bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparative Economic and Technical Evaluation of AG FLNG with One vs. Two Trains of Liquefaction Cycles
Authors: Nguyen Xuan Chi , Regt Ceed de , Mihaeye Komla , Kim Mungyu , Kim Munsung , Yoo Donghoon , Lee Charles , Lee Daniel , Kumar Balesh , Kim Junghoon
Published: April 2017

This study presents a methodology based on the Life Cycle Cost (LCC) to define the optimum yearly Liquefied Natural Gas (LNG) production of a Floating LNG (FLNG) based on the proven gas reserve of an Associated Gas (AG) Field.

This methodology developed specifically for these specific FLNG Concepts can be extrapolated to other type of FLNGs such as full-fledged FLNGs.

For this purpose, several FLNG concepts of Associated Gas (AG) FLNGs are compared. A previous study presented to the OMAE under OMAE2016 – 55152 is used to develop variations based on the same concept with one liquefaction train and two liquefaction trains for both nitrogen refrigerant and Single Mixed Refrigerant (SMR) concepts. These concepts are defined as follows: Case A-1: 1 liquefaction train - nitrogen used as refrigerantCase A-2: 2 liquefaction trains - nitrogen used as refrigerantCase B-1: 1 liquefaction train - SMR used as refrigerantCase B-2: 2 liquefaction trains - SMR used as refrigerant

These FLNG concepts are designed to monetize associated gas from existing offshore fields located within convenient distance of an existing LNG plant or port with LNG storage facility.

The economic model assesses the LCC using Net Present Value (NPV) for both cases. The LCC and Internal Rate of Return (IRR) show that each concept has its own merits depending on gas reserve and production profile. The study provides details on areas of applications for each FLNG concept and how it is influenced by key parameters such as reserve size, production profile, discount rate, estimation accuracy, and development phase.

Based on this, the study provides guidance for the selection of the optimum LNG production capacity for an associated gas production profile with reserves from 0.5 TCF to 1.5 TCF.
Impact of H2S Consumption and Anti-H2S Layer on Flexible Pipe Design
Authors: Vidigal J. , Taravel-Condat C. , Meira J. , de La Tour P.
Published: April 2017

The trend for deep water flexible pipes, leading to high mechanical loads, requires using high strength steel grades which may present limitations in annulus environment. To address this issue, two R&D programs have been conducted: the first one consisted to calculate more realistic H2S content in the annulus considering its consumption by corrosion process. The second one consisted in using a polymeric layer which prevents H2S permeation from the bore to the annulus.

Realistic case studies, representative of the different offshore development regions, originally designed using sour service steel grades with low mechanical resistance, have been optimized considering the H2S consumption by corrosion process in the annulus and the anti-H2S layer to allow the utilization of high strength sweet service steel grades, aiming at a cost reduction. Additionally, the utilization of technologies recently qualified or under development, such as new steel grades with improved mechanical resistance enabled for sour service applications using the two available solutions, is proposed to obtain a further optimization.

Optimized designs are presented for each case study, along with the respective performances against the most relevant flexible pipe failure modes and cost impact. Furthermore, the maximum allowable H2S levels have also been assessed, extending the limits of each solution. By considering the H2S consumption by corrosion process in the annulus, the utilization of high strength sour service steel grades allows to decrease the cross section of the steel layers or the number of armour layers, leading to a weight reduction which is directly converted into cost saving. Regarding the anti-H2S layer, the complete elimination of H2S in the annulus makes possible the use of sweet service steel grades for sour fluid applications, being for extreme sour environments the only feasible solution.

The precise assessment and control of H2S content in the flexible annulus, enable to deliver optimized designs for sour fluid applications with a significant impact on CAPEX and furthermore open frontiers for ultra-deep water even for extremely sour fluid applications.
Tapping into Your Current Data Reserves
Authors: Mowrer Matthew , Roberts Benjamin , Paula Henrique
Published: April 2017

Data analytics and Big Data have revolutionized many industries, especially where minor efficiencies result in significant cost savings. While Big Data is very important, this paper emphasizes use of low cost tools and techniques to provide valuable insight into data that organizations are already collecting.

Organizations spend extensive effort collecting and managing data to support operational and business functions. These functions involve specific stakeholders making specific decisions within a specific timeframe. Within highly-mature functions, data is collected and processed to provide information, knowledge, and insight to its stakeholders; however, these functions are often siloed, limiting the utility (and sometimes visibility) of the data across the organization.

An organization's data is a valuable asset. For limited additional effort, analysts can leverage this asset to provide unique insight. This paper explains tools and techniques that organizations can use to creatively capitalize on untapped potential. Broadly, the approach includes:

Visualizing existing data to improve understanding - In recent years, data visualization software has become much more powerful, inexpensive, and easy to implement for generating and sharing results. Employing intuitive visualization enables analysts to consider multiple dimensions of an issue simultaneously to identify findings and anomalies. Identifying potential applications - By interacting with intuitive data visualizations, analysts can think creatively about use of data beyond its intended uses and posit questions for further exploration. Establishing context within and across datasets – Analysts can define relationships across datasets and analyze them collectively. Correlation analysis across datasets can reveal hidden relationships. Expanding or contracting the analysis time horizon of data can also bring trends to light. Depending on the application, analysts can build data-driven predictive models to simulate various scenarios to improve confidence in decision-making processes.

This approach represents a philosophical change from "Is the data sufficient to answer a given question?" to "What questions can the given data answer?" This approach encourages exploration to reduce the opportunity cost of untapped data. This paper will illustrate this approach through a case studies using publicly-available offshore production and platform data.
Optimization of Nitrogen Liquefaction Cycle for Small/Medium Scale FLNG
Authors: Kim Mungyu , Mihaeye Komla , Min Joonho , Lee Donghun , Park Hyunki , Lee Jonghun , Nguyen Xuan Chi , Regt Cees de , Kim JungHoon , Jang Jungmoon
Published: April 2017

The selection criteria for a liquefaction process for an offshore floating LNG (FLNG) process are different from that for onshore liquefaction plants due to offshore specific considerations like safety requirements, space and weight constraints, and ship motion effects. For a small and medium scale FLNG project suitable for the development of strained gas production and extended oil production, both the Single Mixed Refrigerant (SMR) cycle and the Nitrogen expansion cycle are most widely considered feasible liquefaction process, as they have considerable advantages in terms of space and weight. However compared to SMR, nitrogen as refrigerant has strong additional advantages, even though it has lower thermal efficiency. Nitrogen is nonflammable gas and therefore inherently safer, as the need for flammable refrigerant inventory is eliminated. Also the nitrogen expansion cycle is a reverse Brayton cycle, which has no phase change throughout the refrigeration cycle. This results in a single phase process, which is less prone to reduction in production performance caused by adverse ship motions. Based on the above the nitrogen expansion cycle seems more appropriate for a small and medium scale FLNG.

This paper presents a LNG liquefaction cycle configuration using three stages of nitrogen expansion to improve the efficiency of the conventional nitrogen double expansion cycle, based on a LNG production rate in the range of 1 MTPA. The chosen configuration further optimizes the composite cooling and heating curve of the liquefaction cycle, resulting in higher thermodynamics efficiency. The efficiency of the liquefaction cycle will be improved in order to reduce the interval between the cooling curve of the natural gas and the warming curve of the refrigerant: the closer both curves are, the better the efficiency of the cycle. This optimization is achieved by adjusting the refrigerant operating temperatures and pressures.

The three nitrogen expander liquefaction cycle includes three levels of expansion, each having different temperature and pressure levels: warm, intermediate and cold. This configuration allows the nitrogen warming curve to closely match the cooling curve of the natural gas cooling curve by changing the nitrogen warming curve from two straight lines into multiple intersecting straight lines of different gradient. That is to say, the additional new nitrogen expander generates an additional inflection point within the cold composite curve. As a result, thermodynamic inefficiencies are minimized and power requirements are reduced when compared to the double expansion cycle.

A case study is presented for an open sea associated gas FLNG concept showing a comparison using a liquefaction process based on a two-expander cycle and a three-expander cycle. A Life Cycle Cost (LCC) analysis based on Net Positive Value (NPV) shows an improvement on the project NPV with minor incremental CAPEX.
The Impact of Lubrication on Safety
Authors: Donlon Andrew
Published: April 2017

Maintaining a safe offshore operating environment is becoming increasingly difficult, as producers are pushing their equipment harder to achieve their productivity goals. In this context, maintaining the required safety environment requires a robust lubrication program that can protect equipment from extreme operating conditions and maximize that equipment's availability, thus reducing the need for human-machine interaction (HMI) and enhancing the safety of maintenance personnel.

This paper will provide guidance on how operators can maintain a high standard of operational safety in the face of the ever-increasing complexity and challenging conditions of offshore operating environments. The paper will outline how producers can design a robust lubrication approach - incorporating key lubricant technology considerations and expert technical services to help enhance the reliability and availability of their equipment.

First, the paper will highlight what producers should look for in lubricant formulation. While synthetic lubricants are well understood to be the best performing lubricants, performance among synthetics can vary depending on formulation. And, while some operators may be hesitant to adopt synthetic lubricants due to traditional preferences or cost considerations, this paper will provide a data- based argument for why synthetic lubricants are a must for any best-in-class safety program.

In addition to lubricant technologies, producers must also have the right equipment maintenance processes in place to identify and respond to equipment performance issues before they become a problem. The most important of these services is used oil analysis. This paper will briefly highlight the value of this service and outline specific considerations to help operators optimize their oil analysis programs.

Backed by insights and data from laboratory testing and real-world performance, offshore professionals will be provided with the latest information and best practices they need to further optimize their maintenance program as they work to deliver a best-in-class safety environment for their workers.
Enabling Materials and Corrosion Technologies for Optimizing Offshore Developments
Authors: Wright Eric J.
Published: April 2017

Designing and maintaining systems integrity throughout the life-cycle of oil and gas operations is key to the overall success of these developments. The current industry fiscal environment creates an increased emphasis on meeting this objective with both improved capital efficiency and operating performance. Related to these drivers, materials and fabrication costs represent a high proportion of the capital expenditures of upstream oil and gas developments. In addition, corrosion control, monitoring and inspections related to systems’ integrity represent significant operating expenses. This reality provides real opportunity to positively influence projects’ life-cycle economics by the qualification of improved materials, fabrication and corrosion technologies. An additional incentive is that material and corrosion control performance requirements continually increase because of more demanding designs requiring higher-strength, higher-temperature materials, long-life coatings and highly efficient corrosion inhibitors for carbon steel. In such cases, the technology qualification may be enabling for a project conceptual design or specific component design currently outside common industry practice. There are practical barriers to the qualification and application of new technologies, specifically related to the associated qualification costs and also potential implementation schedule risks. The illustrations discussed demonstrate that careful integration of technology qualification into the overall project lifecycle can address these barriers and enable substantial economic benefits while maintaining high integrity. A key success factor is that the technology should be qualified to commercial standards in terms of availability, reliability and implementation. Illustrative examples are briefly described for oil offloading lines, full wellstream pipelines and well completions that show the important role that technology qualification plays in the success of upstream projects.
Case Study: Fast Track Tieback Using Standardized Retrievable Modules For Subsea Enhanced Production Throughout Field Life
Authors: Donald Ian , Hudson Adam , Bryce Tom
Published: April 2017

This paper describes a case study in the Gulf of Mexico, which demonstrates how new patented flow access technology was successfully used for the first time by an Operator and was one of the contributing factors to the tieback being able to achieve discovery to first oil in 11 months – a record for the Operator.

The paper demonstrates how the Enpro Subsea's Flow Access Modules (FAM) enabled the Operator to use an existing standard stock tree tying back to a spare slot on an existing subsea manifold, by removing intervention engineering for enhanced recovery solutions ‘off the tree’. This decoupling enabled concurrent engineering tasks and therefore de-risked and reduced the critical path of project schedule. As an added benefit, the Operator realized added flexibility and benefits that the FAM technology provides for the asset life of field.

The paper will showcase how, despite the Operator having existing tree and manifold from two different OEM vendors with different flowline connector types, the integration of the flow access hubs at either end of the flowline allowed a range of enhanced production solutions to be fitted at various locations throughout the life of field.

This enhanced production solution gives Operators many operational and commercial benefits due to the flexibility it provides.

In addition to faster delivery and lower cost constraints; the project also required:

Retrievable multiphase metering (with water and sand detection); plus Methanol injection (for potential flow assurance issues); plus Automated flow isolation valve (used for long shutdowns); plus Fluid intervention for flowline hydrate remediation; plus Fluid intervention for reservoir stimulation.

Other enhanced recovery solutions enabled by the flow access technology, but not included in the scope of this case study, include:

Fluid Sampling Multiphase Pumping HIPPs Secondary Well Control.

The paper will showcase how all five solutions were successfully delivered and installed subsea. On the world stage, this parallel flow path technology represents a global opportunity for enhanced production from both brownfield and greenfield assets.

The results in the paper will:

Explain how the flow access technology and intervention hubs were able to reduce risk and length of delivery schedule. Provide a comparison with the traditional flow access methods, and outline the major benefits for industry of this technology. Describe how Operators can gain access to a full suite of enhanced production strategies through the life of field for new and mature assets.
cMIST™: Novel, Compact Dehydration System for Reducing Size and Weight
Authors: Ramkumar Shwetha , Grave Edward J , Larnholm Per-Reidar , Thierens Danny
Published: April 2017

The natural gas industry is increasingly pursuing compact and lower weight processing technology for offshore, onshore, remote, and challenged gas processing. Increased modularity of process equipment and process intensification require innovative solutions. ExxonMobil Upstream Research Company (EMURC) has developed and qualified a new inline dehydration technology meant to replace conventional TEG tower and associated separator vessels to meet pipeline dewpoint specifications. Compact Mass transfer and Inline Separation Technology (cMIST™) achieves this goal with significant reductions in weight and footprint.

The cMIST™ dehydration system relies on state-of-the-art technological advances in contacting and inline separation to achieve pipeline specification dry gas and/or prevent hydrate formation. It includes a novel droplet generator which creates small, well-dispersed droplets with a high surface area for absorption followed by an inline separator. EMURC has completed the technical qualification for the cMIST™ dehydration system and effective December 1st 2016, this system has been exclusively licensed to Sulzer for global deployment in offshore and onshore facilities.

The cMIST™dehydration system was demonstrated using a skid-mounted test unit in the Woodford trend area of Oklahoma, USA at an XTO Energy production facility. It was tested under a range of field conditions to examine the dehydration capacity, operability, and reliability of the technology and it achieved pipeline specification over a range of process conditions and during sustained operation.

The cMIST™ dehydration system enables 50% dehydration system weight reduction and 50 - 80% absorber footprint reduction along with significant capital cost savings. The technology is highly modular to allow for simple transportation into remote, challenged, or offshore environments and provide installation configuration flexibility.
Use of a Cybersecurity Laboratory in Support of the Virtual Vessel Concept to Increase Safety Onboard Marine and Offshore Assets
Authors: Selvam Naveen , Scott Richard , DeWitt Cris
Published: April 2017

Owners and operators of marine and offshore assets must understand what is on "the wire" in their automated and highly-integrated systems. This information allows them to define the transforming functions where virtual data is converted into actionable cybersecurity knowledge. The ABS virtual vessel concept is the computational representation of the data that is sensed, stored, analyzed and transferred as actionable information on a marine or offshore asset. This paper discusses the concept through experiments designed to evaluate assumptions and hypotheses in a purpose-built cybersecurity test laboratory.

Increasing use of integrated control systems onboard the assets and complex integrated technology in the maritime and offshore industry to manage business comes with a higher risk of cyberattacks. These attacks are getting more sophisticated and, in many cases, can have significant impacts on critical areas of operation.

Maritime control system software is not constrained by the same physical laws that predict the physical behavior of equipment and vessels. Software systems behave differently and are evaluated by very different metrics. Because behavioral and security test methods are often conducted on in-service assets, comprehensive testing is impractical and potentially hazardous to perform onboard an asset. Therefore, assessments of cybersecurity solutions and guidelines are performed more on simulated systems in a laboratory environment rather than on actual in-service systems.

ABS is developing cybersecurity "use cases" in which patterns of cybersecurity threats, risks and solutions can be examined, characterized and gauged using field device level information for marine and offshore systems. This research can help the industry understand the nature and risks imposed on virtual vessel computerized elements and inform the development of guidelines and rules to increase the safety and security of real vessels. This paper describes the process of building a cybersecurity lab and research capabilities for marine and offshore assets. Specific projects examine current maritime, government and private sector approaches to research, identify and characterize cybersecurity events in maritime industrial control systems.
Best Practice for Analysis of Polyester Rope Mooring Systems
Authors: Falkenberg Erik , Åhjem Vidar , Yang Limin
Published: April 2017

The objective of the Syrope JIP has been to improve the methods for safe and reliable design of fibre rope mooring systems. Normal, conservative, design practice for polyester rope mooring systems is to use an upper and a lower bound axial stiffness of the polyester. The use of a more advanced, but still manageable design practice allows for a more optimized design.

Only polyester lines have been covered by the work, but the principles are assumed to have a general validity. Extensive testing on change-in-length behavior has been performed on subropes. Testing has covered recommended test procedures from different standards and recommended practices and more realistic load sequences.

Based on test results a conceptual model for the behavior of polyester ropes has been developed. The mean length of a rope depends on the preceding highest mean tension in the rope and the actual tension, including its mean value. The response to wave-frequency and low-frequency loads is described by a dynamic stiffness which increases with the mean load in the line.

Recommended change-in-length testing of subropes is described, and principles for analysis of such tests for identification of parameters in the model are presented. Finally, guidance for use of the model in mooring system analyses is given.
Innovations in a Floating Production System for Optimizing Costs
Authors: Oliveira Allan Carre de , Ruggeri Felipe
Published: April 2017

It will be presented some developments for a ship-shape type floating production system to minimize installation and operating costs for a scenario Polo pre-salt Santos Basin. In that scenario, there are economic advantages using large diameter rigid lines for oil production and also requirements about oil treatment which increases the process plant weight and area at the production unit.

To deal with those new requirements an unconventional concept was developed. The concept is designed to operate with large diameter free standing steel catenary riser connected to a structure that may be disconnected from the hull. The possibility of disconnection allows the assessment of this solution in other harsh environmental scenarios, like hurricanes areas, where being disconnectable is required or an advantage in terms of safety.

The hull form is designed using an optimization process with genetic algorithms that took into account 7 parameters, having analyzed thousands of possibilities in the proposed scenario, focused in minimize steel weight to minimize the platform construction cost. Based on this solution, hydrodynamic analyses were performed to check the interference effects between moonpool and the riser support buoy inside the moonpool.

Based on the optimization results, the advantages and disadvantages of this solution are pointed out at well the estimated cost reduction, which also considers assessments in different scenarios by Monte Carlo approach.
Thriving in a Low-Oil Price Environment - Ursa Asset
Authors: Fairburn Mike , Henson Troy
Published: April 2017

Objectives/Scope

This paper describes a three-year performance improvement journey of Ursa, a Shell DeepWater Tension Leg Platform (TLP) in the Gulf of Mexico, from 2014-2016. The paper will describe the starting point, the foundation for change that was built with leadership, organizational engagement, designing a change program and the process of delivering that program to establish new levels of performance within the organization. The organizational scope includes asset leadership, offshore Facilities/Production staff and on-shore support staff.

Methods/Procedures/Process

The improvement journey involved understanding and increasing organizational capability, recurring reviews of the asset's strengths and performance gaps, selection of improvement initiatives that matter, timely execution of improvements and ensuring that planned results were sustained.

Some of the ways Ursa changed the way it works include:

Ursa's learnings are applicable to any capital-intensive organization.

Results/Observations/Conclusions

Like most organizations, Ursa had been subject to many improvement efforts before the time covered by this paper. However, the results of these improvement efforts had been mixed and were often not sustainable. This led to a predictable attitude in the organization that these "flavor of the month" improvements would come and go, without much change to daily operations.

The approach taken by the Ursa team changed that. By systematically improving how each person thought about, executed and validated their work, performance was materially improved. This took Ursa from a well-performing organization content with its output, to a truly world-class team that continually looks for the best ways to improve and optimize performance.

Improvements realized:

These improvements enabled Ursa to thrive in this low-oil price environment, lead in profitability versus peers, and become a model for TLP operations within Shell.

Novel/Additive Information

Most companies understand how to cut cost/activity…but you can't cut your way to an engaged workforce with more effective work execution. Ursa has found a way to engage its team to achieve dramatic results in this highly challenging environment. Read on to see how you can too.
Cost Effective Offshore Concepts - Compact Semi-Submersible - A New Concept of Windfarm Service Operations Vessel
Authors: Grace Lee , Lee Won-Ho
Published: April 2017

This paper details the process undertaken for the design of a novel windfarm Service Operations Vessel (SOV).

This paper covers:

An offshore wind energy sector overview Characteristics of the Compact Semi-Submersible (CSS) platform Design and analyses required for concept SOV validation Design challenges, risks and solutions Approval in Principle (AiP) process with class

The information within this paper will be useful to design companies moving away from their typical knowledge base and vessel portfolio. Venturing into a new market sector or new type of vessel always presents risk. This early stage AiP process reduces that risk before a project and design gains too much momentum to be able to incorporate regulatory updates or interpretations at a later stage. Challenging area's based on the designer's and classification society's experience are discussed with proposed solutions as well as areas to focus on and develop with up and coming rule updates, guides and interpretations.

The CSS platform is classed as a Mobile Offshore Unit/Mobile Offshore Drill Unit (MOU/MODU) due to previous versions of the design being classed in such a manner for the offshore Oil and Gas sector. Applying a vessel designed for this sector to a new but similar sector which requires alternate regulations calls for clear interpretations and rule compliance. The relevance and applicability of more recent class notations such as "Ship Shaped Unit" are still being investigated and analyzed. This could allow for more relevant and typical vessel like criteria to be applied to the platform when transiting to and from shore and between turbines but then allows for MODU like notations to remain when gangway connected or operating on station and in Dynamic Positioning (DP) mode. HAZID workshops are highly recommended for novel concepts such as this to identify and eliminate "show stoppers" during initial design stages. Time spent undertaking such reviews at this stage pay for themselves in a reduction in design rework during class, functional and production design stages.

The relatively immature and rapidly evolving nature of this industry sector leads to many challenges for all involved and the willingness and cooperation that classification societies play during early stage designs to provide the necessary guidance to safely meet the developing market segments is critical. Offshore Oil and Gas regulations become the founding basis for many novel offshore designs but are not always entirely appropriate because the mechanical, structural, stability, safety and habitability requirements differ in many ways. The AiP process undertaken between designer and classification society for this project highlighted many of these areas and highlighted areas in which rules require development and careful interpretation.
Pushing Conventional Boundaries of Hydrate Management in a Dry Tree Facility
Authors: Kurup Anjushri S. , Hernandez Oris , Idstein Timothy , Zamora Chris A. , Greenly Leah , Anderson Joseph
Published: April 2017

In the oil and gas production industry, it is well known that formation of hydrate blockages can cause substantial economic impact in terms of deferred production and the costs of remediation. Considering these financial implications and to avoid any potential safety concerns during a hydrate remediation, most often operating companies design and operate fields on a hydrate management philosophy of complete avoidance of hydrate formation. In the last few years, however, a shift in the hydrate management philosophy is being observed as discussed in the publications of Creek et al., 2011 and Kinnari et al., 2015, to cite a few. Due to the developments shifting towards more extreme environments, hydrate management philosophy is shifting from complete avoidance to risk management.

This paper discusses the evolution of hydrate management philosophy of a dry tree facility in the Gulf of Mexico. During steady state production, the fluids flow at temperatures outside the hydrate envelope. The hydrate management strategy following a shutdown is to displace (bullhead) the riser tubing with dead oil within the cooldown time (time required for the fluids to enter hydrate forming conditions after a shutdown). However, due to the dry tree configuration, low liquid rates and insulation performance, the cooldown time is short for these high water cut wells. Using gas lift to boost production further decreases the predicted cooldown time to less than an hour making it operationally difficult to complete hydrate safe out measures within the design cooldown time. A few tests conducted in the field to identify a realistic time available after shutdown, along with a few historical instances during which the hydrate safe out measures could not be completed within the cooldown time, have indicated that there exists a range of water cut (WC) and GOR (Gas to oil ratio) within which the system was restarted without a hydrate blockage. This paper describes how a combination of industry standard predictive tools coupled with field observations is shaping the hydrate management philosophy of this field, by operating within conditions that can form hydrates but do not lead to blockage. The paper also describes two hydrate blockage instances that occurred when the operating conditions were outside the identified hydrate blockage limit reinforcing that the WC and GOR of the fluids have a strong influence on the hydrate blockage risk.
Mitigation of Hydrates Using Continuous KHI Injection in Deepwater GoM
Authors: Swank L. , Kapadia K. P. , Webber P. A. , Jones R.
Published: April 2017

Anadarko operates a subsea tieback well in 3,500 ft of water depth that currently produces 525 bbl/d of water, 250 bbl/d of condensate, and 25 mmscf/d through an uninsulated flowline and riser. The subsea flowing pressure and temperature are within hydrate conditions and hence, continuous methanol injection is used to mitigate hydrates using thermodynamic inhibition. With an increase in water production forecasted, higher injection of methanol was required. However, existing chemical injection capabilities were limited and could not accommodate the forecasted increase in water production. Also, high methanol usage resulted in the produced oil on the platform being contaminated with methanol. With a methanol in crude (MIC) limitation of 50 ppm for the export pipeline, a reduction in methanol usage was required.

Based on the modeled flowing conditions for the well, it was determined that anti-agglomerate hydrate inhibition was not feasible because of a lack of hydrocarbon liquid phase at the point of injection subsea. Lab testing and qualification of a kinetic hydrate inhibitor (KHI) was pursued. Laboratory testing was completed for selection of KHI to be co-injected with methanol while minimizing the impact to produced water quality. The details of the change from methanol to KHI and methanol co-injection is described in this paper along with the field optimization.

The initial methanol reduction strategy called for continuous injection of methanol at approximately 20-23%vol to water of the well. With the application of the co-injection process, the methanol injection volume was slowly stepped down while maintaining the same KHI treat rate, injected at 5.1%vol of methanol. Lab testing from a 3rd party who provided the KHI, indicated the lowest possible treat rate of methanol at 18% to water. Once 18% methanol injection was reached in the field and successful, operations re-evaluated and opted to continue optimization of the methanol-KHI dosage rate. Throughout the study, water production of the well from 480 bbl/d of water to 525 bbl/d of water, there was further need for reduction. Currently with the addition of KHI the well is operating at 7.5% methanol injection to water production, about a 50% reduction in methanol volume. Additionally, methanol in crude (MIC) concentration has reduced significantly in the export oil with the reduction of methanol injection.

By increasing the KHI treat rate, there can be a greater reduction of methanol injection to the system and a lower concentration of methanol in the crude. High volumes of methanol in the export line could result in the pipeline shutting in the platform and subsequent down time for the operator. The combination of KHI with methanol was successful in significantly reducing methanol (>50%), proven to be cost-effective, enables reduced methanol injection requirements.
New Wireless Acoustic Network Provides Real-Time Downhole Data During Completion, Casing and Cementing Operations
Authors: Hawthorn Andy , Aguilar Sergio
Published: April 2017

The drilling world has benefitted immensely in the last 20 years from real-time data during on bottom time. Huge advances in safety, efficiency and productivity have come with directional control and geosteering data being transferred back to surface. As wells have become more complex, particularly in the deepwater environment then the actual on bottom drilling time has reduced to less than 15% of total rig time (Blacklaw: SPE GCS Annual Drilling Symposium. April, 2016). The casing and liner running, cementing and completion installation related activities have, however, not had those same benfits. They instead have had to rely on surface measurements and modeling. As wells have become more complex and windows of operations tighter there are multiple case histories where these models and surface measurements are significantly diverging from what is actually happening downhole.
Accelerated Innovation as the Great Enabler for Well Completions - Tools for Cheaper, Safer and Faster Ways of Completing Wells
Authors: Ganguly Partha
Published: April 2017

Technology innovation has played a great role in oilfield by continuously (a) increasing recoverable reserves, (b) decreasing production cost per barrel of oil equivalent (BOE), and (c) making operations safer. The current paper will focus on some of the game-changing innovations and their impact on operational cost and complexity. In Well Completions arena, a significant number of innovative technologies and processes have been developed in the past few years. These include sealing technologies for high-pressure, high-temperature wells that makes production from these wells possible; high-expansion packers for open-hole completions; erosion and corrosion resistant sand screen media that can be easily assembled on the base pipe and retain torque and tension requirements; and autonomous ICDs that can sense and delay water production.

The recent dramatic downturn in oil prices has further accentuated the need for high impact innovation. Additionally, a significant reduction in the time-to-market of new technologies is a competitive advantage. Such an accelerated process merits special considerations, including development of technology processes to assess functional risk in an accelerated manner. This has been done using extensive simulation work (at system as well as sub-system level) in combination with novel experimentation to validate the models. Such model-based development has led to significantly faster convergence of the design and experimentation cycle, as compared to the previous approaches. Additionally, organizational practices (including customer alignments) to enhance innovation success through lean processes also need to be considered.
Comprehensive Experiments and Modelling Reduces Uncertainties in Liquid Management for the Tanzania Gas Project
Authors: Biberg D. , Kjølaas J. , Staff G. , Vanvik T. , Nossen J. , Lawrence C. , Holm H.
Published: April 2017

The Tanzania Gas Project aims to exploit reserves located offshore from Tanzania in East Africa. The project faces challenges in the management of liquid content due to deep waters, rough seabed terrain, long transport lines to shore, relatively steep inclinations, and very dry reservoir fluids. The narrow operational envelope associated with the water depth underlines the importance of accurate flow simulations for design and production. In addition, the low liquid loading conditions are expected to result in substantial liquid accumulation in the upwardly inclined sections of the pipeline for low production rates. A large-scale experimental campaign was launched to reduce the uncertainty in the field development. A novel experimental "screening technique", allowed for the sampling of an unprecedented number of flow rate combinations corresponding to the onset of liquid accumulation. Diameter scaling was addressed by conducting similar experiments in 8- and 12-in. pipes. Froude number similarity was utilized for scale-up and to assess model predictions for field conditions. The data confirmed That the flow model captures the correct physics, and allowed for fine tuning. The updated model was applied in an uncertainty analysis for the Tanzania field, based on a large number of combinations of key input and flow model parameters, sampled from estimated uncertainty distributions. Simulation results for gas production rate, minimum turndown point, etc. were determined as probability distributions. The effort to quantify and reduce uncertainty has been very successful. Engagement of the operating company with experimental researchers, model developers, and software suppliers greatly increased the understanding of the physics and diameter scaling of low liquid loading flows, significantly reducing the uncertainty for gas condensate field developments.
Advanced Petrophysical Evaluation of a Low-Resistivity Laminated Shaly Sand Formation Showed Significant Increase in Reserves Calculations
Authors: Kukharchuk Alisa , XiaoXuan An , Doss Eric
Published: April 2017

Reserve estimation of low-resistivity, low-contrast, laminated shaly sand formations from conventional logging tools often yield inaccurate results of the true potential of the reservoir. A productive zone with horizontal resistivity of 1 Ohm-m can easily be interpreted as wet and therefore overlooked. The resistivity suppression is caused by a lack of conventional tool resolution and the presence of conductive shale lamina. This paper will describe advanced techniques for effective evaluation of the low-resistivity laminated shaly sand sequences.

To accurately identify and quantify these thinly laminated sands, we will detail a method to acquire the necessary data for proper reserve calculation with examples from a well in the Gulf of Mexico. The study well has a deep-water distal turbidite depositional environment, and contains significant intervals of thinly-bedded sands and shales. The sedimentary facies appeared to be different to offset wells because of separation by a large fault. This geological setting caused an expected zone of interest to have a very low apparent resistivity and brought a lot of uncertainty about hydrocarbon potential of the formation. To provide a thorough appraisal, a suite of most beneficial for such environment advanced wireline measurements were acquired, which were combined with core analysis and conventional logs for an accurate evaluation of thin sand layers.

This integrated approach improved net pay calculations by 80% when compared to the conventional petrophysical analysis, allowing the operator to make some key adjustments in the completion program. The proof of the laminated formation having hydrocarbon potential from the integrated petrophysical analysis was confirmed by the production data. Multiple 24-hour flow tests confirmed oil and gas production with an inconsequential amount of water.
Effect of Coupling of Mooring and Riser Systems and FPSO Roll motions on the Design of Flexible Risers
Authors: Rezende Flavia , Vivas Laiz , Carré Allan
Published: April 2017

For the development of the new frontiers in Brazil, spread moored FPSOs with a large number of flexible risers connected to one board of the unit are considered. Due to the large water depth and severe environmental conditions, the design of the flexible risers is challenging and the roll motions of the FPSO are a key parameter. The roll motions may induce large vertical displacements at the top of the risers which affect the ultimate strength of the flexible pipe as well as fatigue of end- fittings. Moreover, the vertical motions and accelerations may induce compression of the riser which could lead to exceedance of allowable curvature limit. The common practice for estimation of FPSO roll motions is to consider the unit in the free floating condition, without the presence of mooring lines and risers. The resulting motions are then imposed at the top of the risers in a decoupled way. Ideally, a fully coupled analysis should be performed in time domain in order to take into account the dynamics of the floater and lines systems simultaneously as well as the nonlinearity involved. However, as this type of analysis is very time consuming, an alternative methodology is proposed, which enables to consider the effects of coupling at early design phase at a reasonable timeframe. This methodology consists in performing preliminary numerical tests (forced motions) in order to obtain the effects of additional stiffness, added inertia and damping originated by the mooring lines and risers to be included in a decoupled motion analysis in the frequency domain. In this study we consider the example of a spread moored system in deep water depth designed for operating in Brazilian conditions. In this case it is observed that the coupling effects are very important, mainly for intermediate and shallow drafts of the unit. In particular, the lines (mooring and risers) may significantly contribute to damp the roll motions. As a consequence, the top tensions in the flexible pipes would be lowered comparing to the results of usual decoupled analysis.
Applying Risk Management Principles to the CVA Process in Offshore Wind Farm Projects
Authors: Adams Thomas G. , Byars Rain
Published: April 2017

The Certified Verification Agent (CVA) role has been defined by the US Bureau of Ocean Energy Management (BOEM) for offshore wind farms construction in Federal waters, and a similar CVA role has been adopted by certain states, such as Rhode Island, who have projects being constructed in state waters. The CVA plays a critical role in assuring the compliance of the offshore wind farm project with the applicable codes, standards, regulations, and plans that govern the design, construction, commissioning and operation of the project. A mature project certification process exists in Europe following the IEC standard, and there are some important differences between that and the CVA role defined by the relevant federal and state regulations in the US market. Risk management principles can help to balance the CVA effort while managing the most important risks on the project and achieving a high confidence level in overall project compliance and quality. These include techniques such as identifying critical design, manufacturing, and installation tasks, developing appropriate sampling plans for inspection, implementing comprehensive documentation review processes, and employing contingency plans for different outcomes and findings.
The Role Of Standardisation And Modularization In Reducing The Cost Of Subsea Electrical Connectors
Authors: Plant Chris
Published: April 2017

Wet mate electrical connectors are a key technology for the deepwater industry, and can be a significant proportion of the cost of a subsea processing project. To operate sustainably in a low value oil market, manufacturers of subsea electrical connectors must change from their current project driven, custom product approach. Cornerstones of the new approach to the current market must be standardisation and modularization.

This paper will focus on the challenges posed in designing and qualifying a connector system to meet a cross-industry specification, e.g. SEPS SP-1001 (soon to be an IEEE/IEC specification). It will focus on the difficulties in finding a common interpretation of a specification, designing in complete compliance with a cross-industry specification, and include detail of the planning and execution of on-going qualification programs, which are being run in accordance with cross-industry controls (fibre-optic and electrical) and power specifications.

We will examine the different ways in which a connector specification can be interpreted and how the interpretation drives the connector design, test arrangement design, and cost. This interpretation is particularly important when examining the cost of a qualification program and associated equipment, with costs for specialist qualification equipment contributing significantly to the cost of new product development.

Modularization is also a key enabler for cost reduction, allowing the same connector family to be used for multiple applications with only configuration, rather than project or application specific redesign. We will focus on the difficulties found when trying to identify a number of industry requirements which can be combined into a specific product, for example, subsea power distribution, long-step out, subsea compression, and direct electrical heating.

The focus on this paper will be about presenting real-world experience of design and qualification of connectors based on three case studies, for subsea power distribution, long step out electrical controls, and long step out fibre controls.