bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diver-Less Removal Of The Teal Riser
Authors: Jones Trevor , Walker Craig 
Published: September 2015

Abstract

Objective/Scope
In Q4 2012, the 8” Teal dynamic riser required replacement. A project team was assembled to remove the existing riser and install a replacement. The riser was originally installed in the 1990's by divers based on the Anasuria Floating Production Storage Offloading (FPSO). The FPSO facilities that were used to provide diver access into the chain table area to secure the bend restrictor were no longer operational. Previous diver intervention at the chain table had experienced high levels of non-productive time, so a remote removal method to cut and lower the riser and bend restrictor to the seabed was pursued.

Methods, Procedures, Process
The project team initiated a concept study to set the challenge to release the riser from the FPSO remotely to a) reduce HSE risk; b) de-risk project by separating release campaign from recovery campaign and c) perform the work offshore using a very small team (FPSO bedding constraints was one of the reasons the team didn't use an air dive team to do it from the FPSO). The concept selected was largely based on a method used for removal of other similar risers in 1999 albeit that all that remained from that campaign was a PowerPoint presentation. The majority of engineering calculations and drawings could not be located.

Results, Observations, Conclusions
The tooling was designed, fabricated and tested in less than 6 months from award of contract to offshore operations. During the offshore campaign, various issues were encountered (e.g. incorrect ‘as built‘ documentation) but the remote removal campaign was a success with both the riser and its bend restrictor being removed from the FPSO without requiring any diver intervention, thus reducing the project costs and HSE exposure.

Novel/Additive Information
Lessons learned from the offshore campaign are being captured with the concept being further refined to allow the removal of the riser and bend restrictor without first having to cut and remove the topside riser end fitting. This should reduce the offshore operational time for any future riser removals and remove the risks associated with unknown internal condition of the riser.
Managing Uncertainty to Deliver Sustainable Unmanned Operations
Authors: Gordon Brian , Duncanson Robert 
Published: September 2015

Abstract
This paper describes the key elements of managing uncertainty to deliver sustainable unmanned operations: developing timely and appropriate operational philosophies; focusing on designing hazards out, in the very early phases of a project; and the importance of key business drivers.
The early establishment of operational philosophies contributes significantly to project certainty and would be considered mandatory to deliver on a not normally manned concept. These philosophies are fundamental in terms of reducing cumulative risk to the individual, high production availability and facilitating optimal life cycle costs.
The influence, importance and implementation of drivers, such as Inherent Safety (IS) and Operational Efficiency (OE), in order to manage uncertainties across project phases are discussed. Demonstration of As Low As Reasonably Practical (ALARP) risk can be subjective if these drivers are not included in the early design phases. The paper also shows that inherently safer design and sustainability are lifetime partners.
The operations philosophy is a key element in defining to the project, how the “customer” wants to run the facility. It is essential that the operational philosophy should not be derived from the output of the concept design i.e. “after the event”. Rather, the operations philosophy should be a parent document which should drive some of the concept requirements.
Omissions from or lack of attention to the operations philosophy, in any phase, will inevitably cause increased risk, loss of efficiency, lost production, unnecessary work for both vendor and customer alike and potentially lead to not achieving unmanned status. The influence of project drivers in each project phase needs to be understood and acted on for certainty of outcome and the delivery of not normally manned or minimum manning concepts.
The paper concludes that organic growth of complexity causes loss of value on all projects and it is essential that the operational philosophy is established in the concept phase to reduce complexity and certainty of outcome.
Mapping the Hydrocarbon Envelope From Inside a Wellbore—Reducing Uncertainty During Infill Drilling
Authors: Mnich Cheryl , Bisain Amarjit , Perna Ferdinando , Mearns Leanne , Saputra Eky , Anderson Callum , Dupuis Christophe 
Published: September 2015

Abstract
In 2014 ConocoPhillips (U.K) Ltd. drilled a third development well, a horizontal infill, in the Brodgar gas condensate field (central North Sea) to target a low relief structure 6,000 ft west of the existing production wells. A new deep resistivity tool was successfully used in this well to aid geosteering and mapping of the hydrocarbon envelope.
A pilot well was originally proposed to reduce uncertainty around the hydrocarbon-water contact (HWC) and the top structure depth at the target location. However during data acquisition planning, extensive simulations of the response of the deep directional resistivity (DDR) logging-while-drilling (LWD) tool were carried out to evaluate its capability to reduce these uncertainties. The simulations gave confidence in the ability of the DDR tool to: (1) detect the reservoir 50 ft true vertical depth (TVD) away before wellbore arrives at top reservoir; and (2) effectively map the top and base of the entire reservoir zone. The decision was made to drop the pilot well and apply this new technology to mitigate the risks and meet the well plan and production objectives. This decision was supported by detailed reservoir simulation work and uncertainty modelling.
The tool response showed the range of hydrocarbon column height upon landing at the initial target location to be between 70 and 110 ft (mid case predrill simulations predicted a column of 104 ft). Due to mechanical issues, this initial wellbore had to be abandoned and sidetracked at the 13 3/8-in shoe. As the sidetrack was a twin of the abandoned hole, the DDR LWD tool was not required for landing the sidetrack but was used for geosteering the horizontal section. The tool provided a real-time resistivity profile that could be interpreted up to 80 ft above and below the wellbore resulting in an accurate “map” of the hydrocarbon envelope. The tool has helped to significantly reduce uncertainty on top structure depth and on water encroachment behaviour, leading to re-interpretation of the seismic, static, and dynamic models.
For ConocoPhillips (U.K) Ltd. this case study has demonstrated the value of applying new technology to reduce subsurface uncertainties and eliminate unnecessary well cost.
Digital Oil Field Powered with New Empirical Equations for Oil Rate Prediction
Authors: Espinoza R.. 
Published: September 2015

Abstract
Empirical equations have always been used to fit and later predict oil rate production. The most common and widely use empirical equation are those we use during production decline analysis. With decline analysis equations we are able to predict in most cases production decline as a consequence of reservoir pressure decline. However, these equations will not perform as desired when a sudden reduction on the oil rate of a well has occurred as a consequence of changes on the well head parameters such as a change of the production choke or the gas oil ratio (GOR). These unexpected changes of the oil rate are not able to be predicted with most common used decline analysis equations and generally speaking with deterministic equation sets.
In this paper, a new empirical equation is described to allow the calculation of oil rate from a given well when only information of choke size and well head pressure is available. Calculated production from this equation shows outstanding result in terms of precision when compared with other equations available in the literature like Gilbert, W.E. (1954) and Ros, N.C.J. (1961). In addition, this equation can serve as a great operational surveillance tool when incorporated into a centralized production system and database. Finally, the methodology is described in a way that the reader can apply and adjust the equation to be used in oil fields with naturally flowing wells and stable water cuts.
Advanced Intelligent Completion Solution for Extended Reach Wells
Authors: Basak Debasmita , Gurses Sule 
Published: September 2015

Abstract
Extended Reach Drilling (ERD) wells can be extremely long and technically challenging from drilling through completions, clean up, stimulation and production optimization. This paper will focus on the key challenges associated with ERD well completion, real-time clean up, production monitoring and optimization and will present an advanced intelligent solution enabled by new technologies to handle these complex challenges.
As the fields become more mature, there is an increasing requirement for real time flow profile understanding and interventions to correct unwanted flow profile anomalies such as water production, gas breakthrough, etc. to have better production and reservoir management. By combining real-time data monitoring and active control with optimal zonal isolation along the wellbore has been proven to be one of the most efficient and effective completion strategies in the industry for the abovementioned requirements. The operator can proactively manage production, eliminate or reduce interventions and associated production downtime, well costs and risks. However, getting the invention less permanent intelligent completions to the Total Depth (TD) of ERD wells is one of the major challenges and hence very long horizontal ERD wells are typically completed partially leaving out stretches of reservoir section unmonitored and uncontrolled. Also, conventional intelligent completions have clear limitations on number of flow control valves and sensors that can be deployed in a well, mainly limited by the maximum number of control lines, which can be deployed with the completion. The limitation comes from the feedthrough port limitation of critical completion tools such as tubing hanger, production packer etc. and also from the completion deployment challenges faced with increasing number of control lines. This limits the ability to have an optimal segmentation along the wellbore in many cases.
Another important challenge that our industry faces is in effectively using real-time monitoring data to make informed decisions and take required actions efficiently. Traditionally the whole process of data gathering from down hole tools to decision making and taking reasonable action is long ranging from months to years and requires multi-disciplinary expertise. As a result the well controllability, reservoir management and hence production optimization are compromised due to technology solutions limitation.
New all electrical solution with reliable downhole wet connects and integrated answer product software for data management and analysis of real-time data presented here is a key intelligent end to end solution. This paper gives details of this new generation technology solution that enables above mentioned challenges.
ICS and IT: Managing Cyber Security Across the Enterprise
Authors: Effendi Asif , Davis Robert 
Published: September 2015

Abstract
Industrial Control Systems (ICS) were originally built on proprietary technology and primarily focused on “up-time” and “safety”. Being isolated from the business environment they were independent islands of networked devices. However, ongoing advancements in business technology, brought with it new possibilities, such as the ability to access data and systems located inside of the previously isolated ICS environments. At this point many Industrial Control Systems (ICS) moved from proprietary technologies, to using the same protocols as business IT systems. This paradigm shift has led to an evolving convergence of business and process control networks, which has generated the effect of increased efficiency and visibility to field operations, but also brought with it new cyber security challenges.
Modern technologies contain well known cyber exploits and vulnerabilities which are now inherited in the ICS environment. As a result, ICS environments find themselves directly in the crosshairs of cyber attackers. Effective management of these cyber security challenges and exposures in the ICS environment has emerged as an important and dynamic element in the operational safety, security, and reliability of the infrastructure in the oil & gas industry.
Many of the principles for protection and controls used in the enterprise environment should now be adapted to fit the ICS environment. However, requirements within the ICS differ significantly from the enterprise and should be considered.
This paper will provide an oil and gas industry insight into cyber security programs and countermeasures, and will explore the similarities and differences between IT and ICS protection and risk management.
Converting ESP Real-Time Data to Flow Rate and Reservoir Information for a Remote Oil Well
Authors: Camilleri L.. , El Gindy M.. , Rusakov A.. , Adoghe S.. 
Published: September 2015

Abstract
Flow-rate testing is the most fundamental and essential form of reservoir surveillance and is typically performed on a monthly basis using a test separator. This case study reviews the results from modelling a well located in a jungle for which poor testing quality precluded inflow analysis. The main causes were logistical difficulties, large flow transients, and phase segregation in the flowline between the wellhead and test separator.
A virtual flowmetering technique was investigated to determine a trend of reservoir pressure and skin and identify production optimisation opportunities. The algorithms used real-time data from permanent downhole gauges and electric submersible pump (ESP) surface controllers, which provided the necessary measurement frequency, resolution, and repeatability to capture well performance transients and provide a full production history. The liquid rate calculation used the principle that the power absorbed by the pump is equal to that generated by the motor. Water cut was calculated by modelling the production tubing pressure drop with a multiphase correlation.
Virtual flowmetering is demonstrated to provide a credible alternative where test separators and multiphase meters cannot be deployed owing to logistical difficulties such as in swampy terrain or on unmanned platforms and subsea. Furthermore, the high frequency, resolution, and repeatability of this particular flowmetering technique are greater than those obtained with traditional monthly, or even weekly, test separator data. This case study illustrates how these three attributes enhance nodal analysis, pressure transient analysis (PTA), and superposition, which enabled monitoring the well's reservoir pressure and well interference without the need to conduct pressure buildups.
Additional value comes from extending the application of this virtual flowmetering technique to wells that do not have testing difficulties, especially those that are under producing and require detailed diagnostics (e.g., PTA). The technique is also well suited to application in true real time because it is analytical, valid across the full pump range, and able to capture transients without requiring an iterative process. Is real-time flow rate just around the corner?
Enhance the Drilling & Tripping Performance on Automated Rigs with fully automated performance measurement
Authors: El Afifi Sameh , Albassam Bassam , Fahmy Fadi Atef 
Published: September 2015

AbstractThis paper describes the development and implementation of a unique new capability to automatically measure the performance of drilling crews and Invisible Lost Time; the supporting technology service makes it possible to carry out detailed comparisons of the performance of crews across a large number of installations. This technology service uses rig sensor data to automatically generate an objective description of the drilling process using the patented “Automated Operations Recognition System” without the need of additional personnel or equipment on the rig site.This simply will help improving rig performance of drilling and tripping operations and allow benchmarking and comparison between different rigs and different crews etc.The service is used to; Analyze the drilling process at a high level of quality and detail which complements traditional morning reporting. The patented “Automatized Operations Recognition System” has the potential to significantly reduce total well time by setting standardized and objective benchmarks in order to identify non-productive or “Invisible Lost Time”, otherwise known as “ILT” and to maintain an increase in performance.Uses a well-defined set of Key Performance Indicators (KPI) to measure drilling performance accurately in order to make Invisible Lost Time visible.Compare actual performance with predefined practices, and then maintain performance-optimized procedures once they are in place.Optimize an organization’s performance through benchmarking and trend analysis using Automated Drilling Performance Measurement system.Among many of the examples presented in the paper will be one on the variation in the tripping slip to slip connection time and drilling weight to weight time of 4 wells on 3 rigs.In addition, the variation among different drilling crews on each rig which showed huge differences when comparing similar operations. The paper will also present the potential savings after implementing this initiative.
Collaborative Working in Shell - Value Achieved, More to Follow
Authors: van den Berg Frans G. , McCallum G. A. , Wallace Stewart 
Published: September 2015

Abstract
Collaborative Work Environments (CWEs) have been implemented in the majority of Shell’s assets. The large scale deployment was achieved through a structured programme, taking assets and projects through a standard CWE design, implementation and embedding approach.
This paper provides an overview of the progress of Shell’s CWE programme. It shows its reach, the value achieved, the learnings and the response to the current low cost environment. It also looks forward to further opportunities for collaborative working in wider business areas in an oil and gas company.
Enhanced Kick Detection with Low-Cost Rig Sensors Through Automated Pattern Recognition and Real-Time Sensor Calibration
Authors: Pournazari Parham , Ashok Pradeepkumar , van Oort Eric , Unrau Sean , Lai Stephen 
Published: September 2015

Abstract
In recent years, the drilling industry has been exploring the use of sophisticated downhole sensors and more elaborate surface sensors to improve prediction and detection of trouble events such as kicks, fracture breathing and lost circulation. The use of such sensors, however, comes at a considerable additional cost and is often difficult to justify on low-cost land-based wells. On the other hand, the conventional suite of low-cost surface sensors often drift out of calibration and, without manual intervention, can provide bad data that may lead to missed or false alarms. It would be highly desirable if the conventional sensors could still be used but with improved robustness and precision for event detection. This paper reviews existing event detection methods and their shortcomings, and proposes a new method that not only addresses these shortcomings, but also improves the quality of the sensor data gathered.
This paper presents a pattern-recognition system that allows for fast analysis of sensor patterns to identify events, and a real-time sensor calibration methodology that uses a combination of a physics- based model and machine-learning techniques to improve the quality and usability of rig sensor data. Focus is on gains/kick events in particular. The calibration algorithm analyzes the quality of sensors in a mud circulation system and calibrates these sensors to yield meaningful data. This leads to a much higher accuracy in the sensed data, e.g. by mitigating flow sensor drift. The presented event detection system can then more reliably detect a kick, lost circulation or a fracture breathing event with reduced frequency of false/missed alarms.
The proposed method has been tested and implemented on actual mud circulation sensor data from the field. Using the analyzed data we demonstrate how real-time calibration can high-grade the data from a simple flow paddle sensor into much more accurate flow rate readings. We also show how sensor calibration allows for increased confidence in the values of other sensors as well, such as the pump stroke counter readings. Ultimately, the method presented in this paper allows one to extract more meaningful information from inexpensive surface sensors and make drilling trouble event predictions that are much more accurate than currently available industry methods.
Fusion of Real Time Data Transmission and Visualization to Optimize Exploration Well Testing Operations
Authors: Miyajan Ramzi , Khudiri Musab , Wuhaimed Ali , Gill Harmohan , Nahdi AbdulHakim , Kashif Muhammad , Meraj Hamood 
Published: September 2015

Abstract
One of the critical operations during the exploration phase is well testing required determining fluid type, flow rate, and the sustainability of the production. With the right planning, technology and implementation, well testing can ensure reservoir quality and production such as, permeability, initial reservoir pressure, hydraulic fracture parameters, near wellbore formation damage, geometry of the reservoir, and reserve quantities.
Exploration Well Testing Operations require a complex integration of various services including surface well testing, artificial lift via coiled tubing, downhole data transmission and on-site operational activities. The increase in exploration activities involves various service companies’ proprietary data acquisition systems that introduce a challenge for decision makers due to segmented data and information. This calls for establishing an integrated unified viewer combining the operational data for engineers to enable real-time data supervision, technical support and decision making from the headquarters to well-site locations reducing operational risks and optimize required cost.
This paper highlights the progress of the real time data transmission interface to support highly active exploration well testing operations in Saudi Aramco.