bluuebunny/crossref_metadata_2025_split huggingface dataset:
Holistic Production Enhancement for Life of Field
Authors: Avery Mike , Greenaway Robert , Bridge Christopher , Rice Phillip , Mcilroy Thomas , Giraud Charlotte 
Published: April 2020

Abstract
This paper summarizes enabling technologies that operators can utilize when planning their field lifecycles, from development and construction through to decommissioning. By approaching field development in a holistic manner, it is possible to minimize total expenditure (TOTEX; the sum of both capital and operational expenditures), whilst also maximizing return on investment and hydrocarbon recovery.
With long-term regulatory compliance and production enhancement in mind, early introduction of flexibility into a subsea field infrastructure can enable simplified well or equipment access for common life of field activities, such as erosion sensor replacement. The resulting systems also permit execution of appropriate interventions by utilizing modest and therefore lower cost multi-service vessels (MSV) in place of larger multi-functional rigs at a premium.
In the following sections, eight different examples of various subsea production problems are presented, with an overview of how they were successfully resolved. These examples serve to demonstrate that the technologies required to deliver advanced production enhancement solutions are sufficiently mature. The paper concludes by demonstrating how more robust planning and provision for flexibility within subsea production system (SPS) design can lead to more rapid resolution and improved financial returns. Supporting these examples, discussion is provided on how digital analysis and hydraulic treatments can be used to help provide early identification and resolution of issues, thereby themselves acting as means of ultimately achieving production enhancement.
By adopting the approaches outlined within this paper, a step-change in production performance is within reach. Subsea systems designed for life of field may include digital technologies to perform on-going advisory services, live fluid sampling capability to assess production performance, and flexible architectures with access points. The optimization of on-going production and necessary intervention can drive informed operational decisions and continual optimization of the field.
The results include a reduction in operational risk exposure, maximized ultimate oil recovery, and the ability to effectively manage unplanned changes in performance. This forward-looking approach to field development, combined with a high degree of flexibility, is crucial for supporting prudent investment within today's challenging environment.
The Relevance of Annulus Seal Assemblies Qualification for Long-Term Subsea Well Integrity
Authors: Weidlich Marcos Correa , Pereira Gustavo Henrique , De Souza Bruno Sergio Pimentel , Borges Alexandre Thomaz , de Melo Everton , Santos Rodrigo Ossemer 
Published: April 2020

Abstract
The annulus seal assembly is an essential component of the subsea wellhead system, providing hydraulic isolation to other annuli. A failure of that device can lead to a very costly replacement intervention, due to the need of removal of the subsea equipment and production string, or even serious integrity consequences, such as underground blowout or cascade collapse of the casing strings. During the well lifetime, the annulus seal assembly is submitted to various types of loads, depending on the well temperature and the operated pressure of the "A" annulus. The analysis of those loads identified critical moments for the annulus seal assembly, which could exceed the capacity of that device if the proper lock mechanism is not installed, and cyclic loads could further depreciate its capacity. The objective of the present paper is to present a methodology to evaluate the critical loads, failure modes and qualification procedures for long-term well integrity.
Executing Unconventional Coiled Tubing Sand Plugs for Multistage Fracturing Operations in HP/HT Wells
Authors: Singh Ishaan , Saraf Aman , Pathak Akash Ramesh , Bandyopadhyay Bholanath , Dehingia Madhurjya , Wijoseno Danny Aryo , Sharma Lovely , Gondalia Ravi Ramniklal , Jha Amay Kumar , Joshi Vaibhav , Shaik Moulali , Rao Dasari Papa 
Published: April 2020

Coiled tubing (CT) sand plug operations associated with multistage fracturing operations in high-pressure/high-temperature (HP/HT) wells are very challenging, in part because of the small number of such jobs that have been performed worldwide. The wells in "A" field in India have HP/HT formations, with a bottomhole temperature (BHT) of 310°F and a reservoir pressure of 9,000 psi. Although millable bridge plugs are preferred industry-wide, this case illustrates how sand plugs become a suitable alternate solution for multistage stimulation to address space limitations, equipment and completion restrictions, and small tubing sizes, even in challenging downhole conditions. This study provides solutions to operational challenges of low injectivity and completion restrictions, which preclude bullheading and use of conventional bridge plugs. Simulations were sensitized to identify the best solutions for sand settling time, HP/HT conditions, pumping rates, CT speeds, and cleanouts where calcite or scale deposits on sand hinder bottomhole assembly (BHA) penetration.
Best practices are given for sand plug operations in challenging HP/HT environments; those best practices can be applied as a reference to design, prepare, and safely perform CT sand plug jobs in such conditions around the world. To address operational challenges in the cases presented here, the first three stages were bullheaded and the last two (a total 325-m sand plug) were placed using CT. Wireline was run to verify CT sand plug tag at ×200-m measured depth (MD). After the successful refracturing job, the 340-m sand plug was cleaned out, followed by acid spotting and squeeze using CT to rejuvenate the lowest zone. Strict application of the recommendations prevented the occurrence of operational contingencies, such as stuck CT, sand bridging, and settling of sand in surface equipment.
Prelude FLNG Towing, Station-Keeping and Mooring Hook-Up
Authors: Jones Ashley Michael , Clergue Simon , Pedlow Philip Jonathan , Holyst Cyril , Artus Victor , Buck Andrew , Wake Damian , Keij Willem 
Published: April 2020

Prelude FLNG ("Prelude"), the largest offshore floating facility ever built, was constructed in Geoje, South Korea, requiring a 3,200nm ocean tow to its installation location 475km north northeast of Broome, Western Australia. A team of station keeping vessels then took control of Prelude to accurately hold her in position above the pre-laid moorings for mooring hook-up operations.
Planning and executing the tow, station keeping and mooring hook-up operations for mega floaters in remote locations requires precise planning, bespoke solutions to unprecedented challenges, comprehensive testing over a prolonged period and a global team with a diverse skill set. Overcoming key challenges required extensive engineering coupled with state-of-the-art vessel simulations, a bespoke mooring handling system, and full-scale winch wire testing. The result was a safe, successful and efficient operation demonstrating the industry's ability to execute the unprecedented challenges of projects in the search for economic development of remote and challenging reservoirs.
Early Kick Detection from Downhole Measurements: A Novel Method for Reducing the Frequency and Magnitude of Loss-of-Well-Control Events
Authors: Tost Brian Christopher , Rose Kelly , Carney Janine , Aminzadeh Fred , Suhag Anuj 
Published: April 2020

Abstract
Loss-of-well-control (LOWC) events are generally defined as uncontrolled flow of formation or other fluids to either the surface or another subsurface formation. Such events are also known as blowouts. Blowouts can result in the loss of human life, catastrophic damage to ecosystems, and substantial economic losses. Many blowouts start with a "kick event", where the formation pore pressure becomes greater than the wellbore pressure, causing formation fluid to flow into the wellbore and combine with the drilling fluid (i.e., mud). Detecting a kick as early as possible is key to preventing a blowout. Conventional kick detection methods (e.g., monitoring mud pit returns, monitoring wellbore liquid levels) are usually time-consuming, resulting in delays during which the kick may grow in intensity and efforts required to re-establish well control may become more extensive. Some, more sophisticated kick detection techniques use instrumentation that can be costly. In this paper, an alternative, lower-cost, early kick detection method is proposed.
Here a kick detection method is proposed that uses measurements from the instrumentation deployed on the drillstring to provide real-time information on the wellbore. Specifically, bulk density, acoustic (compressional wave) velocity, and electrical resisitivity are considered for use as detection parameters. These fluid mixture (combined formation and drilling fluid) properties as a function of kick fluid volume are estimated. Theoretically, these parameters are found to be sufficiently responsive to be used for kick detection. However, additional work is needed to determine how these parameters respond in experimental or field conditions.
Fully Integrated Subsea Sulfate Removal and Low Salinity Plant for IOR and EOR
Authors: Hegdal Torbjørn , Haruna Samuel , Sveberg Knut 
Published: April 2020

Abstract
The world's first full-scale subsea plant for production of sulphate free or low salinity water for IOR and EOR purposes has been designed, procured, constructed, and commissioned. This has been achieved with the involvement and support of an original equipment manufacturer, the Norwegian Research Council, and several offshore oilfield operators. The full-scale subsea treatment plant has undergone qualification in accordance with API 17N, and this paper shares key design aspects of the plan, operational experience, and the water quality results achieved.
Subsea seawater treatment for water injection has several inherent advantages compared to topside treatment. One significant aspect is the increased flexibility afforded to reservoir engineers in improving effective reservoir management by providing the opportunity to implement any desired water injection capacity, anywhere and anytime. In addition, the ability to provide 'tailor made' water for injection into oil reservoirs is seen as a game changing opportunity for offshore oilfield production companies wishing to produce more, produce faster, and produce cheaper.
The process advantages of the seawater treatment plant being on the seabed allows for a design that is simplified compared to a corresponding topside plant. This system design is explained in the paper and how it translates into improved reliability and availability. The all electric design also has the capabilities to be installed, moved, and reused on the seabed with minimum impact on topside infrastructure.
This paper provides information that has not been presented before about the novel subsea seawater treatment process. It shares commissioning and operational knowledge gained during a six month test period and includes water quality results achieved at progressive points through the treatment plant. The ability to operate a water treatment plant on the seabed necessitates instrumentation and control that provides good condition monitoring of equipment and the ability to check and control water quality. The novel methods that have been employed and tested on this treatment plant are discussed.
The treatment plant has been fully tested and is now available to clients for installation and operation on an offshore field. Lessons learnt are shared along with showing how the treatment design can be used to provide high-quality water on a wide range of field applications at any stage of a field's lifetime.
There are several aspects of the design that reduce the health, safety and environment (HSE) impact of water injection in general, including; lower power consumption (reducing carbon footprint) and no (or significantly reduced) liquid chemical requirement; hence, lower handling exposure for operators.
Decisions, Decisions – FLNG Technology Options for Pretreatment, Liquefaction and Driver Selection
Authors: Tierling Kenneth Shane 
Published: April 2020

Abstract
Floating LNG (FLNG) technologies are being deployed to monetize mid-sized offshore gas reservoirs, avoiding constructing a sub-sea gas pipeline to a land-based LNG facility and export jetty. Containing the processing to an oceanic environment also reduces the impact on indigenous peoples as well as terrestrial flora and fauna. FLNG facilities also have the potential of serving multiple offshore fields over the life of the facility, thereby reducing the minimum size field that can be economically monetized.
Three major decisions for FLNG topsides are pretreatment, liquefaction and driver technology selections, with major impacts on safety, weight, space, maintainability and sensitivity to motion. A fourth decision is selection of a new build hull or LNG carrier revamp. The take-away from this work is an understanding of the tradeoffs inherent in these selections, supporting tailoring an FLNG facility to business constraints.
Cryogenic processing requires pretreatment for removal of water and carbon dioxide to prevent solids formation. The use of brazed or welded aluminum equipment, common in cryogenic processing, also requires the removal of mercury. Candidate pretreatment technologies will be covered with an emphasis on the advantages and drawbacks regarding weight, space, and sensitivity to both tilt and motion.
Offshore liquefaction technologies are often novel and have few or no offshore references. The available offshore liquefaction technologies and Licensors will be presented. Because of the diversity of liquefaction technologies, the technologies will be grouped by refrigerant, and then these liquefaction categorizations will be compared with an emphasis on safety, scale, weight, and sensitivity to motion and efficiency.
Application of mechanical drives for centrifugal compressors in an offshore environment is well-practiced. Given this maturity, types of technologies will be compared on power ratings, availability, maintainability, flexibility and weight, without referring to individual suppliers.
The Application and Comparative Study of Calcined Clay and Nanoclay Mixed Cement Slurries at HPHT Conditions
Authors: Murtaza Mobeen , Rahman Mohammad Kalimur , Al Majed Abdulaziz Abdulla 
Published: April 2020

In oil and gas wells construction, the cement sheath in the annulus between casing and formation plays a critical role throughout the producing life of the oil and gas well. Under elevated conditions of temperature and pressure, set cement changes its physical, chemical and mechanical properties. Sometimes these changes can lead to strength retrogression of cement. Recently, it was found that calcined clay (CC) and nanoclay (NC) significantly improve the hardened cement matrix properties as both materials have pozzolanic properties. Both additives have characteristics such as acid and sulfate resistance, low heat of hydration, low density, low permeability and the formed phases with the higher thermal endurance.
In this study, cement mixes with different percentages (1% & 2%) by weight of cement (BWOC) of calcined clay and nanoclay were investigated and compared with Class G cement slurry. Rheology, fluid loss and compressive strength properties of all cement slurries were measured.Rheological properties were measured at 50°C temperature and atmospheric pressure. The fluid loss test was conducted at 50°C and 1000 psi pressure. The uniaxial compressive strength (UCS) test was conducted for cement samples cured at 121°C temperature and 3000 psi pressure conditions for 24 hours and 5 days in HPHT curing chamber. Microstructural investigations were conducted using SEM analysis of cured samples.
It was observed that addition of nanoclay and calcined clay in Class G cement enhanced the rheological properties of cement slurries. The plastic viscosity increased with an increase in percentages of both additives. Higher values of yield point and plastic viscosity were obtained for calcined clay. In case fluid loss, a reduction in fluid loss was noticed for nanoclay. There was no appreciable change in fluid loss with the addition of calcined clay in mixes. Calcined clay-based cement slurries resulted in robust structure and sustained high compressive strength after exposure to high temperature high-pressure conditions. The nanoclay-based mixesgave higher strength compared to Class G cement slurry but lower than calcined clay. The compositional analysis showed that calcined clay gave low calcium/silica ratio and strong bonded structure.
This study will pave a way for researchers to study further the application of calcined clay in oil and gas cementing and its long-term durability.
A Robotic System Development for Rigless Light Intervention
Authors: Figliuolo Saulo Queiroz , Beal Valter Estevão , Rodamilans Guilherme Bulhosa , Almeida Danilo Araujo , Heredia Laerte Girola , Almeida Cleber Ribeiro , Igino Wellington Passos , Santos Hugo Francisco Lisboa 
Published: April 2020

Abstract
A major concern in offshore production is the well intervention cost and the time taken to perform the operations. These issues relate to the need for a rig or a similar unit to perform those operations. This paper presents the current stage of the development of an autonomous robot for rigless well interventions. The robot enters the well through the Christmas Tree using a special tool. This proposal will allow significant cost reduction by avoiding the need for a rig to do light workover operations in offshore locations. This strategy reduces intervention time since a simpler unit may deploy the robot. Examples of operation performed by the robot are production logging, gas lift valve replacement, sliding sleeve opening and closing and plug insertion or removal. A Simplified Robot allowed evaluating the technical feasibility of this proposal, both theoretically and experimentally. This Simplified Robot allowed evaluating the Traction System, the Energy Storage, and the Positioning Algorithm. After that, the design of the Real Robot started. This system will be modular and adjustable according to the needed operation.
Appomattox Mooring System Lessons Learned
Authors: Liagre Pierre F. , Ang Zhili , Wibner Christopher G. , Aragh Sina H. 
Published: April 2020

This paper presents a multitude of lessons learned during the 5 years spent on the design, manufacturing and delivery of the on- and off-vessel mooring components for the Appomattox semi-submersible.
Appomattox is Shell's newest and largest deepwater oil & gas production asset in the Gulf of Mexico (GoM). It was successfully moored about 260 kilometers Southeast of New Orleans, in June 2018 using a 16-point chain-polyester-chain mooring system. It was the culmination of the work done by a dedicated team of Shell civil-marine engineers, mooring equipment suppliers and an offshore installation contractor. Shortly after completion of mooring lines hook-up operations, the polyester ropes were pre-stretched, and the FPS was moved into position for the start of the Steel Catenary Riser (SCR) system installation. Appomattox started production in May 2019. The mooring equipment has so far been performing as expected.
The delivery of Appomattox mooring components was particularly challenging due to an unusually large number of stringent constraints including: 40-year design life, first application of fairleads with underwater chain stoppers in the GoM to mitigate out-of-plane chain link bending fatigue, polyester rope properties fine-tuned to ensure that installation and in-service requirements are met, stringent inspection oversight to enforce project-specific requirements, Thermal Spray Aluminum (TSA) on portions of the platform chains and novel chain handling equipment and method for mooring lines hook-up operations, just to mention a few. The design of the overall system and management of the mooring equipment vendors was performed using mostly in-house resources.
The paper starts with some general information about the Appomattox development. The three subsequent sections present the mooring system, the delivery team and the overall timeline. The lessons are then organized in sections by mooring component types (on-vessel, polyester ropes, chains, and various connectors). Some reflections on how stakeholders influenced certain characteristics of the mooring components are disseminated throughout the paper. The paper also includes some observations about how the equipment performed in the field even though the lessons learned about the commissioning and offshore installation are left for a separate future paper.
Effect of Best-Estimate Clay P-Y Curves on Performance of Offshore Structures
Authors: Wu Fu , Chen Ching-Hsiang , Litton Richard W. 
Published: April 2020

Abstract
Fixed offshore platform pile foundation design and assessment in the Gulf of Mexico (GOM) has been based on API RP 2A [1] and current (2014) API/ISO RP 2GEO 1st edition [2] recommendations. Over the years, post-hurricane observations of the platform performance in the GOM have shown that these standards tend to underestimate soil lateral stiffness and capacity. Research work has been carried out for years to understand this conservatism and define the best-estimate soil lateral reaction for pile foundation design. These efforts culminated in a proposed draft of API/ISO RP 2GEO 2nd edition, which re-defines the clay soil lateral reaction formulations (p-y curves) for piles under monotonic, cyclic, and fatigue loads.
This paper summarizes a study performed to determine the effect of the new clay soil p-y curves on the structural responses of offshore platforms. In this study, three (3) featured fixed offshore platforms in the GOM were selected as representative structures for structural analysis and comparison. The selected platforms are actual platforms in operation in the GOM. The predicted platform responses from analyses were directly compared with measured and observed platform performance in field, including platform damage in hurricanes.
Analysis results demonstrate that structural models using the soil reaction formulations of the proposed 2GEO 2nd edition (draft), in combination with the best-estimate soil profiles interpreted based on the standard direct simple shear (DSS) tests, adequately predicted the platform responses observed in field.
The clay soil p-y reaction formulations (monotonic, cyclic, and fatigue) proposed for the update of 2GEO, as included in Appendix A, show significant improvement over the formulations in older editions of 2GEO and RP 2A, and are endorsed and recommended for pile foundation design and assessment.
Complete documentation of the study can be found in [3].