing flowline blockages. The risk of hydrate-associated blockages could be higher for transient (shut-in/restart) operations compared to continuous production. Often in offshore production, there are unplanned shut-ins that could lead to increased operational hazards. Despite the practical importance, few studies have addressed the hydrate plugging mechanisms during transient operation.

To investigate hydrate transportability in transient operation, tests were performed using an industrial-scale flowloop (3.8 inch in internal diameter and 295 feet in length) with crude oil for a range of water fractions (30–90 vol.%), at 5 wt.% salinity, and across a range of mixture velocities (2.4 -9.4 ft/s). For the tests performed at 50 vol.% water cut (WC) at 5.7 ft/s, the pressure drop and mass flow rate measurements suggest that the transient (or restart, RS) test could result in an earlier onset of hydrate bedding, occurring approximately twice as fast, and may lead to a higher relative pressure drop when compared to the continuous pumping (CP) test. These flowloop experiments suggest that for the RS tests, rapid hydrate formation and agglomeration followed by the water-in-oil (W/O) emulsion destabilization could cause an early increase in pressure drop (and higher operational risks) compared with the CP tests. The tests using an anti-agglomerant (AA) additive (at 1 and 2 vol.%) were performed at 50 vol.% water fraction for all mixture velocities. The tests with an AA indicate that 2 vol. % AA (at all velocities) could prevent hydrate plugging and maintain a slurry flow at 50 vol. % WC for both RS and CP tests. The tests with 1 vol.% AA (at 5.7 ft/s for 50 vol.% WC) show larger fluctuations in pressure drop in the RS test compared to CP tests performed under similar conditions. It is suggested that an improved understanding of hydrate plugging mechanisms during transient operations could help in the development of advanced strategies to manage hydrate transportation in typical subsea operations, particularly involving unplanned shut-ins and subsequent restarts.
Workflow to Evaluate Wax Deposition Risk Along Subsea Production Systems
Authors: Coronado O. , Kak A.
Published: April 2017

The potential for wax formation and deposition along subsea production systems pose a severe flow assurance risk. During early stages of a field development (when information is limited), the risk needs to be quantified in order to develop preliminary mitigation strategies. This paper presents a workflow that can be used to evaluate the wax deposition risk for any field development by integrating the available wax laboratory data with simulation tools.

The proposed workflow consists of tuning fluids models, benchmarking the wax deposition models (using the measured wax deposition rates), and conducting wax deposition simulations with the benchmarked models. Deposition mechanisms such as diffusion and shear stripping can be adjusted during the benchmarking step.

The wax deposition predictions can be used to evaluate various design options during development stage and for devising operating strategies throughout the life of the field (such as insulation requirements, injection of paraffin inhibitor, pigging operations, etc.). In field developments where thermal management is a challenge and wax deposition cannot be avoided, a structured approach toward wax modeling is crucial to make the right engineering decisions.

Wax laboratory measurements alone are not sufficient to quantify the wax deposition risk because of the uncertainties associated with the laboratory results and the difficulties to reproduce the actual field production conditions. When comparing the results obtained with the default wax model coefficients (no benchmarking) and the benchmarked models, the predictions are significantly different. Similar deviations are observed with the predictions based on wax data reported by different laboratories (for the same fluid sample). The overall design and operating strategy are highly dependent on wax deposition rates. Therefore, the discrepancies between the wax data measured by different laboratories suggest the need to standardize the test protocols.

The main objective of the proposed workflow is to try to bridge the gap between the laboratory wax test measurements and transient flow assurance modeling. The ultimate goal is to reflect the wax characteristics in the large scale field operations. This workflow is intended to facilitate the communications between engineering design teams and flow assurance laboratories; because more representative data are needed to better predict the wax problem throughout the field life.
Integrating Decision Support Models with Market and Non-Market Value Attributes for Platform Decommissioning: An Effective Approach for Resolving the Challenges Inherent at the Nexus of Science and Policy
Authors: McCann B. M. , Henrion M. , Bernstein B. , Haddad R. I.
Published: April 2017

Many critical factors must be considered in determining the most feasible and appropriate options for decommissioning offshore oil and gas platforms, including alternatives from complete removal to partial removal with artificial reefing. Using financial-based cost/benefit analysis to evaluate decommissioning options neglects the complexities inherent in a successful platform decommissioning process, which includes non-monetary values such as the production of greenhouse gasses and the gains and/or losses of ecological services due to partial or complete removal.

Multi-attribute decision analysis provides technically defensible consideration of both market and non-market values associated with the outcomes of rig decommissioning while allowing stakeholders to clearly and transparently investigate and evaluate the nexus between financial considerations and other factors (e.g., air/water quality, biological productivity, ocean access) that drive public policy. In California, the PLATFORM decision support model was a key component in helping a diverse group of stakeholders reach consensus on the preferred policy of partial removal and artificial reefing, which ultimately resulted in the creation of a public regulatory framework for rig decommissioning—the California Marine Resources Legacy Act.

We describe how to use multi-variable decision analysis to facilitate offshore oil and gas platform decommissioning. We implemented decision analysis as a software tool (PLATFORM) to clarify and evaluate decommissioning alternatives against a comprehensive set of objectives, including both market and non-market values. Decommissioning options selected for in-depth analysis were complete platform removal and partial removal to 85 feet below the water line, with the remaining structure converted to an artificial reef. PLATFORM performed key analyses of the impacts of each option (e.g., on costs, fishery production, air emissions). The analysis found a near-consensus of stakeholders in support of partial removal and a "rigs-to-reefs" program. Decision support models, such as PLATFORM, are readily adaptable to support regulatory decision-making and alternatives analysis for decommissioning worldwide, including the North Sea, Australia, and Asia.
Low-Adhesion Coatings as a Novel Gas Hydrate Mitigation Strategy
Authors: Brown Erika , Hu Sijia , Wang Shenglong , Wells Jon , Nakatsuka Matthew , Veedu Vinod , Koh Carolyn
Published: April 2017

Gas hydrates typically form at high pressure and low temperature conditions where water and small gas molecules exist in sufficient concentrations. When these thermodynamic (temperature, pressure, composition) conditions are fulfilled in oil and gas production flowlines, gas hydrate plugs can form and greatly restrict flow, which can lead to severe safety, economic, and environmental consequences. One potential strategy towards hydrate management involves allowing hydrates to form, but mitigating their tendency to deposit on the flowline walls by deploying a low adhesion, protective surface coating on the interior of the flowline. Without deposition (and agglomeration), the hydrate slurry can be transported until it exits the thermodynamically stable region without impeding production.

In this study, two coatings were produced and evaluated to determine their effect on hydrate adhesion onto carbon steel surfaces. The coatings used in this study were a super-hydrophobic, anti-icing coating and an omniphobic and corrosion resistant coating. The coatings were applied to substrates in both pristine (no corrosion) and pre-corroded conditions, where the coupon was exposed to a 5 wt.% salt solution prior to coating. Hydrate/surface interactions were studied using micromechanical adhesion force measurements in both liquid and gas bulk phases. A model sII cyclopentane hydrate (forming the same hydrate structure that is typically formed in subsea flowlines) was utilized at atmospheric pressure for the liquid phase measurements, while the high pressure measurements were performed using methane/ethane mixed gas hydrate (also sII). Rocking cell tests were also conducted to evaluate the coatings at high pressure under dynamic conditions using methane/ethane mixed gas hydrates and a liquid loading of 70 vol.% (water + oil).

It was observed that applying the coating to a surface was effective at reducing the adhesive forces between hydrate particles and steel surfaces, especially in the presence of corrosion. This held for both the low and high pressure micromechanical force adhesion tests. Rocking cell tests additionally revealed a significant reduction in time to hydrate deposition at low water content under dynamic conditions. The initial results from these three apparatuses suggest that utilizing these coatings may be an effective hydrate mitigation strategy at low water content, and in flowlines which have undergone significant internal corrosion, but more research is necessary to characterize the hydrate/surface interaction when a higher water content is present.
A Review of Hydrate Formation for Partially Dispersed Systems in Multiphase Flow Conditions and the Detection of Hydrate Deposits
Authors: Majid Ahmad A. A. , Grasso Giovanny , Creek Jefferson L. , Qin Hao , Charlton Thomas , Estanga Douglas , Rivero Mayela , Bbosa Ben , Waturuocha Amaka , Volk Mike , Koh Carolyn A.
Published: April 2017

The formation of gas hydrates in subsea oil and gas flowlines is a major concern since this can cause production interruptions, and environmental and safety problems. Under gas hydrate formation conditions, hydrates can create flow restrictions, that may then lead to plugging of the flowline. The risks associated with hydrate formation in subsea flowlines increases significantly as the reservoir matures and the amount of produced water increases. The oil and gas industry recognizes the need for the investigation, development and implementation of better hydrate management strategies covering the gaps in current practices.

In helping to develop better hydrate management strategies, hydrate formation in partially dispersed multiphase flow conditions were previously investigated using a high pressure industrial-scale flowloop (Vijayamohan et al. 2016). In our recent tests using the same flowloop, the effect of hydrate volume percent on the pressure drop of the system was evaluated. The amount of hydrate formed in the system was limited by systematically controlling system temperature and gas available for hydrate formation.

In recent flowloop tests, it was also hypothesized that hydrate deposition on the pipe surface can contribute significantly to a rapid increase in the pressure drop (Grasso 2015). As such, an investigation into hydrate deposition mechanisms and their detection was performed. Deposition mechanisms were investigated using a high pressure lab-scale flowloop (Grasso 2015). In this part of the work, hydrate deposition mechanisms were evaluated by varying parameters such as liquid loading, water cut, subcooling, and liquid/gas phase velocity. The results from these laboratory-scale investigations show that both liquid and gas phase velocities have a high impact on the amount of hydrate formed in this system.

The results from the investigations presented in this paper provide new insights into hydrate formation and deposition mechanisms. It is anticipated that such investigations can lead to new possibilities for more advanced hydrate management strategies for the flow assurance community.
Gas Hydrate Formation in High Water Content Systems Containing Anti-Agglomerat and Salt
Authors: A Majid Ahmad A , Braniff Martin , Creek Jefferson , Koh Carolyn A , Kusinski Greg , Gomes Joseph
Published: April 2017

In this work, the effects of an anti-agglomerant (AA) and salt (sodium chloride, NaCl) on water-in-oil (w/o) emulsion stability with and without the presence of gas hydrates is presented. The characteristics of gas hydrate formation and the hydrate slurry transportability were determined using a high pressure autoclave cell, with continuous mixing. The stability of the emulsions was independently measured by performing bottle tests, where the stability of the emulsion was determined by observing any evidence phase coalescence for a period of one week after emulsification. In addition, the stability of the emulsion with hydrate formation and dissociation was tested using high pressure differential scanning calorimetry (DSC). From high pressure autoclave studies, it was observed that the formation of a stable emulsion was shown to with the subject oils led to transportable hydrate slurries. Note however, it was observed that for this specific oil at 75 vol.% water cut and the addition of both AA and salt, a highly viscous mousse with viscosity of ~100 000 cP formed when the emulsion was saturated with methane gas at 950 psia and 20 °C. Even without the presence of hydrate, the formation of a highly viscous mousse may not be desirable in the field production system since it could render the system inoperable (effectively plugged).

Interestingly, it was observed that the highly viscous mousse produced dispersed slurry of hydrates upon hydrate formation. Based on the autoclave studies, the absolute motor current (which indicates the relative viscosity of the system) at maximum amount of hydrate is 2 times lower of its original viscosity.