bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Cool Down Simplifies Using Dissolvable Materials
Authors: Fripp Michael , Walton Zachary 
Published: April 2018

Abstract
Dissolvable materials are enabling a revolution in the completion and stimulation of wellbores. Effective design of dissolvable fracturing tools, however, needs to account for the substantial cooling effect that arises during pump down and stimulation. The degradation process, degradation time, and material properties change because of the wellbore cool down.
A wellbore cools when fluids are injected into the formation. Temperature profiles are measured with fiber-optic cable and are simulated with numerical models. Both measured and modeled results show that downhole temperatures can be cooled to near surface temperatures. This temperature data is combined with experimental dissolution behavior to show that different dissolution behavior occurs during pump down, setting, wellbore stimulation, and wellbore temperature recovery.
The actual temperature that fracturing tools will experience during their useable life depends on wellbore cool down and can be much less than the static formation temperature. All dissolvable materials have dissolution rates and material properties that are temperature dependent. Some dissolvable plastics will not degrade at lower temperatures. Measured and modeled cool down from hydraulic fracturing are used to show the temperature profile during different operational stages. The greatest temperature cool down occurs while the dissolvable fracturing tool is isolating a zone during the fracture treatment. This temperature cool down also occurs during the only time of the operation in which the fracturing tools are required to maintain a significant differential pressure. The temperature cool-down effect becomes more significant as more zones are fractured and more fluid is injected into the formation. Dissolvable fracturing tools should be designed for the temperature experienced during wellbore cool down rather than the static formation temperature.
Both field data and numerical modeling show that a dynamic temperature estimation is more accurate than static bottomhole temperature (BHT) at predicting the temperature experienced by dissolvable fracturing tools. The cool down of the wellbore is an important design parameter for the materials and construction of dissolvable tools.
Functional Design Specification FDS for MPD Equipment Installation on Deepwater Drillships
Authors: Patil Harshad , Deshpande Kedar , Dietrich Earl , Arnone Maurizio 
Published: April 2018

Defining the specification and moreover the limitations of Managed Pressure Drilling (MPD) equipment installations on Mobile Offshore Drilling Units (MODU’s) could be challenging from a functionality stand point. These challenges mainly arise from a wide range of functional or drilling parameters that these permanent or semi-permanent MPD installations are exposed to. With the ever increasing demand of using MPD, many of the existing and new built MODU’s are getting furnished with MPD equipment. Since the increase in demand of MPD equipment for the offshore market is attributed to the advantages that the MPD systems exhibit, typically for drilling wells that demonstrate narrow drilling margins, the MPD system significantly assist in managing bottomhole pressures, especially to mitigate ballooning, and to manage losses / kicks. Due to the potential exposure of the MPD installation to extreme environments, and to ensure proper utilization of these MPD systems within its design limits, it is necessary to define the Functional Design Specification (FDS) for the MPD equipment installed on MODU’s.
The FDS consists of four major calculation categories for the MPD equipment installations. These are, "surface line frictional pressure loss calculation", the "PRV sizing calculation", the "Riser degassing with MPD equipment as a function of MGS liquid and gas handling capacity" and lastly the "erosion calculation" of the piping that is installed as part of the MPD equipment on MODU’s. The development, methodology and approach of specific calculations that were performed to estimate the functional design specification, encompassing these four categories are illustrated in this paper.
The paper describes the method utilized to estimate friction loss through MPD surface lines based on specific calculations that estimate friction factors as a function of mud rheological properties, pipe geometry, length etc. The results obtained from the developed program to estimate frictional pressure loss in surface lines, were calibrated using fingerprinting data obtained from earlier installations on similar Drillships. Next, the FDS calculation uses the MGS (Mud gas separator) gas and liquid handling capacity to estimate the amount of gas that could be safely circulated out from the riser from above the closed BOP’s, without exceeding the MGS capacities and MPD equipment pressure limitations. The paper explains how the PRV sizing calculations were performed which help in specifying the limiting flowrates that the PRV can handle, as a function of mud weight and pressure differential based on API 521b. Lastly the paper illustrates the estimated erosion calculation based on the maximum flowrates that the MPD system could potentially be exposed to due to drilling and/or any limiting riser degassing events, using DNV recommended practices.
A Cost Reduction Methodology for Offshore Projects
Authors: Nunes G. C. , da Silva A. H. , Esch L. G. 
Published: April 2018

Abstract
Current oil prices have made the offshore exploration of oil reserves a major challenge for oil companies. Standardization and extensive use of chattered units has allowed Petrobras to effectively promote competitiveness, cost reduction and reduced schedules in its projects. As a step forward in its pursue for cost reduction Petrobras has recently looked into Integrated Field Development. This article presents a low cost methodology for the design of production systems.
Experience shows that integration among reservoir, flow assurance, subsea, well design and topsides teams is crucial for achieving a successful project. Besides being pursued for a long time, this integration has only been partially achieved in the industry and cost reduction opportunities have been lost.
This article shows a cost driven methodology that can be used for guidance in the generation and screening of FEL1 alternatives. Metrics for the various parts of the system have been created and integrated in a simulation environment that allows economic analysis of different sorts. In FEL2 the methodology allows, for example, the evaluation of the number and capacity of platforms, the optimal schedule of well construction, the use of flexible or rigid risers, the diameter of production lines and the choice of technologies for handling streams with high CO2 concentration in an integrated way.
A simulation of an oil field shows effective results. In this new methodology a representation of each discipline is developed to allow their integration with the objective of making comparative economic analysis of alternatives.
Integrated Subsea Supplier-Led Solution: A Case Study
Authors: Ligny F. Hurault de , Roberts I. , James D. , Eliseeva E. 
Published: April 2018

Abstract
There is a global trend for integrated subsea alliances to be involved in projects earlier, with a broader scope and in closer collaboration with the operating company. Sometimes, this is achieved by enabling contractors to develop and propose their own field development concept, known as a supplier-led solution (SLS). This paper refers to a case study that demonstrates an effective way to improve project economics.
A benchmark field layout plan was first generated using the customer's reference case. Then, a fully unconstrained SLS was developed to challenge and improve this reference case based on six main factors:
Integrated production system modelling Fit-for-purpose project and design scoping Alternative field architecture Use of standardization Use of supplier or industry specification Integrated project execution
A production assessment, cost estimation, and schedule were developed first for the reference case, fully compliant with the customer specifications, and with no deviation to the scope of work, and second, for the completely unconstrained SLS.
Comparing the SLS to the reference case for this case study, the main improvements were as follows:
Accelerated production thanks to integrated modelling and the introduction of subsea boosting technology Significant improvement in capex of approximately 41% Accelerated schedule due to a proposed innovative bidding process and a reduced equipment lead time enabled by standardization Lower project risk profile by improving the execution predictability primarily due to the integrated subsea offering
The combination of these improvements resulted in better project economic viability and allowed lower contingency cost accruals due to proactive risk management. The SLS also helped the operating company to build a viable development scenario in order to pass through the next project stage gate.
This paper demonstrates how an integrated subsea alliance with a broad spectrum of capabilities from the reservoir to the surface can deliver value through fully integrated earlier engagement. The methodology presented in this paper can be customized for any offshore prospect; the only prerequisites are early engagement, access to required data, and the freedom for the contactors to develop their own solution, in coordination with the operating company. A key feature of the proposed methodology is to link the SLS to reservoir representation, which avoids the common pitfall of delivering capex savings at the expense of larger production (revenue) losses.
Integration of Wearable Technology for Inspection Tasks
Authors: Pray J. , McSweeney K. P. 
Published: April 2018

Greater complexity in offshore assets has introduced operational changes that impact the ways in which services are provided. Keeping pace with this evolution has led to an increased interest in emerging technologies that can be used in inspection tasks. Implementation of wearable technologies provides a way to capture and visualize information more efficiently, streamline inspection services, and integrate on-site, real-time information capture, thus allowing for more informed and rapid decision-making as well as alternative approaches to planning, execution, and reporting.
Wearable devices can both collect and deliver data in the field, creating a synergy that enables the focus to remain on the task at hand while being able to automatically obtain access to relevant resources. Wearable technology allows field personnel to immediately and effectively capture, share, and collaborate with real time information, hands free. Wearables can also bridge time and distance constraints imposed by having a worldwide enterprise, and enable more informed, real-time decision making. With advanced visualization and augmentation, contextual data can be super-imposed on reality providing interactive job aids, ease of access to asset history, and current state asset health with digital capture of records/narratives. This technology can provide faster, more dynamic intelligence and direction to help quickly identify specific areas of interest for targeted inspection applications.
Incorporation of wearable technologies follows a phased approach. The first step is to look at ways of improving current systems and identifying what processes can be adjusted for increased efficiency and safety. The second phase leverages the use of sensor technology in collecting and analyzing data to improve processes by enhancing data capture and providing additional connectivity. The third phase focuses on creating new processes and developing broader capabilities by building a knowledge base from collected and analyzed data. This phase requires data to be collected, categorized and indexed to identify patterns. The end result of following a structured implementation process is the ability to incorporate ambient intelligence and augmented reality to enable risk-informed decision-making and support efficient execution of inspection tasks.
This paper will primarily address phase 1 activities as well as discuss the driving factors for the use of wearable technology in the offshore industry, the current and future capabilities and use cases for wearable technology, as well as experience, lessons learned, and next steps in the implementation process.
2 Million Pounds Force Electrical Ram BOP
Authors: Kuilenburg Robert van , Li Jie 
Published: April 2018

Abstract
Historically, ram type Blow-Out Preventers (BOP) use hydraulic actuated bonnets to either close the pipe ram or shear the drilling strings in the well. Current hydraulic control systems consist of a massive number of parts. Failure of any of these parts typically require drilling contractor to pull the marine riser and Subsea BOP, resulting in substantial revenue loss. In addition, hydraulic BOP control systems use Multiplexed Electro-Hydraulic (MUX) control systems which add another layer of complexity. However despite all these technologies there is very little direct measured data coming back to surface such as the ram position. Most of the status information is inferred or derived from a few data sources such as hydraulic fluid gallon counts.
Improved electrical battery technology now provides the possibility to store the needed electrical power on the subsea stack and function the eBOP™ subsea motors in the API required time range. For the shear ram, pressured nitrogen that is stored on the stack, provides a booster force to generate a total combined closing force in excess of 2 million pounds. This paper will describe the eBOP ram concept, manufacturing and prototype eBOP testing results including shear testing in excess of 2 million lbf. The eBOP ram is designed to be retrofitted on existing BOP bodies. The eBOP benefits such as improved safety, cost savings, precise control, monitoring and feedback will also be discussed.
Quantitative Analysis of Drilling Progress with Real Time Modelling
Authors: Austin Simon , Nieuwoudt Hermanus , Tilsley-Baker Richard , Jonsbråten Fredrik 
Published: April 2018

Abstract
Reservoir navigation of wells is a highly skilled, valued, and integrated part of the drilling process, especially in complex, deviated development-wells steered through challenging geological targets. Real-time modelling is a new, significant extension in capability to reservoir navigation.
There are many case histories demonstrating the effectiveness of reservoir navigation whereby wells are steered within a productive zone for a significantly higher percentage of footage drilled. This capability increases well productivity and ultimate recovery (reserves) in an extremely cost-effective manner. Indeed it is a key enabler for the oil industry in many provinces around the world.
Quantifying by how much reservoir navigation adds value, specifically in dollar terms, has been traditionally the preserve of back room staff. The answer is generally provided in the fullness of time when interest in the subject has waned.
Real-time modelling puts a value on reservoir navigation services. It can be used to quantitatively determine if drilling ahead will deliver required value. For example, the process to stop drilling (‘call TD’) can be implemented on a truly informed basis with all salient facts at hand. It will also be used to fully optimize well completions both by maximizing production and reducing cost, consigning geometric completions to history.
The focus of real-time modelling is fast, localized analysis (measured in minutes) with a quality high enough to enhance operational decision making. In this regard, it complements detailed reservoir studies that are rigorous and field-wide and for this reason necessarily take much more time (measured in weeks or months). So while there are many common skill sets required for these two processes, they are distinct and different in their purpose. This situation is unlikely to change in the near or medium term.
Real-time modelling has been performed using a combination of downhole measurements being analyzed by competent personnel with advanced software. The results are showing just how much well operations can be still be optimized. Real-time modelling should become standard practice for every well when drilling reservoir intervals.
Platform Modular Drilling Rig – An Improved Design to Help Achieve Better Returns in Low Oil Price Environment
Authors: Tang S. , Zhu X. 
Published: April 2018

Modular drilling rigs (MDR) are widely used on fixed platforms that require extended drilling and/or workover operations during the platform life time. Compared with using jackup rigs, the use of MDRs can save a lot of money for the operators if it is well planned and executed. A MDR can be configured into large modules, where each could weigh as much as 700MT, or in small modules, where each module is limited to up to about 40MT so that it can be lifted by one of the 50t cranes coming with the rig. While each of the two designs has its own merits and shortcomings, it was believed that a third option does exist between these two designs that, with an optimized module size and configuration, can achieve a good balance between maximizing benefits and avoiding drawbacks.
With the above intention, a conceptual study was commissioned by Scivita Inc. (Scivita), with the support of China Oilfield Services Limited (COSL), to analyze the MDR module configuration and determine its impact on the rig weight, the delivery time, the moving cost, and the flexibility for rig owners. The design data and operating insights from five existing MDRs, in the Campeche Sound of Mexico, were collected and used for this study. From 2006 and 2015, COSL and Scivita jointly designed, constructed, and commissioned these five MDRs to be used on PEMEX platforms. COSL has gained a significant amount of experience and insight from operating these rigs since 2007.
Following the conclusions derived from the analysis of the existing rig data, an improved MDR design is proposed that features the standardized medium size modules for power generation, accommodation, substructure, and drill floor. This design will showcase a MDR that is relatively lightweight, occupying minimal deck space, and is adequately integrated to reduce the number of loose items and offshore hook-up effort. With the moderate module weights, it costs less to source transport vessels and derrick barges, or to find a storage space onshore. Following this standardized design, the cycle times for the design and construction phases can be significantly reduced so that they will not be on the critical path of the project schedule.
Finally the expected cost savings using this design is presented in comparison with the more conventional designs of both large and small modules.
Harnessing Data Effectively to Develop a Low-Manned Platform in a Remote, North Sea Operating Environment
Authors: Knutsen Edmund , Ileby Morten 
Published: April 2018

Abstract
Condition monitoring—a data-driven approach to equipment maintenance—helped a large oil company achieve a key strategic objective in its development in the Ivar Aasen field: a low-manned platform. The field is located approximately 112 miles (180 km) off the Norwegian coast. Production on this particular platform began in December 2016, with the remote condition monitoring of equipment done by onshore operational organization in Trondheim, Norway, approximately 620 miles (1,000 km) away. Not only is the remote condition monitoring of equipment helping the operator to optimize maintenance schedules, but it also has helped make the low-manned platform a reality, in addition to substantial cost savings.
Qualification of New Technologies in Subsea Processing
Authors: John Smarty Mathew , Liu Meng-Lung , Wang Zhenghua , Lin Jessie 
Published: April 2018

Subsea processing is rapidly evolving; new technologies are routinely proposed for field application. Introduction of these new technologies, with limited or no previous operating history in the proposed environment, necessitates systematic design verification and validation. Generally, these technologies are not covered by existing rules, regulations, codes or procedures. Therefore, a different approach is required to help qualify their intended function. This paper describes a new qualification process ABS recently published. It also illustrates using the new technology qualification (NTQ) process for subsea compressors, as an example. The NTQ process can be used for qualifying other industry applications, from data analytics engines to new inspection technologies.
The NTQ process is divided into five stages: Feasibility Stage, Concept Verification Stage, Prototype Validation Stage, System Integration Stage and Operational Stage. These stages are aligned with the typical engineering product development phases of to-be-qualified equipment; and are compatible with industry Technology Readiness Levels Approaches (e.g., API RP 17N, ISO 16290). The main activities in each stage include risk assessments and engineering evaluations. These activities build, each upon the next, to determine qualification criteria and means to determine compliance with them. Results of risk assessments and engineering evaluations may lead to design improvements, or modifications to system requirements.
The proposed methodology affords industry a systems engineering-based approach for new technology qualification. The methodology is derived from many years of experience in design verification and validation of new/novel concepts for the offshore industry. The NTQ process has been successfully implemented for Independent Third-Party Review of High Pressure High Temperature designs. Lessons learned from these projects have been incorporated into the ABS Guidance Notes on Qualifying New Technologies. Upon completing the necessary requirements for each NTQ stage, a Statement of Maturity letter is awarded to the technology owner for demonstrating technology readiness for that stage. The Statement of Maturity can assist vendors in demonstrating feasibility and level of maturity for funding – as well as providing confidence to project partners, potential clients and regulatory bodies.
A differentiating feature of the new methodology is the iterative process within each qualification stage to assess the ability of the new technology to perform intended functions in accordance with defined performance requirements. Using systems engineering principles that are easily incorporated into the existing engineering process – and recognizing technology maturity at various development phases – is unique and valuable. Another key benefit of the method is the seamless transition from technology qualification, for equipment manufacturers, to class approval of an asset for owners/operators incorporating the new technology.