bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cognitive Errors in Estimation: Does Anchoring Cause Overconfidence?
Authors: Heywood-Smith A. B. , Welsh M. B. , Begg S. H. 
Published: September 2008

Abstract
Tversky and Kahneman [1] described the biases known as anchoring and overconfidence, respectively, as: the tendency of people to base estimates on any number just seen; and the tendency of people to provide too narrow ranges when estimating the range that an uncertain value might fall within. They also suggested that anchoring might be causing overconfidence if people start by working out their best guess and then adjust from there to get the end points of their range – such that the best guess acts as an anchor. This has passed into the management literature as fact [2, 3] but research on this relationship is actually mixed [4, 5]. This previous research has, however, focused almost exclusively on decision makers making decisions significantly different from those that they normally would.
We present results of a study of 56 oil and gas personnel, designed to demonstrate whether or not anchoring and, specifically, best guesses, cause overconfidence in people when responding to technical scenarios of the sort they might encounter in their real-life roles. These results indicate that having the expert participants give a best guess prior to estimating ranges they were 80% confident would contain the true value (sourced from open access field data) did increase overconfidence as Tversky and Kahneman predicted. Externally provided anchors, however, are shown to have potentially equally strong effects on overconfidence due to their ability to shift the entire range upward or downward. Expertise in regards to the specific parameters being assessed was not found to be related to bias susceptibility.
Finally, we discuss these results, with particular focus on the differences between this study and previous research and how this might account for our different findings, and its implications for confidence interval elicitation and uncertainty representation within the industry.
The Impending Expertise Crisis: New Technology Comes to the Rescue
Authors: Irgens Morten 
Published: September 2008

Description of the Material
While Information and Communication Technology (ICT) is a key enabler of productivity, it is not applied evenly along the information value chain that starts with the capturing and transformation of data into information into analytical models and into decisions. The application of automation drops steadily along the chain, which is unfortunate since it is at the analytical and decision levels where industry specific domain knowledge is needed, in other words where highly experienced knowledge workers, petrotechnical and operational expertise that are increasingly in short supply are needed.
The examples are many, for instance in geological modeling, reservoir planning, reservoir management, and operations planning and management. For instance, making day-to-day rig fleet decisions to meet several key performance goals (such as minimizing rig movements and costs while maximizing utilization and time to market) needs expertise and long-earned experience but still cannot be done well using a manual approach. Still, computerized decision support is almost non-existing.

Application
Recent advances in optimization and artificial intelligence technologies make it possible to support many of the industry's knowledge workers in their tasks, support the most experienced to get more work done with more confidence, and empower the less experienced to tackle tasks that otherwise would have been beyond their capabilities. In operations, they promote decisions complex, dynamic situations that are aligned with key performance goals, and show tangible value of operational decision-making in real time.

Results, Observations and Conclusions
There are many convincing examples both outside and inside the oil and has sector that show reduced planning times, reduced response times, improved work processes, reduction in operational errors, improved "what-if" abilities and decision-making, reduction in operational cost, and increased expected production.

Significant New Contributions
The new technologies and their use in decision support systems increase the productivity of knowledge workers.
Initial State of Stress: The Key to Achieving Long-Term Cement-Sheath Integrity
Authors: Saint-Marc Jérémie , Garnier André , Bois Axel-Pierre 
Published: September 2008

Abstract
Cement sheath design has been undergoing very deep changes for the last five years, mainly thanks to Carbon Capture and Storage (CCS). Indeed, for this application, Operators will have to demonstrate to national regulators that cement sheath can provide zonal isolation not only during the operational phases, but also during another phase: the long term storage. Stakes are as big as the market is, covering CCS plus traditional Oil and Gas market, where harmless operations to the environment know-how has become decisive to open new business opportunities.
To ensure zonal isolation, cement system should be properly designed. It should be correctly placed to ensure it is hardening as per designed. Finally, its mechanical properties should be in adequacy with the successive operations the well is submitted to. Many years dominated by rules of thumb to evaluate cement sheath damage have progressively been replaced by engineered methodologies implemented in software. They can be numerical or analytical based, dealing with mechanics of solid or porous media. What should matter are not their pros or cons, but the correct assessment of their limitations to appreciate simulation results.
To evaluate stresses a material can withstand before failure, constitutive laws and failure criteria are necessary but not sufficient: Initial state of stress is mandatory as it sets the initial distance from failure. After presenting the state of art and its weaknesses to evaluate cement sheath initial state of stress, this paper presents Total's methodology based on porous mechanics where initial state of effective stress results from cement hydration evolution with time under downhole conditions. The final state of stress is the consequence of the initial state plus additional stresses from operations. This methodology has been implemented in Total's dedicated software and has been successfully applied to design cement sheath on various operations worldwide: One detailed in this paper.
Artificial Lift Optimization in the Orito Field
Authors: Williams Sandy , Rozo Rafael , Aya Fernando Pérez , Salazar Hernández José Ismael 
Published: September 2008

Abstract
The Orito field located in the South of Colombia, near the Ecuadorian border has been in production since 1967 and is operated by the Colombian state oil company, Ecopetrol (originally discovered and exploited by Texaco). Petrominerales signed an Incremental Production Contract agreement in April 2001 to participate with Ecopetrol in increasing production from the field. Under the terms of the agreement Petrominerales invest 100% of any development activity in return for a portion of the value of the incremental production.
The Orito reservoir is a multi layered reservoir with three production intervals: Pepino, Villeta and Caballos at depths of 3000 ft TVD and 7000 ft TVD respectively. The reservoirs are depleted and pressures are below the original bubble point pressure. The wells can exhibit a number of challenges for production of fluids using artificial lift including: scale; solids production; high GOR; early high water production; and also very high CO2 (80%). Solids issues are exacerbated on wells where hydraulic frac jobs have been performed, which have resulted in a number of premature failures (less than 14 days) of ESP systems.
Artificial lift has been applied to the field and most lift methods have been tried at some point including Electric Submersible Pumps (ESPs), Rod Pumps, Gaslift, Jet Pumps and Progressing Cavity Pumps (PCPs). This paper will: identify the challenges associated with each lift method in this operating environment; present a lift method selection philosophy; provide details of a pilot program to convert Gas lifted wells to rod pump and; document the key steps taken to evolve an ESP design capable of producing the solids from the fractured wells.
Optimizing Injection Intervals in Vertical and Horizontal Wells for CO2 Sequestration
Authors: Kumar Navanit , Bryant Steven L. 
Published: September 2008

Abstract
Storage in deep saline aquifers is one of most viable options for sequestering anthropogenic CO2. The choice of completion for injection wells -- fully or partially completed vertical well, length of horizontal well -- has significant effect on the eventual trapping of CO2 as well as its potential for leakage. Thus optimization of the completion for a target injection rate can help maximize trapping. The density difference between CO2 and in-situ brine influences the optimization because it causes the pressure difference between wellbore and formation to vary with depth in a CO2 injection well. For a long completed interval in a vertical well, the flux distribution is therefore not uniform. Reinforced by relative permeability effects, this can cause deeper perforations to contribute less to the injection rate. In extreme cases only a fraction of the perforations contribute to injection. The degree of non-uniformity depends on the injection rate. The nonuniformity in turn reduces residual phase trapping because less volume of rock and brine comes in contact with CO2.
Field scale compositional reservoir simulations are carried out to study the plume behavior and CO2 trapping under different injection strategies. A semi-analytical algorithm is discussed to determine the optimum interval of injection. For horizontal wells two competing effects, trapping along the well length vs. trapping along the transverse direction, determine the optimum well length. These effects can be correlated to the dimensionless gravity number during injection. Injection at bottom of aquifer results in better trapping and lower leakage potential. For a given rate, the perforation interval can be calculated so that all the perforations contribute throughout the injection period. In a horizontal well, longer well length increases the trapping in direction of well path but reduces trapping in the transverse direction. Consequently, the benefits of a strategy to maximize injectivity may be offset by the disadvantage of less CO2 entering secure modes of storage.
Distributed Temperature Sensor Measures Temperature Resolution in Real Time
Authors: Hadley M. R. , Kimish R. 
Published: September 2008

Abstract
Fiber-optic distributed temperature sensors (DTSs) are used increasingly in the oil and gas industry to provide temperature logs in real time. Often, users need to know the temperature resolution—the noise level on the measured temperature trace. Temperature resolution can be difficult to specify because it depends on many factors, including averaging period, fiber length, excess attenuation from connectors and splices, and hydrogen darkening of the fiber. To overcome this difficulty, we developed a novel technique to enable the DTS to provide an estimated temperature-resolution trace to accompany each temperature trace. We modeled the noise generated by an optical receiver as constant background noise plus signal-dependent shot noise; parameters of this model were readily measured during system tests. Because the DTS measures the Stokes and anti-Stokes signal level at each point along the fiber, we were then able to calculate the corresponding noise at each point. We modified the subsequent data processing that calculates temperature from these signals to handle a Gaussian model (μ, σ) instead of a single-valued signal. The resulting output provided an estimated temperature-error trace point-by-point along the fiber to accompany each temperature trace. Being derived from the optical signal levels rather than from statistics of the measured temperature, the estimate is not affected by the actual temperature varying with time or along the fiber. However, changes in signal level resulting from changing fiber loss immediately affect the error trace, giving a real-time indication of measurement quality. We have validated the technique against actual temperature noise measurements using a resolution test rig we designed for the purpose. We found good agreement between the estimated and measured temperature resolution, over a range of operating conditions. This new technique, by providing temperature error bounds based on conditions obtaining at the time of measurement, will enable the performance of a DTS to be continuously monitored and will give temperature analysts the information needed to determine the confidence levels of their temperature log interpretations.
Polymer Injection in Deep Offshore Field: The Dalia Angola Case
Authors: Morel D. , Vert M. , Jouenne S. , Nahas E. 
Published: September 2008

Abstract
Whereas on-shore polymer injection may be qualified as a mature EOR technique, considering the hundreds of operations that have been conducted all over the world, only one polymer pilot has been implemented offshore, and none in deep offshore conditions.
A very thorough feasibility study of polymer injection has been made on the Dalia field in Angola, a typical deep-offshore high permeability (&gt;1D as an average) sandstone reservoir containing medium viscosity oil (3 to 7cP under reservoir conditions).
The study has demonstrated that high molecular weight hydrolyzed polyacrylamides could be used under a wide range of salinities covering sea water and a mixture of sea water and produced water.
Additional recoveries in the range of 3 to 7 % can be expected in this particular context of large well-spacing development of a medium viscosity field.
Powder polymer supply is achievable for deep offshore fields either with a specific bulk carrier or using standard international containers to transport big bags (750 kg).
Although the on-deck option is simpler, even in the case where no room is left on the existing FPSO, marine options can be found to safely process the polymer on a barge connected to the FPSO (depending on the sea conditions), but the on-deck option is more simple.
The need for an injectivity pilot is compulsory to demonstrate the operability of the facilities, and the injectivity of the polymer solution. A single well test has been designed and is planned fall 2008 in Luanda on one of the well of the Camelia reservoir.
A skid dedicated to the injectivity test has been designed, assembled and constructed to prepare a mother solution of polymer from powder. Tested in France (no injection), the skid has been shipped to Luanda for installation on the FPSO during summer 2008.
Future of the project will depend on the injectivity tests results and on-going studies on a phased approach.
Production Data Analysis of Shale Gas Reservoirs
Authors: Lewis Adam M. , Hughes Richard G. 
Published: September 2008

Abstract
Unconventional shale gas reservoirs have become a very important part of the resource base throughout the world, but especially in the United States. Production data analysis techniques using various forms of material balance time originally put forth by Palacio and Blasingame (1993) have been proposed and validated in recent publications for a variety of problems (including shale gas and coalbed methane systems) using an adjusted system compressibility function similar to that proposed by Bumb and McKee (1988) to account for adsorbed gas. These modified material balance solutions allow for "type curves" (rate or pressure solutions) to be used in a conventional analysis manner.
The significant challenge in the application of production data analysis for shale gas systems is to determine what the parameter values (analysis results) represent within the context of the inherent complexity of these systems. In this work we propose a slight (but substantive) modification to material balance time and apply the technique to synthetic and field data to assess the capability of this approach for the analysis of production data from gas shales. The formulation we use is that of Cox, et al. (2002) which provides a means for evaluation production data as an equivalent "well test", where we are able to observe characteristic flow regimes in the data and constrain several of the key parameters of interests in shale gas systems. While the field results are difficult to corroborate, the relative magnitudes of the parameters we obtained appear to be reasonable.
Oilfield Trainees Benefit From PDA-Based Applications
Authors: Hughes J. A. , Martin R. , Guerrero J. V. 
Published: September 2008

Abstract
Training departments in today's oilfield industry are faced with the challenge of equipping new employees with the ability to lookup technical information and to perform accurate, routine calculations in a short period of time. Traditional methods include classroom instruction for a group of students who follow along with a personal computer or hardcopy manual. Hardcopy manuals are relatively inexpensive to produce in large quantities, but they are a bulky resource to carry around after the course. Personal computers and laptops are powerful tools, but a plan to assign laptops to individuals or to dedicate a number of computers to a classroom may be cost prohibitive.
Another tool that is becoming more popular is the PDA or PDA-phone. As portable as a cell-phone, powered by a PC-like operating system, and at a cost somewhere between those two cousins, the PDA has gained the attention of trainers and students. Teaming the training department with the software applications group, a plan was conceived to improve and customize an oilfield PC application for use on a PDA. Once that plan became a project, a search began for other, existing PDA software applications that could be useful in the oilfield.
This paper follows the success of one software application that was made available for both PC and PDA, and how students were empowered to give quick, accurate answers to common, difficult questions – with the tap of a stylus. It also outlines the direct benefits to the training department, trainees, employer, and ultimately to the customer. Finally, the paper evaluates the cost-benefit of PDA ownership and the potential for other applications or information to be made available for the PDA.
Evaluation of Reservoir Connectivity and Development Recovery Strategies in Monument Butte Field, Utah
Authors: Wang Jianwei , Abiazie Joseph , McVay Duane A. , Ayers Walter B. 
Published: September 2008

Abstract
Monument Butte field produces oil from 22 commingled sandstone reservoirs across a 2200-ft interval of the Green River formation. Total (primary and secondary) recovery is less than 10% of the OOIP. Green River formation sands are lenticular, lacustrine fluvial-deltaic units that have limited aerial extent and vertical communication, resulting in poor interwell connectivity. Moreover, the reservoirs sands have low permeability. To determine interwell connectivity and to identify methods to improve oil recovery, we conducted detailed reservoir characterization and simulation studies in a pilot area of Monument Butte field.
We built a 3D geostatistical model and ranked geological realizations using production history matching with streamline simulation. Detailed petrophysical and geological modeling were used to quantify interwell connectivity of sands as a function of well spacing. Studies of interwell connectivity were also used to identify flow barriers that we applied in upscaled reservoir simulation models to better represent interwell connectivity. A combination of manual and assisted history matching methods was used to calibrate the reservoir model. Primary, secondary, and tertiary development strategies were then evaluated for future optimization of oil recovery for new developing areas in Monument Butte field.
This study yielded a reservoir model much improved over those of previous studies. A good history match was obtained for most wells, despite the complexity of this stacked, heterogeneous reservoir system. Simulation results indicate that interwell connectivity has the greatest impact on reservoir performance. Interwell connectivity was demonstrated for only major sands, and interwell connectivity increases as well spacing decreases for these sands. A pilot 20-acre infill drilling study is needed to verify this conclusion. The overall connectivity for the combined 22 zones is 0.056 (connected adjacent well pairs divided by total adjacent well pairs). The connectivities for major sand zones evaluated by history matching are 0.65, 0.16, 0.23, and 0.01 for the D1 sand, C sands, A sands, and LODC sands, respectively. Simulation results indicate that reservoir performance can potentially be improved with various reservoir management strategies, including infill drilling. For new development areas, water flooding should start as soon as possible (within 6 months). Tertiary recovery methods may have potential in the Monument Butte field, given the low recovery efficiencies for primary and secondary recovery. Water-alternating-CO2 injection appears to be superior to other tertiary recovery methods. Further evaluation and piloting of tertiary methods is required, given the connectivity risk. The target area study results can be used to guide the development of other parts of the large Monument Butte field.
Dynamic Decision Trees as an Alternative for Real Options Valuation
Authors: Galvis C. F. , Bravo O. 
Published: September 2008

Abstract
This paper suggests a model to incorporate Real Options Valuation (ROV) to the decision-making process concerning E&P projects, through a robust, flexible and innovative technique: Dynamic Decision Trees (DDT). The proposed approach integrates Discounted Cash Flow (DCF), Decision Trees and Montecarlo Simulation into one practical methodology much easier to utilize and understand than the traditional binomial lattices. The DDT model is presented using as framework the valuation of developing the Sardinata field in Colombia.
Given that the Net Present Value (NPV) of the Discounted Cash Flow associated to the project was negative and close to break-even, the decision to execute it was delayed, despite management's good feelings regarding production potential and high oil prices. However, by modeling the project via DDT, it was possible to calculate the value inherent in project's uncertainty and managerial flexibility, allowing decision-makers to apply the Real Options concept and make better informed decisions. Consequently, the decisions to obtain 3D seismic and drill 25 infill wells were triggered.
Real Options are a direct extension of Financial Options, as well as its most common valuation methods. Therefore, the assumptions upon which this theory is built must also apply for Real Options Valuation. However, this does not occur when using these valuation methods in highly risky projects such as those of the Oil & Gas Industry. The authors offer an alternative solution for valuing real options in E&P projects, yet still complying with the assumptions that support the theory.
Through the use of DDT it was possible to avoid limitations in volatility estimation and option valuation, leading to a far-reaching and more accurate application of the theory. DDT proved to be a simpler, more robust, and more flexible manner for valuing real options than the traditional binomial lattices when dealing with E&P projects.