bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methodology for Integrated Reserves Management: Providing Regulatory Compliance and Improving Decision Making
Authors: Virine Lev , MacDonald Doug 
Published: October 2009

Abstract
Effective corporate reserves management systems allow petroleum companies not only to track reserves and provide input for reporting to regulators, but also to serve as a decision support system. Implementation of such reserves management systems comes with a number of challenges. Regulatory bodies, including the U.S. Security Exchange Commission (SEC), require proper categorization of reserves based on evaluating whether the volumes can be economically recovered in a timely manner. The reserves management system should be able to provide technical and economic volumes based on up-to-date prices, capture and analyze uncertainties in the reserves volumes, provide secure data access and data archiving, and implement an approval and audit process.
To address these challenges, a methodology for integrated reserves management was developed. This methodology comprises three integrated processes: data management, which ensures fast and secure access to reservoir data; economic and technical volume calculation; and a flexible reporting process. The proposed workflow includes the following steps. Reservoirs, as well as prospects, are organized within a corporate hierarchy. In accordance with SEC regulations and SPE/WPC Petroleum Resources Management System guidelines, the data management process captures proven, probable, and possible reserves, as well as discovered and undiscovered resources for different petroleum products and companies with different working interests. Each category of each reservoir is associated with an economic case that contains information about costs, prices, and the fiscal regime. Economic volumes can be calculated based on the results of economic evaluations of the reserves. Uncertainties in reservoir data are captured using multiple scenarios for each reservoir and category. A regional pricing mechanism allows for updating prices for all economic cases at a particular level of the corporate hierarchy. All changes to the economic results data would be recorded and require approval.
This methodology for integrated reserves management provides for the comprehensive management of reserves data in the organization. It allows accurate reserves tracking and reporting to regulatory bodies by mitigating the negative effect of motivational biases. Through a consistent set of categories, scenarios, products, and companies, the proposed workflow provides evaluation and tracking of both technical and economic volumes.
A Game Theoretic Approach to Conflicting and Evolving Stakeholder Preferences in the E&P Industry
Authors: Willigers B. J. A. , Bratvold R. B. , Hausken K. 
Published: October 2009

Abstract
In the high-risk E&P industry, the profit of each stakeholder depends on the strategies of all. The optimal choice for one player may not be optimal for other players, who may opt to prevent it. These characteristics suggest using game theory to model decision situation in the E&P industry. In a business dominated by joint ventures and tight governmental regulation, an understanding of the interests and influence of all stakeholders is particularly important. Although the E&P industry is accustomed to develop complex economic models to obtain insight into the commercial attractiveness of joint ventures, the influence of other stakeholders is often ignored. Each stakeholder must decide how much to invest, in which sequence to make decisions, whether to make decisions before or after the other stakeholders, which decisions to make before versus after technological and organizational uncertainty is resolved, whether to accept or block the designation of one stakeholder as dominant, and whether to accept or block hub placement within one of multiple oil fields. A joint development program of a portfolio of gas fields and its gas processing and export facility has been analyzed using tools from game theory. The focus is on which infrastructure to develop and when. Players’ preferences are functions of equity stakes and expected reserve sizes of the prospects. The analysis provides insight into the preferred development options of the individual players, how preferences change as uncertainty gets resolved, and how much individual players are to gain or lose if certain investment decisions are made. The analysis allows a player (1) to identify under what conditions its objectives are aligned with fellow players and (2) to quantify the maximum amount it can pay to gain support from its fellow players.
Practical Portfolio Simulation: Determining the Precision of a Probability Distribution of a Large Asset Portfolio When the Underlying Project Economics are Captured by a Small Number of Discrete Scenarios
Authors: Willigers B. J. A. 
Published: October 2009

Abstract
One of the great successes of modern financial risk modelling is the application of computing technology to simulate complex continuous probability distributions associated with the value metrics of real-life assets. The Monte Carlo simulation technique is the best known example and is widely applied by economists in the E&P industry. However a Monte Carlo simulation in which project economics are aggregated into a large asset portfolio is rarely undertaken. The main reason is that present computing systems cannot handle the vast amounts of data generated in a Monte Carlo simulation of a large asset portfolio.
A pragmatic solution for this issue might be to approximate the continuous distribution of feasible project outcomes using a small number of probability-weighted discrete scenarios. In a corporate portfolio simulation, a project sample would be drawn from these discrete distributions as opposed to the original continuous distributions. If either a global assumption needs revision or a single asset requires recalculating, the economics of a relatively small number of scenarios would be computed. Thus, there is no need to store or recalculate a large number of outcomes (typically more then 2,000) for each project, as would be required in a conventional Monte Carlo simulation.
A prerequisite for this approach is that the frequently skewed and complex continuous probability distributions of each of the assets can precisely be described by a small number of scenarios. This study documents the level of precision that can be achieved using Swanson's rule and variations thereof. Our analyses suggest that if the P50 is at least 33% greater than the P10, the simulated portfolio mean and standard deviation are within 5% and 15% of the actual values, respectively. The approximation of the lower end of the distribution, i.e., the downside risk of a portfolio, is within 4% even for an extremely asymmetric lognormal distribution.
The proposed portfolio simulation methodology addresses the largely unmet need of corporate managers to improve their understanding of key risk and value drivers and their impact on the performance of a corporate asset portfolio.
A Mechanistic Model for Gas/Liquid Flow in Upward Vertical Annuli
Authors: Yu T. T. , Zhang H.-Q. , Li M. X. , Sarica C. 
Published: October 2009

Abstract
In this study, a mechanistic model is developed to predict flow patterns, pressure gradient and liquid holdup for gas-liquid flow in upward vertical annuli. The flow pattern transition model consists of modified Zhang et al. (2003a) unified model for dispersed bubble flow and annular flow pattern transitions, Caetano (1986) model for bubbly flow transition and modified Kaya et al. (2001) model for slug to churn flow transition. The hydrodynamic models are developed based on the dynamics of slug flow and the film zone is used as the control volume. The two liquid films are taken into account in the annulus slug flow and annular flow model developments. The churn flow model is developed based on the Zhang et al. unified model for pipe flow by using a much shorter slug length.
Real Time Response to Field Corrosion Data Through an Electronic Client Portal Interface Leads to Decreased Well Failures
Authors: Higgins Rocky , Lamb Jim , Szymczak Steve 
Published: October 2009

Abstract
Simple and economical solutions are best affected when open communication exists. In this case study an operator and a specialty chemical supplier worked to reduce both microbial influenced corrosion (MIC) and CO2 corrosion. The process of corrosion mitigation was greatly enhanced through the use of a client portal (CP) by which real time data was released onto the portal, an operating engineer diagnosed the data and remedial measures were taken to reduce the corrosion failure rates.
The number of wells (&gt;3800) and the amount of gas production (&lt;80 mscfd) dictated the use of an economical electronic tool that could hold all pertinent data and manipulate the data in order to make valid assumptions. The CP allowed the field technical staff to input corrosion and failure data directly into the CP database. This would be coupled with an e-mail notification to the project engineer. This e-mail would give an overview of the data analysis as well as a recommendation and cost for remedial action. The engineer could immediately make a cost-benefit decision and respond to the technician. Subsequent monitoring tracked the progress in arresting corrosion.
Those 3800 gas wells produce from depths of 5200 to 8000 ft. Total well tubing failure rates stood at 0.125 FPWY (failures per well per year). This was equal to 475 failures per year. After 18 months of a focused corrosion inhibition program managed through the CP, the tubing failure rate dropped 70% to 0.0375 FPWY. This is a reduction of 330 well failures per year. This resulted in workover cost savings in the millions of dollars per year.
Knowing the problem, arriving at a solution and implementing a remedial program make up the core effort of production engineers and service companies. In this case study, sound problem identification and real time remedial actions served to reduce workovers and related costs. This resulted in a production increase due to the decrease in downtime for workovers. By integrating the CP into the problem solving process, the operator saw improved results more quickly.
Effect of Eccentricity and Rotation on Annular Frictional Pressure Losses With Standoff Devices
Authors: Pratap Singh Ajay , Samuel Robello 
Published: October 2009

Abstract
Pressure drop estimates are critical for components of the drilling process. During drilling and cementing operations, many stand-off devices, such as centralizers, reamers, and turbulators, are widely used. Few studies have explored the pressure losses arising from these attached devices in the drillstring or casing string with eccentricity and rotation, and these pressure losses are assumed to be negligible. Eccentricity between the wellbore and the stand-off devices, rotation, and the complicated geometrical designs of these devices, which relatively irregular and complicated, increase the complexity of the frictional pressure loss calculations. This study examines the effect of the various geometrical parameters of the commonly used devices, eccentricity, and rotation of the devices, flow rate, and rheological properties on the annular pressure loss using c computational fluid dynamics (CFD). For laminar flow, the 3D Navier-Stokes equation is used. The turbulent flow is based on k- model. This paper presents the results of the study of the alteration and effects of various rheology models on the flow profile and annular pressure losses. This parametric study explores the importance of eccentricity and device rotation and presents a simple set of comprehensive equations and guidelines to calculate the pressure losses for commonly used devices. These equations and guidelines are useful in the determination of the number of devices and of their optimum placement in the string. Although the annular pressure loss against these devices may be negligible, at times incremental pressures from the large number of stand-off devices or in a narrow clearance extended reach wells are potentially detrimental to the well. This paper also presents case studies in which the pressure losses were not negligible and stresses the importance of considering the pressure losses encountered using these devices.
A Second-Order Fast-Forward Model for a Gamma-Gamma Density Logging Tool
Authors: Zhou Tong , Miles Jeffrey R. , Case Charles R. , Chiaramonte Joseph M. , Ellis Darwin V. 
Published: October 2009

Abstract
A fast-forward (FF) model for density logging is an essential element for inversion techniques, which may be performed with density data alone or jointly with other measurements. Such models must be both fast and accurate to be of value in the log interpretation process. The environment of high-angle or horizontal (HA/HZ) wells presents a scenario in which forward models have particular promise.
In the 1980s, Watson (1984) developed the technique of differential sensitivity functions to rapidly predict the response of a density logging tool. However, the accuracy of this technique is modest because of the limitations inherent in its linear approximation. In this work, we extend the density sensitivity technique to a second-order approximation. A critical component of this model is the second-order sensitivity functions, which are challenging to calculate. With the aid of the perturbation feature in the MCNP5 code, we use elements of the sensitivity functions at both the first and second orders to approximate the second-order dependences.
We calibrate the model in fully detailed MCNP (Monte Carlo N-particle) simulations of the EcoScope* LWD tool response for a wide range of borehole conditions covering formation electron densities from 1.5 to 3.0 g/cm3; drilling fluids of water, light mud, and heavy barite mud; and standoff values from 0 to 1 in. The maximum deviations between the forward model predictions and MCNP simulations in these diverse borehole conditions are 0.02 g/cm3 for the long-spacing (LS) electron density, 0.03 g/cm3 for the short-spacing (SS) electron density, and 0.04 g/cm3 for the compensated electron density. This combination of accuracy and versatility is a dramatic improvement over the performance of linear sensitivity techniques. We benchmark the model in a simulated HA/HZ well environment and demonstrate performance that is roughly consistent with the calibration. The speed of the improved forward model is almost equivalent to that of the original sensitivity function technique and is six orders of magnitude faster than the Monte Carlo data calculations.
Simulation of Liquid Unloading from a Gas Well with Coiled Tubing Using a Transient Software
Authors: Salim P. , Li J. 
Published: October 2009

Abstract
Unloading gas wells is one of the most common applications for coiled tubing (CT). Despite the large number of jobs completed, fundamental questions about the optimum gas lift rate, run-in-hole speed and how much nitrogen is required remain. This is because the unloading process is not steady state, and the commonly used CT computer simulations can only model steady state flow.
This paper describes transient software that has been developed and used to determine the nitrogen volume and cleaning time required when optimizing the process of liquid unloading from a gas well with CT.
Based on experimental test results with a full scale flow loop, a critical gas velocity model was developed. This model determines how much liquid can be lifted for a given gas rate under varying operating conditions. It also determines the minimum gas rate required for complete liquid unloading. Several examples are presented which illustrate the transient characteristics of the liquid unloading process. A few field cases illustrate the benefits of using the transient model and some problems with conventional design methods.
Injectivity and Gravity Segregation in WAG and SWAG Enhanced Oil Recovery
Authors: Faisal A. , Bisdom K. , Zhumabek B. , Mojaddam Zadeh A. , Rossen W. R. 
Published: October 2009

Abstract
Gas-injection enhanced oil recovery can recover nearly all residual oil where the gas sweeps. Sweep efficiency in these processes is often poor, in large part because of gravity override of gas. Stone and Jenkins presented a model for gravity override in homogeneous reservoirs, showing that the distance gas and water travel before segregation depends directly on injection rate. In cases where injection pressure is limiting, injectivity is key to overcoming gravity override.
Stone assumed continuous co-injection of gas and water as a model for WAG, contending that this is valid as long as slugs mix near the well. This model for co-injection can be extended to relate segregation distance for co-injection processes directly to injection pressure. Injectivity depends on saturations very near the well, however. Therefore, where injection pressure is limiting, this model is pessimistic because injectivity in WAG is greater than in co-injection.
We investigate the increase in injectivity possible with WAG compared to co-injection in 1D and 2D, and the implications for gravity override in 2D, using a range of models for gas and water relative permeabilities. We confirm that the greater injectivity of WAG improves vertical sweep compared to Stone's model when injection pressure is limiting. The greatest improvements occur when slugs violate Stone's assumption: that is, they are too large to mix fully near the well. The increase in injectivity over co-injection is greater for foam than for WAG without foam, because foam has much lower mobility when gas and water flow together.
A similar benefit occurs for "simultaneous water and gas" (SWAG) injection from a single vertical well with water injected higher in the formation than gas. There is a modest benefit to injectivity of injecting water above gas, but far smaller for water-gas flow than that estimated for foam in a previous study.
Designing a Successful Training Class: Benefits and Challenges of Knowledge Transfer from Chemists to Engineers
Authors: Vorderbruggen M. , Woo G. 
Published: October 2009

Abstract
We are currently entering a crisis point in the petroleum industry. The cost and complexity of acquiring hydrocarbons is increasing while the pool of experienced personnel shrinks. It generally takes years of real world experience to create an expert field engineer capable of handling all the factors involved in getting the goods out of the ground. Mentoring and specific on-the-job training/classes helps bring new engineers up to speed, but often these lessons are limited to how and when to do something, especially in the area of chemical products. Understanding the mechanics of their chemical tools empowers engineers.
Lacking both general experience and knowledge about their chemical tools, field engineers require more support both from their supervisors and from their tech support laboratory. These technology support requests translate into time lost, money spent, and customer dissatisfaction. Laboratories are being overrun by requests that would not have been asked a few years ago. To combat this more actual chemistry is being taught to both our new and older engineers. The goal is to replace experience with knowledge, to give them a deeper understanding of what their chemicals are doing to the formation, to the equipment, and to each other. By understanding the why, they can figure out the how and the when.
The benefits of such training are presented in this paper. These include such things as increased confidence, quicker problem solving, improved customer trust, and more. Suggestions on how to teach chemistry to engineers are included. Presentations, homework and tests must be worded in "Engineerese" rather than "Chemical Mumbo-Jumbo" to maximize transfer of knowledge. The end result of all this is improved response times, improved customer relations, reductions in technology support requests, and assorted other benefits. In other words, it makes the company more money.
Simulations of Field Development Planning Help Improve Economics of Heavy-Oil Project
Authors: Teotico Dwight , Schauerte Luke , Griffith James , Schottle Gary , Mehl Ralph 
Published: October 2009

Abstract
When Shell began an ultraheavy-oil development in Alberta, Canada, the field plan was based on manual pad positioning without consideration for surface hazards, trajectory constraints, or injector/producer slot requirements arising from the prefabricated pad configuration.
Shell teams were challenged to investigate alternative field development plans to reduce the initial investment. The volume of wells, surface hazards, trajectory constraints, and pad slot configuration requirements for injector-to-producer ratios made this a formidable task. Shell leveraged the expertise of third-party consultants and powerful software to generate numerous development scenarios, which enabled the Shell staff to focus on the economics of each plan.
An aerial image that delineated surface hazards, an elevation grid, and injector/producer targets were loaded into the 3D subsurface visualization environment of the software to generate pad placement simulations, including trajectory designs. The software followed the Shell planning constraints and avoided all surface hazards.
The analyses were conducted for the highest, lowest, and median number of pads. From these three scenarios, a value analysis was plotted. This value analysis enabled the planning team to identify the optimal surface-to-reservoir configuration and to maximize the value of the field by delivering all of the reservoir targets, while minimizing the number of pads needed to drill. The output also yielded field cumulative values, including total and nominal well length, to support future economic analyses.
The analysis determined that 87 pads maximized the value of the field when 42-well pads were considered. Additional studies determined that when 50-well pads were considered, more than 99% of the planned reservoir targets could be drilled from 72 major and four or fewer minor pads. In either case, a significant reduction from the original 98 pads was realized. Through the combined efforts of Shell engineers and third-party consultants, as well as the use of state-of-the art software, this optimization was completed in only eight worker-weeks.
This paper describes the software and processes used to reduce Shell's estimated field development costs and to minimize the environmental effect of the field by reducing the number of pads required.