bluuebunny/crossref_metadata_2025_split huggingface dataset:
Repeated Judgment Elicitation: Tapping the Wisdom of Crowds in Individuals
Authors: Welsh M. B. , Begg S. H. 
Published: October 2009

Abstract
It is commonly recognised that the Wisdom of Crowds [1] enables a group of people with limited knowledge to make, on average, very accurate estimates. This process underlies the success of prediction markets [2], which are used to accurately predict outcomes as disparate as elections and box office takings. In the O&G industry, however, there are clear limits on the number of people who can be canvassed for their opinions. Not only are there a limited number of people with sufficient knowledge to make any estimate at all for a particular problem but confidentiality restricts this further. Recent psychological research, however, has demonstrated benefits of repeated individual judgments – asking the same person to repeatedly estimate a parameter. We critically review individual, repeated-elicitation techniques currently in use and describe a method that avoids many of the problems with these – More-Or-Less Elicitation (MOLE) [3].
The MOLE is compared with alternate, single- and repeated-judgments elicitation methods, yielding superior accuracy and calibration to any of the alternate techniques. Its estimates explain an additional 20% of the variance in the parameter of interest over its nearest rival and less than 9% of its elicited ranges did not contain the true value when expected to. We argue that, for the O&G industry, repeated individual judgments have the potential to greatly improve the accuracy and calibration of estimates and, further, that the MOLE harnesses the benefits of repeated judgments while avoiding common problems such as repetition of answers and confirmation bias.
This paper reviews the latest research on repeated judgments in elicitation and demonstrates the benefits of repeated, individual judgments for elicited values. The MOLE, which takes advantage of these benefits, is simple and easily transferable to most elicitation domains, enabling its benefits to apply throughout the industry.
A Systems Engineering Approach to Change Management that Overcomes the Barriers to User Acceptance
Authors: Campbell Michael 
Published: October 2009

Abstract
Definitions are important to understanding the message of this paper. Therefore, let's begin with the two key definitions. At a high level a system is defined as the combination of related parts organized into a complex whole1. And change management is defined as a structured approach to transitioning individuals, teams, and organizations from the current state to a desired future state2. Taken together, these definitions should dispel the notion that moving people from the status quo to a new way of working with digital technology will not be either easy or quick. As we have all learned, it is complicated and sometimes, unpleasant.
As an illustration, Douglas K. Smith gives us words of wisdom as we try to get users aligned with the new technology. He says, "You can encourage, cajole, demand, reward, support, flatter, educate, reassure, inspire and threaten, but until enough people, including you risk some combination of ChoiceActionReflectionRepetition
Neither individual nor organizational change occurs.3
Strategies for Acquiring and Integrating Petrophysical Data for Reservoir Evaluation
Authors: Amabeoku Maclean O. , Kersey David G. , BinNasser Rami H. , Mohammadi Hisham H. 
Published: October 2009

Abstract
The use of key wells to improve formation evaluation programs is well established as this method has been proven to improve petrophysical accuracy. In the key wells, extensive logging, coring and fluid sampling programs provide the data used to develop better predictive models for water saturation, lithology, porosity, and permeability. To be effective, key well programs must obtain representative special core (SCAL) data from all cored facies, but this often requires high-density sampling, which may not be cost effective. This paper presents a strategy to meet technical and business objectives by selecting optimum number of samples required to provide the data needed to develop improved petrophysical models.
A case study is provided showing the development of an optimum SCAL sampling strategy for a carbonate reservoir. This example highlights how an optimum sampling program for capillary pressure, electrical properties and relative permeability tests leads to enhanced formation evaluation. The case study demonstrates how effective sampling strategies improve determination of water saturation and permeability. It also shows how relative permeability data from a carbonate reservoir may not be directly usable for reservoir simulation if all rock types are not sampled. To represent all rock types, porosity and permeability were initially used to develop hydraulic units. Next, geologic descriptions, which incorporate thin section petrography, X-ray diffraction, and scanning electron microscopy, were used to characterize the reservoir rock in terms of geological facies. X-ray computerized tomography (CT scanning) was used to determine core plug heterogeneity, especially vugginess and mineralogical changes not visible on inspection. Lastly, mercury porosimetry was used to group core plugs of the same rock type based on similarity in pore size distribution. These composited core plugs were then subjected to relative permeability measurements at reservoir conditions.
Using the data from this study, core-calibrated saturation and permeability profiles were developed for all rock types. In addition, an analytical relative permeability model for direct input into flow simulators was developed and validated. This model is easy to use and can be modified quite easily during reservoir simulation by changing some predetermined parameters in the model. This should reduce the time and expense of history matching. The model incorporates the scatter in relative permeability data that is usually encountered in laboratory measurements.
Can Sand Screen Failures be Prevented in Gravel Packed Cased Hole Completions?
Authors: Gillespie George , Jones Colin 
Published: October 2009

Abstract
Sand control screens must effectively retain the gravel pack and formation sand, and provide a conduit for fluids to flow into a cased hole producing well. A failure may occur while completing the well, or at some time during the well's operating life. The root cause of the screen failure is often difficult to determine with absolute accuracy. Often, it is determined that screen failure occurs due to a combination of plugging and erosion resulting in the loss of sand control.
A comprehensive test program was undertaken to evaluate erosion rates of different screen types of cased hole completions completed with wire wrap, prepacked screens, metal mesh, or compliant sand screens. The purpose was to determine whether any screen type had a marked advantage to resist erosion during the gravel packing process. Tests were conducted at high velocities to simulate the end of the gravel packing process to determine erosion of the screen in a reasonable time scale.
To evaluate the expected screen's service life while the well is in production, configurations of each screen type were installed in a test fixture, and several tests were conducted at different velocities and sand concentrations. Special ports were used to simulate producing through a cased hole perforation tunnel.
The sand was sized to pass through the screen with minimal plugging, which would simulate fines production over time in a producing well. The specific wear rates and percent of rate loss were determined for each test. Micro photos were used in the analysis of the wear patterns, along with pre and post test measurements of the wire wrap slots or metal mesh pore sizes.
This paper will describe the test methods used, the test results and lessons learned, and will describe a model that can be used to predict a screen's service life for cased hole completions based on a given set of well conditions.
Improving Allocation and Hydrocarbon Accounting Accuracy and Automating Associated KPI's
Authors: Cramer Ron , Schotanus Dave , Colbeck Nick 
Published: October 2009

Abstract
In the oil industry it is necessary to reconcile fiscally measured hydrocarbon production with estimated production from the associated wells. This process is known as "allocation" and is important for a number of reasons including accounting for field production to owners/governments, field surveillance and volumetric input to reservoir simulators.
Traditionally allocation is performed on a monthly basis, reconciling the "less accurate" sum of the well tests adjusted by well uptimes with the "more accurate" fiscal measurements. This process is subject to a number of inherent inaccuracies including less than perfect well tests, lack of knowledge of precisely when the wells were interrupted, unknown well flow changes and how to effectively allocate the difference between fiscal and well test measurements.
Ineffective allocation can lead to financial consequences due to inaccuracies in volumes allocated between multi-various owners and various tax regimes. Inaccuracies can also feed through to reservoir simulators which may be used in corresponding decision making processes such as where to drill the next well. These inaccuracies are generally compounded with time, as allocation is performed month after month over the field life cycle.
Associated with hydrocarbon accounting are some Key Performance Indicators (KPI's) such as well daily production and deferment rates.
The purpose of this paper is to describe Shell experiences in improving allocation accuracy and automatic KPI reporting through more effective use of available production data and by using a continuous, rather than a discontinuous hydrocarbon accounting process.
Simplification of Coupled Reservoir and Facility Modelling to Facilitate Efficient Decision-Making: An Example of a Miscible Sour Gas Flood for Enhanced Oil Recovery
Authors: van Berkel J. T. , Hassan A. A. , Haynes B. , Woodhead T. J. 
Published: October 2009

Abstract
The Shell integrated modelling methodology places a strong emphasis on achieving the appropriate focus at each step in the business cycle. In particular, the net is cast wide at the project feasibility stage requiring a large number of development opportunities to be evaluated using simple or coarse modelling. Where the development planning requires an understanding of critical interactions between the reservoir and the surface due to the presence of a complex facility network, an Integrated Production Systems Model (IPSM) is an essential tool. To provide for an efficient and flexible evaluation of a range of development options it is crucial to simplify where possible, with a suitable validation step to ensure that the simplifications have not lost essential detail.
To illustrate the methodology, a field case of the miscible gas flood of several different reservoirs produced through a common facility is presented. Results from an IPSM with a simplified facility model were validated against a more detailed facility model in Unisim. The simplified facility model has sufficient details to closely match the predictions from the detailed model and is easy to change when defining alternative concepts or scenarios. This methodology allows for a rapid and robust evaluation of various field development concepts using an integrated reservoir/facility model.
Drill-Bit Metamorphism: Recognition and Impact on Show Evaluation
Authors: Wenger Lloyd M. , Pottorf Robert J. , Macleod Gordon , Otten Glenn , Dreyfus Sebastien , Justwan Holger , Wood Emily Sekula 
Published: October 2009

Abstract
With petroleum exploration and development progressing into deeper and more challenging environments, drilling technology has provided the means to effectively and safely reach and complete desired targets. Approaches such as turbo-drilling with polycrystalline-diamond compact (PDC) bits or diamond-impregnated bits increase penetration rates, lessen drill-bit changes, and are more easily steered in directional drilling, but also generate artifacts that may hinder recognition of indigenous hydrocarbons and interfere with geochemical interpretations. The higher bit speeds with turbo-drilling compared to rotary drilling (e.g., ~1000 vs. 300 rpm, respectively) often generate additional heat that may essentially fuse rock cuttings with drilling mud, thermally crack oil-based drilling fluids, and produce both hydrocarbon and non-hydrocarbon artifacts.
Bit-generated rock textures and pulverized drill cuttings, mixed with drilling mud cause difficulty in evaluation of lithology, age, and shows. The recognition of indigenous vs. artifact products is crucial to determining the presence and characteristics of hydrocarbons encountered in the well bore. These can be distinguished through analyses of mud gas and fluid-inclusion volatiles (FIV) analyses of drill cuttings.
Analyses of mud gases show that gases typically not found in natural gases are generated during drill-bit metamorphism (DBM) including CO, ethene, and propene. Gases are rich in methane and C2-C4+ hydrocarbon gas components and may include H2S, CO2 and carbonyl sulfide (COS). Laboratory experiments suggest that thermal cracking of oil-based drilling mud can be the major contributor to these gases. Cracking of base oil alone generated wet gas with little CO2 and no H2S, while cracking of base oil in drilling mud generated wet gas with abundant CO2 and H2S. Drilling mud additive components such as lignosulfonate are likely sources of the generated CO2 and H2S. Recognition of DBM is crucial to effective drilling operations and evaluation of indigenous hydrocarbons.
Evaluating the Movement of Injected Gas and Identifying Bypassed Condensate in the Oso Field, Offshore Nigeria
Authors: Sumpter L. T. , Gunther M. , Kerscher I. M. , Leininger S. C. , Wudiri B. 
Published: October 2009

Abstract
The Oso field is a faulted monocline that has been producing condensate from two shallow marine/fluvial reservoirs since 1992. Original pressure data indicates the two reservoirs are connected in the condensate leg but not in the water leg. This relationship requires seal at some points of cross-fault reservoir juxtaposition and leak at others. The original aquifer pressure was much lower in the younger reservoir, allowing the original condensate-water contact to be over 1,100 feet deeper than the contact in the older reservoir. Neither reservoir had an original gas cap, but both have received gas injection.
The objective of this study was to gain a qualitative understanding of the dynamic behavior of the reservoirs and faults in order to identify the key elements of the reservoir architecture prior to building a geologic model and progressing to reservoir simulation. Specifically, we attempted to evaluate cross-fault communication between the two reservoirs, cross-fault communication within the same reservoir, the significance of interbedded shales in the relatively thick older reservoir, advancement of the aquifer, the movement of injected gas, and the potential for bypassed condensate. The interpretation of available seismic data provided a coarse framework for this study, but the most significant insights came from the evaluation of wireline log, pressure, and production data from more than 70 wells drilled at various stages of the field's history.
Pressure data from wells drilled after production start-up combined with observations of the distribution of injected gas allowed us to conclude that there is significant variability in fault transmissibility among different faults and along the length of a single fault or fault system. This variability may be explained, in part, by changes in fault gouge composition associated with net-to-gross variation in the reservoir. Observed gas movement (or lack of movement) across some faults has very specific implications for the location and risking of in-fill wells targeting bypassed condensate. Interbedded shales within the thick (~750 feet) older reservoir have a significant impact on the sweep efficiency of injected gas and the location of bypassed condensate. The interbedded shales could not have been mapped from seismic data or with the limited well control available in the initial stages of development, but with the additional well data acquired in subsequent in-fill drilling programs we were able to map them for this study. Mapping of the shales allowed us to interpret the distribution of bypassed condensate encountered by in-fill drilling, demonstrating the importance of maturing our mapping as the field matures and considering both geologic and reservoir engineering data and concepts in the mapping process.
Training the Next Generation of Project Leaders
Authors: Massingill Robert D. 
Published: October 2009

Abstract
ExxonMobil1 Project Management resource needs require the successful assimilation, development, and retention of young talent. This paper will highlight key components, examples of methods used, and recent lessons learned at ExxonMobil Development Company (EMDC) to ensure our employees develop the Global Project Management skills required for the project needs of tomorrow.
Specifically, two key components of our career development program will be discussed. A primary way to prepare the next generation of project leaders is to ensure they gain a core set of competencies in their first three years via a combination of "on-the-job" training experiences and traditional training courses. New project management engineers are provided a focused list of experiences that they are to gain either through on-the-job experience, classroom training, or individual learning experiences (e.g. interviews, computer-based training, or technical coaching). Classroom training in specifically designed company courses ensure our future project managers have the skills and knowledge of ExxonMobil methods / processes to be successful in meeting all project goals. These courses include both technical and individual effectiveness topics. Assignments for the engineers are selected to facilitate the development of Basic Level and Competent Level Project Management skills. All activities are defined and tracked with an award given for the achievement of these Early Competency Milestones.
Mentorship is the second key component of developing the next generation of project leaders. Mentoring plays an important role in knowledge transfer and wisdom sharing – the ability to expedite the acquisition of experience and skills without having engineers "get old" doing the work is vital. The mentoring program in EMDC assigns each professional with a mentor to help guide him / her both technically and from a career management perspective. Additional methods of mentoring to share experiences and knowledge are utilized. A program called "Ongoing Wisdom and Learning" (OWL) pairs senior project professionals and senior technical professionals with groups of less experienced engineers in an open and candid discussion of their career. OWL topics range from technical subjects to project leadership to career guidance and has proven to be a very popular knowledge transfer technique.
The ultimate method to acquire key project management skills is to include an assignment on a multi-national project. Several projects have "development" positions built into the staffing plans and funding program. These projects combine the two key aspects of the development program: "on-the-job" experiences and strong mentorship.
With a structured and focused approach to the development and preparation of our young talent, ExxonMobil feels it will be able to continue to meet the resource needs for energy projects around the world.
Multivariable Control for Upstream Gas Processing
Authors: Vines Michael 
Published: October 2009

Abstract
A project successfully implemented Multivariable Control (MVC) on three upstream gas processing plants at Longford, Victoria (Australia). This poster includes discussion of MVC theory, field data, plant models, results and conclusions.This poster is applicable to control system design or optimization for upstream production facilities. The project employed MVC on both Turbo-Expander and Lean oil type gas processing trains. The technology, however, is relevant to all constrained oil and gas production facilities. Constraints mitigated by this technology included capacity, product specifications, liquids recovery and equipment imposed limitations.The project enhanced recovery of LPG from natural gas in the three gas plants. The MVC technology created plant models of up to one hundred variables to effectively automate the plants. All plants models had a prediction horizon of two hours and a running frequency of one minute. Economic optimization of the plant uses both linear and quadratic programming. Variables controlled included continuous, intermittent and ramp variables. The MVC project exceeded expectations. The gas plants now recover more LPG from sales gas and the plants" capacity increased. Plant stability, alarm and operator intervention frequencies also improved. Looking forward, there are further attractive opportunities for MVC in Esso's upstream facilities. There are currently plans to apply MVC technology to three light ends fractionation trains at Long Island Point on Westernport Bay (Australia).The Longford Gas Processing facilities are owned by Esso Australia and BHP Billiton in a 50:50 joint venture arrangement. The Operator, Esso Australia Pty Ltd is a subsidiary of the Exxon Mobil Corporation.
Practices Implemented to Achieve Record Performance in Narrow-Margin Drilling in Bass Strait Extended Reach
Authors: Kilroy Dale D. , Dupriest Fred E. 
Published: October 2009

Abstract
This paper discusses the successful application of the operator's drilling performance management process in the Australia Snapper / Moonfish platform drilling program. Snapper performance has historically been limited by shale instability, collapsing coal seams, lost returns, and other narrow margin drilling challenges. The design and execution practices implemented achieved record performance while simultaneously addressing the borehole behaviors that prevented the previous extended reach drilling (ERD) campaign from fully developing significant Moonfish resources.
The operator's performance management process ensures both bit and non-bit limiters, such as borehole instability, are addressed with equal rigor, technology, and workflow. Issues that were previously viewed as trouble costs are treated as drilling performance limiters so solutions are pursued that both eliminate the trouble time and increase footage per day. The performance and borehole management practices implemented by the multifunctional team included:
– Wellbore profile optimization to maximize shale and coal stability; – Specialized rig equipment and operational practices for equivalent circulating density (ECD) management; – Unique coal drilling practices to improve borehole stability; – Application of specialized hole cleaning equipment and surveillance; – Bit and bottomhole assembly (BHA) design to manage borehole quality while maximizing rate of penetration (ROP) and tool life; – Contingency planning for execution flexibility to respond to borehole limiters; – Office and field team training and alignment for flawless execution.
The Moonfish M33a and Moonfish A26a extended reach wells were drilled to total depths of 20,341 and 21,180 ft, respectively. Both wells were completed under budget and are among the highest oil producers in the Bass Strait. The performance management process ensured that the borehole behaviors which had lowered the results of previous wells were addressed, while simultaneously achieving record setting performance.
Interests in the Snapper and Moonfish fields are held by Esso Australia and BHP Billiton in a 50:50 joint venture arrangement. Esso Australia Pty Ltd provides services to the joint venture and is a subsidiary of the Exxon Mobil Corporation.