bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Experience Transfer and Learning Can Lift Knowledge From Individuals to the Organizational Level
Authors: Mathisen Petter , Andersen Mats 
Published: March 2017

Abstract
During a field development, huge amounts of data are created and gathered. To what extent is the captured data and knowledge actually reused? Is human knowledge and operational information effectively utilized in future projects and can it be used more efficiently during the development phase or the lifetime of the field?
Since 2014-2015, The pilot client has been focussing on implementing a software tool for collecting operational data and engineering experience. By creating a common "knowledge database", the operator makes sure the individual learning in each project is saved and made accessible on a company level. Based on the results recorded on the field development, the pilot client has seen that by standardising the knowledge management process, it is possible to locate features for improvement of effectiveness by minimising human error and ensuring motivation for working with optimisation across the company.
Learning across large organisations has always been a great challenge. During a field development a huge amount of data is collected over a longer period. Data comes from several sources in different formats – service companies, rig owners, technology providers, and licence partners. During a field development project, it is natural that the engineering teams want rather to spend time on operational project management than looking for data.
Based on the experience from both AGR and the pilot client, offset analysis often means a large portion manual data processing and searching for experiences. Working like this means that human error is not locked out. In addition it is very time-consuming and often creating repeated efforts, leading to non efficient resource usage. In the planning and execution of operations, it is important to learn from past experiences to avoid making the same mistakes several times, and to learn from others' success. Valuable experiences exist in most of the organisations, but are unfortunately often difficult to access for the end user.
To address the human element around creating and capturing data, The pilot clienthas focused on standardising the process at the same time prioritising knowledge management and skills development within the field development team.
To execute the focus, The pilot client uses software technologies to create a cloud based database of well data and experiences in one place, enabling easy access to visual displays for the user. Experiences are captured through a standardised user interface.
The engineering time is now spent on analysing data, not looking for it or if found spending hours on processing it.
The software visualises trends and opens window for detecting potential challenges in the project and identify missing data and risk. Similar information can be shared between teams onshore and offshore and information flow enables to map potential for improvement in effectiveness.
New Generation 3D Simulator Predicts Realistic Mud Displacement in Highly Deviated and Horizontal Wells
Authors: Tardy P. M. , Flamant N. C. , Lac E. , Parry A. , Sutama C. Sri , Almagro S. P. 
Published: March 2017

Abstract
Effective mud removal is a prerequisite to attain the cement coverage necessary for good zonal isolation. Because of this, the oilfield industry has dedicated considerable attention to the topic of mud displacement over the past 60 years. The first 2D annular displacement simulator was introduced in the 1990s and it is now widely available. The results are satisfactory for simpler configurations. However, for deeper wells with complex trajectories such as highly deviated or horizontal wells, the models start to show their limits. This paper discusses the advancements in mud displacement simulation that overcome the limitations of the previous generation simulator and provide a more realistic simulation in highly deviated and horizontal wells.
A new generation simulator now provides high-fidelity results via a combination of: 1) a pipe displacement model, accounting for fluid contamination inside the pipe; 2) a high-resolution annular displacement model, accounting for the complex 3D annulus shape with full determination of axial and azimuthal flows; and 3) a stiff-string centralization model based on the finite-element method, predicting casing position in a 3D wellbore.
A primary cementing operation for a horizontal well was studied and an unprecedented congruence was witnessed between predicted fluids annular concentration maps and ultrasonic cement log. The simulator was also able to predict complex channeling patterns in the annulus. These results allow a better understanding of the cement placement technique and provide means to optimize the sequence of fluids to achieve effective mud displacement in the well.
Enabled by advancements in today’s computing capabilities, the new simulator is able to simulate both simple and highly complex scenarios more realistically. Finally, the new model allows better planning and decision making to achieve zonal isolation and well objectives.
A Proactive Safety Culture Leading to Reduced TRIR
Authors: Robert Seth , Fiffick William , King Kenneth , Guillory Robert 
Published: March 2017

Abstract
The following is a 5 year case study for a drilling services and manufacturing company describing an employee driven safety program. The results show the downward trend of the company TRIR from 2011 to 2015 and discusses the tools and techniques used to lower the rate year after year.
In 2011, a companywide initiative was launched that introduced safety teams for every team member of the organization. Through routine safety team meetings, improved communication, safety projects, and safety training the company began a journey of increased awareness and appreciation for individual safety commitments. Throughout the 5 year journey new tools were introduced, such as behavior based safety programs and increased visible management commitment with an end result of a reduced Total Recordable Incident Rate of 85%.
In 2011, there were 18 recordables resulting in a Total Recordable Incident Rate (TRIR) of a 1.3. Safety teams were introduced throughout the entire organization and new safety tools were implemented, such as behavior based safety and improved communication. In 2012, the TRIR was reduced to a .66. Different tools and trainings were introduced for front line supervisors and individuals. The safety culture continued to improve throughout the organization. A sense of excitement and awareness became visible. In 2013, the TRIR was lowered to a .45. New initiatives continued including annual safety themes and management led initiatives, such as Safety Week. In 2014, the TRIR was a .46. The mission to zero continued and leading measures evolved. Improved safety training was offered and an improved new hire orientation was implemented that included active participation from senior management. In 2015, the TRIR was a .20.
This case study covers all the changes and initiatives that were implemented over the 5 year journey, step by step, that led to the decrease in the TRIR over the last 5 years. This is an example of a proven model with lessons learned that is scalable and can be implemented in any organization looking to reduce their TRIR and improve their safety culture.
Predicting Rotor-Stator Fit in Positive Displacement Motors PDMs
Authors: Alvarez Alfredo A. , Boscan Jorge 
Published: March 2017

Abstract
One of the most challenging aspects of using positive displacement motors (PDMs) is understanding the influence of each variable on the motor functioning and failure modes. Rotor-stator fit is the most critical factor in achieving maximum service life and performance. The objective of this paper is to present a new method to predict the rotor-stator fit that accounts for all main downhole variables.
This new methodology will enable the selection of a rotor-stator combination that delivers a balance between performance, efficiency, and service life. Fit selection is complex and should be made based on physics models, testing data, field data, and experience. However, downhole temperature is commonly the only variable used to calculate thermal expansion of the elastomer and the resulting rotor-stator fit. Effects of environmental conditions and operating parameters are normally neglected. This paper presents a calculation method for predicting rotor-stator fit in PDMs that includes environmental conditions and operating parameters.
A mathematical model is proposed to account for additional expansion caused by internal heat buildup (hysteresis). Additionally, a time-sensitive equation is used to estimate elastomer volume changes resulting from the interaction between the fluid and the elastomer. In conjunction with the equations developed, collected rotor and stator wear data captures the effect of rotor coatings, drilling fluid, solids content, and elastomer mechanical properties. An additional equation is also utilized to estimate the change of elastomer volume caused by the system hydraulics (downhole pressure and flow rate). Final fit prediction is obtained by combining all these effects. Normalized fit ranges can then be correlated with expected performance and risk of failure. After testing and validation, results from the new method have proven to be accurate in applications with both low and high downhole circulating temperatures and for different elastomer types, drilling fluids, and varying operational conditions. A real case is presented.
Unlike any current temperature-based prediction method, this new model integrates the effects of the most important downhole variables to accurately predict the rotor-stator fit. As a result, uncertainty in operations decrease; risk of failure is drastically reduced; and the reliability, performance, and service life of positive displacement motors are improved.
Use of Quantitative Risk Analysis Methods to Determine the Expected Drilling Parameter Operating Window Prior to Operation Start: Example From Two Wells in the North Sea
Authors: Daireaux Benoît , Cayeux Eric , Haavardstein Stein , Stokland Leif Magne 
Published: March 2017

Abstract
While in a well-defined context, drilling operations can be optimized to a great extent, other more complex drilling operations, either due to challenging trajectories or taking place in more unpredictable geological setting, may incur undesirable delays due to unforeseen difficulties. For such challenging drilling operations, it is more and more common to perform pre-operation verifications in the form of "drill the well on the paper" or "drill the well in the simulator". Such methods may help the engineering team to discover some of the flaws of the operation plan but they fall short in providing quantitative risk assessments of the studied drilling operation plan.
A methodology based on uncertainty propagation throughout all the input parameters of the drilling program has been developed to quantitatively assess the inherent risks levels embedded in a drilling operation plan. Hundreds of simulations are performed automatically to estimate a safe drilling parameter operating window for every depth of the planned drilling operation. The analysis of the obtained window size allows to determine the risk levels and which of them are the most predominant. This allows to check if the plan is robust and to prepare for countermeasures in case difficulties should be encountered.
This quantitative risk analysis method has been applied to two challenging drilling operations performed in the North Sea.
When a case has been described, the analysis is performed automatically and does not require any human intervention. The analysis of the results may thereafter be used by the drilling team to focus on the most essential challenges ahead of the drilling operation during the "drill the well simulation" session.
Novel Techniques for Modelling Re-Fracturing in Tight Reservoirs
Authors: Shaikh Hamza , Iwuoha Sochi , Islam Arshad 
Published: March 2017

Abstract
In the current low commodity price environment, several operators have chosen to return to their mature fields to re-fracture the reservoirs to improve overall recovery of reserves. Although modelling remains challenging, re-fracturing treatments have been successfully executed on multiple wells worldwide. This study compares three different approaches to model re-fracturing in tight sands as a means of reducing the overall uncertainty. Multi-domain integration was utilised in which geomechanical data was coupled with petrophysical analysis to build a three-dimensional (3D) hydraulic fracture model. Fracture pressure history matching was performed and the model was validated using calibration data available from microseismic analysis and extended leakoff tests. Production history matching was performed to validate the reservoir simulation model and estimate the resulting depletion around the wellbore. Geomechanical properties and the resulting minimum in-situ horizontal stress were re-calculated incorporating the results of depletion using three different approaches: Pore Pressure Model, Scale Model and Non-Scale Model. Finally, the hydraulic fracture models were re-constructed using the revised geomechanical properties to simulate re-fracturing using various pumping treatments. The fracture geometries obtained from re-fracture simulations were dependent on the model used for re-computation of geomechanical properties post-production as well as the fluid volume pumped. These properties were also validated using laboratory testing. Comparison of the three approaches indicated consistent geometries when small volumes of fluid or typical ‘Plug and Perf’ designs were pumped. Upon pumping larger volumes or typical ‘Sliding Sleeve’ treatments, major differences were observed using the three approaches indicating larger uncertainty and warranting the use of the more rigorous Non-Scale Model. Validated models are important tools for designing hydraulic fracturing treatments to avoid risks of sub-optimisation of fracture designs or undesirable bashing of offset parent wells. Good understanding of re-fracture models helps oil companies make informed decisions regarding their completion programme, hence improving overall hydrocarbon recovery. Modelling of re-fracture treatments continue to pose a challenge for engineers due to added subsurface static and dynamic complexities. This study presents basic guidelines to follow for modelling, with results verified from laboratory testing.
Subsea Installation of an Interventionless Annular Safety Valve Reduces Operational Time A Case Study
Authors: Sirevåg Espen , Torsteinbø Ørjan , Murdoch Euan 
Published: March 2017

Abstract
With the downturn in oil price and recent reduction in drilling activity, especially in high-cost environments, the industry is increasingly looking to save time, cost, and risk throughout all drilling and well operations. Conventional completion operations are being challenged to identify possible ways of reducing time and cost. To address this, the industry is adopting new technologies and methodologies to reduce risk, rig time, and nonproductive time (NPT) and to conduct operations in way that traditional tools do not allow. This paper focuses on the first subsea deployment of a remotely activated annular safety valve (ASV) in a deepwater well located in the Norwegian sector of the North Sea.
ASVs are traditionally set by one of four methods: a dedicated setting line to surface, applied tubing pressure, applied annulus pressure, or the shifting of a mechanical sleeve, which allows communication to a setting chamber. This paper describes an approach for running the ASV that requires no dedicated setting line and is initially insensitive to tubing pressure; this facilitates the full testing of the completion prior to setting the ASV packer. Using existing rig infrastructure, a frequency modulated pressure cycle is sent from surface to command a sleeve to move and allow communication with the setting chamber. The ASV packer is then set and tested.
The first subsea deepwater installation of the ASV was completed in August 2016, and this method of deploying the ASV provided several advantages over traditional methods.
Interventionless Reservoir Isolation Valve Removes the Requirement for an Intermediate Completion: A Case Study
Authors: Edwards Andrew , Murdoch Euan , Munro Christopher 
Published: March 2017

Abstract
With the constant push to save rig time and costs, the industry is looking to technology to provide these benefits whilst maintaining the same operating standards and risk mitigation. Radio Frequency Identification (RFID) technology provides the means to remotely actuate downhole completion tools, thus reducing rig time by mitigating the requirement for intervention runs and the risks associated.
This paper will focus on an application of RFID technology to enable an operator to eliminate an intervention run or intermediate liner into a 10,000-ft reservoir section in the North Sea. The case-study well has pre-perforated liner in two zones—a 4-1/2-in. lower zone and a 7-in. upper zone (Fig. 1). These zones are isolated with swellable packers and pressure-actuated annulus packers. The typical procedure is to straddle the annulus packers individually using an inflatable plug, but setting the lower annulus packer incurs additional risk while running in the horizontal for an extended distance.
In this application the client is to use the RFID Reservoir Isolation Valve (RIV) to eliminate an intervention run to set an annulus packer. The RFID RIV provides the means to isolate the lower reservoir section and to provide a closed system to apply tubing pressure against.
Figure 1 Well schematic
Degassing Rate of Drilling Fluid Base Oils as Exposed to Depressurisation and Drill String Rotation
Authors: Grimstad Alv-Arne , Linga Harald , Haave Øyvind , Saasen Arild 
Published: March 2017

Abstract
An experimental set-up is established, designed for recording the absorption rate of a liquid during gas influx and at rotational flow conditions in an annulus. Likewise, the set-up is designed for monitoring the degassing rate from the liquid during controlled depressurisation, resembling the pressure drop during vertical annulus flow.
The set-up is designed for system conditions up to 400 bar, 150 °C, resembling downhole conditions. Annulus outer/inner diameters are 73/59 mm and the length of the main section is 1000 mm. A windowed section at the top allows monitoring of liquid volume changes and possible foaming behaviour during gas absorption/degassing. An inner cylinder can be rotated at speeds up to several hundred rpm, enough to produce Taylor-vortices and even turbulent flow in the annulus. For the reported test runs the system pressure is 100 bar, with temperatures 40 and 80 °C.
Two different base oils are tested, one normal mineral oil and one linear paraffin oil. A number of tests are run, with varying rotational speed and depressurisation rate. For tests with lower rotational speeds the degassing is postponed, with a corresponding higher maximum degassing rate as system pressure decreases towards atmospheric conditions. The impact from drill string rotation and type of base oil is shown, demonstrating the importance of describing the kinetics of the gas bubble nucleation rather than assuming instant equilibrium of gas and drilling fluid during the depressurisation during the vertical annulus flow.
Tests performed at experimental set-ups like the one presented will provide data for more advanced models of drilling fluid degassing behaviour. This will enable a more correct interpretation of data during well control events.
Predicting Gas Loading Capability in Oil-Based Drilling Fluids
Authors: Skogestad Jan Ole , Linga Harald , Bjørkevoll Knut S. , Saasen Arild 
Published: March 2017

Abstract
During a gas influx scenario in drilling and well operations, early detection is important in order to prevent harmful consequences to rig, personnel and environment. However, the influx of natural gas may be masked if the gas loading capability of the drilling fluid is considerable. This work aims to provide a methodology for predicting the gas loading capability of oil-based drilling fluids, such that precautions for early gas influx detection can be made also for HPHT-drilling with oil-based drilling fluids.
In principle, the bubble-point curve; i.e. the transition from single liquid phase to two-phase, of the mixture of drilling fluid and natural gas determines the maximum loading capability of gas in the drilling fluid at the actual pressure and temperature. In overbalance situations the gas loading capability is decisive for the volumetric response and severity of gas influx. Thus, the gas loading capability needs to be accurately described for hydraulic models used for well control. This paper describes a methodology for gas loading capability prediction based on the bubble-point curve as determined from thermodynamical equations-of-state calculations. Different thermodynamical models have been evaluated and compared with experimental data for OBDF–methane systems. In particular, the features and requirements for the models are discussed.
Strategies for tuning the models to experimental results are necessary regardless of the choice of equations. Both models and experimental data on gas loading capability versus pressure follow the linear Henry's law in the subcritical region, and deviate severely from this as the pressure is increased towards the dense phase region of the drilling fluid – natural gas mixture. The determination of the dense phase region is of particular interest, as for this region there exists no limit in terms of gas loading in the drilling fluid. The proposed methodology forms the basis of a promising tool for gas loading capability calculations that, if utilized in drilling simulation software, may improve understanding and help detecting gas kicks early, thus lowering the associated risks, in particular for HPHT-drilling.