bluuebunny/crossref_metadata_2025_split huggingface dataset:
Web-Based Hosting of Multiassets and Multiusers Production Workflows
Authors: Theuveny B. , Nieten J. , Kosmala A. , Sagar R. , Donovan M. , Cosad C. 
Published: December 2007

Abstract
Real Time production workflows introduce significant changes to the production management practices. The introduction of new technologies such as affordable satellite communication, local field area networks, global connectivity to the internet, collaborative workspace (both virtual and actual war room concepts) and data mining agents have all contributed a number of enhancements in the production arena. Although the early gains obtained during the implementation of real time workflows can be as large as increase of 50% of production in some assets, the long term gains are typically in the order of 3 to 8 %. The paper provides a number of approaches to quantify the value of enabling traditional production processes with real time information and activities.
This paper also presents some inroads and lessons learnt in terms of the deployment of a new breed of real time services offered to support daily production management activities. These Activities include: Electrical Submersible Pump (ESP) monitoring and surveillance, real time productivity monitoring based on interpretation of downhole sensors and multiphase flowmeters. The analysis of over 600 installations worldwide provide insights of solutions and opportunities in varying environments covering a wide range of challenges such as North American cost sensitive context to Colombian security conscious field operations and harsh environment deployments.
Among the main challenges of the real time infrastructure for the production world, is the infamous management of legacy systems (old and aging SCADA systems, archaic instrumentation, challenging production sharing agreement financial terms). The paper offers a number of recommendations, and establishes a methodology to the deployment of workflows power by real time information.
A short discussion of the relative benefits of hosted services versus fully integrated solutions housed within the asset IT infrastructure provides key elements to operators to decide what would be the long term cost effective solution to be selected for a given asset.
Transport of Ethane-Rich Gases Using an Extensive Gas Pipeline System
Authors: Zarei Raed , Alvarez Carlos 
Published: December 2007

Abstract
The paper discusses a field case involving the transportation of ethane-rich gas streams. The streams were re-routed using an extensive pipeline network system with the objective of increasing ethane recovery. The changes presented significant operational challenges for managing large amounts of liquids accumulated in the pipeline system and delivering production smoothly to process.
Prior to re-routing the gas streams, transient multiphase flow simulations were performed to establish pipeline liquid accumulation, minimum and maximum allowable rates, pressure losses, and pipe scraping operations at different velocities. A later comparison between calculations and actual field performance showed a good match.
Dropping the planned refrigeration system for the gas pipeline system achieved significant capital savings. Ultimately, re-routing of the ethane rich gas allowed additional recovery equivalent to approximately 20 mmscfd with no additional capital investment.
A modern transient multiphase flow simulator proved useful in testing and setting up field operational changes prior to implementation, and managing extensive pipeline systems with severe liquid accumulation.
Methodology For Manipulation Of Wellhead Pressure Control For The Purpose Of Recovering Gas To Process In Underbalanced Drilling Applications
Authors: Graham R. A. , Culen M. S. 
Published: December 2007

Abstract
An updated approach to underbalanced well design has been developed with a view to enhancing the ability to recover gas to process (pipeline, gas plant, offset well, temporary storage, etc.). With the growing trend towards reducing greenhouse gas emissions, this technique evaluates the range of anticipated operating conditions (gas inflow and wellhead pressures) as a function of liquid and gas injection rates and the productivity index of the reservoir.
Typically, underbalanced drilling projects have been designed to minimize gas injection requirements down the drill string or annulus (concentric injection or parasite injection) for equipment efficiency and erosional considerations. This means that wellhead pressure is typically kept to a minimum, maintaining sufficient pressure to aid in shipping liquids from the separator. An exception to this is where elevated wellhead pressures may be desired to increase bottom hole pressure and reduce inflow from the reservoir, however, the objective in this instance is to control bottom hole pressure.
The typical approach to designing for underbalanced drilling parameters is normally based upon a graph of bottom hole pressure on the y-axis as a function of gas rate on the x-axis. It is usual to overlay the hole cleaning parameters – based upon minimum annular liquid velocity – and minimum and maximum equivalent flow rates through the motor. In addition, the target bottom hole circulating pressure limitations (usually derived as a function of reservoir pressure) define the operating window from which the required liquid and gas injection rates can be determined.
This updated approach addresses many issues such as equipment sizing and expected production rates while drilling through to effective pressure management at surface to aid in well stability. Furthermore, the approach lays down the fundamental groundwork for future underbalanced control algorithms.
Applying Advanced Fracture Diagnostics to Optimize Fracture Stimulation in Coalbed Methane Reservoirs: Case History of Two Fields in the Rocky Mountains
Authors: Wolhart S. L. , Stutz H. L. , Mayerhofer M. J. 
Published: December 2007

Abstract
Coalbed methane development continues to increase accounting for 8% of U.S. gas production in 2002. Many coalbed methane wells must be stimulated by hydraulic fracturing in order to achieve economic production rates. However, optimizing hydraulic fracture treatments in coalbed methane is difficult and advanced diagnostics can aid in the process. This paper discusses completion optimization for two coalbed methane reservoirs in the Rocky Mountains. Hydraulic fracture mapping was performed with treatment well tiltmeters on several wells in each reservoir. Treatment well tiltmeter fracture mapping is an emerging technology to optimize development of low permeability reservoirs. The fracture height measured with the treatment well tools was used to calibrate a fracture model for each field. The fracture mapping, calibrated model and on-site diagnostics were used to modify completion and stimulation strategy in these fields.
The completion strategy for both fields was fairly similar early on. Fracture mapping showed height growth through several coal stringers in both areas. There was some degree of containment in the laminated lithology bounding the pay packages but one field was more prone to height growth at higher pumping rates. Job size and injection rate were drastically reduced in this field because of the height growth tendencies and the presence of nearby water sands. This paper shows how the application of fracture diagnostics and engineering can reduce costs and help avoid costly errors. One example is shown with advanced diagnostics applied early in the development of a field and another example is shown with diagnostics applied after some development has already occurred. The differences in hydraulic fracture geometry that can occur between areas are also shown and how they create changes in completion strategy.
Economics for Enhanced Coalbed Methane (ECBM) and CO2 Sequestration with Horizontal Wells
Authors: Jikich Sinisha A. , Bromhal Grant S. , Sams W. Neal , Gorucu F. Burcu , Ertekin Turgay , Smith Duane H. 
Published: December 2007

Abstract
Injection of carbon dioxide into unmineable coal seams is a promising technology for reducing anthropogenic gas emissions and increasing ultimate recovery of coalbed methane. The combination of incremental methane produced and possible tax incentives might compensate for the costs associated with CO2 injection.
Currently the U.S. Department of Energy (DOE) is co-funding a pilot CO2 sequestration and enhanced coalbed methane (ECBM) project in the Appalachian Basin, in a thin coal seam. Horizontal wells have been drilled in the seam to increase CO2 injectivity and methane production rate. Previously, the reservoir simulations we performed for the planned pilot pattern indicated an optimum length for the horizontal injectors to maximize methane recovery and CO2 storage. By varying operational parameters such as time of primary production, injector length, injection pressure, injection timing, and production well pressure, we can evaluate different production alternatives to determine possible tradeoffs between optimum recovery of methane and CO2 sequestration, as defined by the amounts of the gases injected or produced.
The economics of an ECMB/sequestration project using horizontal wells are sensitive to the design parameters. In commercial practice it is necessary to select a design that maximizes the economic return. In the work presented here, net present value (NPV) was used to optimize the economics of the project. The evaluation used actual design parameters, current costs to equip the field for CO2 injection, and operating costs in the actual price range of ongoing projects: coalbed methane (CBM) and CO2 enhanced oil recovery. Methane recovery and CO2 injection data were obtained from our reservoir simulations. The economic impact of tax incentives was also considered in the analysis.
The analysis demonstrates the significance of reservoir size, proper design and implementation, and tax incentives for economic viability of projects for enhanced coalbed methane production and coalseam sequestration.
Modeling of Experiments on Water Vaporization for Gas Injection
Authors: Zuluaga Elizabeth , Lake Larry W. 
Published: December 2007

Abstract
Dry gas injected into wells will vaporize water from the near wellbore zone. The vaporization starts from the well and proceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine, but water will be vaporized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus, there are different mechanisms for injection and production.
For both injection and production, vaporization concentrates solids in the brine. When sufficiently concentrated, minerals will precipitate into the formation. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem for dry gas injection.
Experiments have been performed previously to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve, 2003). The experiments were performed by injecting dry methane into core samples that contained immobile water. This would represent water vaporization in a gas injector.
Effluent water concentration curves showed two vaporization periods: A constant rate period and a falling rate period. The existence of a constant rate period means that the mass transfer within the core is occurring at conditions of local equilibrium. We interpret the falling rate period as the result of a moving capillary transition zone in which the amount of water vaporized decreases slowly because of capillary pressure effects.
We interpret the vaporization results with two traveling wave solutions. The first, which can be solved analytically, assumes that the capillary diffusion coefficient, D, the volume fraction of water in the gas phase, Cwg, and the volume fraction of water in the water phase Cww are constant. For this case, the results of the traveling wave are optimized with the capillary diffusion coefficient D to match the laboratory experiments. The second traveling wave solution must be solved through numerical integration. In this case, the capillary pressure and relative permeability scaling exponents are fitted to match the laboratory experiments. The fitting provides insights into the nature of wetting phase flow at small saturation.
Internal Repair of Pipeline Leaks Using Pressure-Activated Sealant
Authors: Rusch David W. , Romano Michael 
Published: December 2007

Abstract
A cost-effective method of internally repairing pipeline leaks has been developed that – in many instances – eliminates the need for expensive and risky external mechanical repairs.
By delivering a pressure-activated sealant between two pigs to a leak site and pressure activating the sealant to polymerize as a flexible solid within the leak path, it is possible to internally repair pipeline leaks without the need for excavating or replacing defective sections with minor leaks.
Perforating for Injection Wells
Authors: Folse Kent , Dupont Richard , Malbrough Joshua , Chow Christopher 
Published: December 2007

Abstract
Optimizing the design of injection processes in sand control (i.e., conventional gravel pack and frac-pack) and stimulated completions as well as in injection wells has been a primary goal in selecting methods to improve cost and operational efficiency. It is well accepted that perforating with shaped-charge jet explosives has had a large impact on the efficiency of oil and gas completions in cased wells. However, accurate predicting of the impact of different perforating systems or operations can be difficult, as there are many variables in the process that can not be easily quantified; therefore, modeling the detailed physics of the process is complex.
This paper examines perforating as it relates to injection wells and/or injection processes. Experiments using field shaped-charge explosives were conducted under a variety of conditions with different cores to quantify injectivity compared to productivity. Results from the laboratory experiments were then compared to field data for validation. New knowledge and insights are gained to better understand and to optimize the design of injection processes in sand control completions and completion processes in injection wells.
A Coalbed Methane Reservoir Simulator Designed and Developed for the Independent Producers
Authors: Jalali Jalal , Mohaghegh Shahab D. 
Published: December 2007

Abstract
There are many coalbed methane reservoir simulators in the market. The two most important characteristics of these models that, for all practical purposes, put them out of the reach of most of the independent producers are their price and complexity of use. In order to effectively use these commercial simulators, the average CBM producer must have at least one dedicated engineer, preferably with a graduate degree, on the staff that is willing and capable of performing effective modeling and simulation. It seems that the commercial simulation packages have been designed for majors, large independents and consultants. This leaves the majority of independent producers that are in the business of CBM production in a class by themselves. The model that is presented in this paper targets this class of CBM producers.
A new CBM reservoir simulator has been developed at West Virginia University in order to address this specific need of our industry, specifically in the northeast of the United States where new interests in coalbed methane have been growing steadily. The WVU CBM model uses a previously developed legacy code by King and Ertekin at PSU as its point of departure. The nearly twenty year old King & Ertekin's formulation which has been verified and proven to be robust, forms the foundation of WVU CBM model. The WVU CBM model is PC-Windows based and has a user friendly and graphical interface. The PSU model used a commercial solver that if was used in this model it would have made it prohibitively expensive for the independent producers. A new solver was developed and is used in this model. The new WVU CBM model is a single-well radial model with a graphical input interface that includes default values for the Pittsburgh coal for all parameters in case some of the values are unavailable. It generates graphical outputs in form of gas and water production rate vs. time, cumulative production vs. time, pressure, saturation and gas desorption distribution throughout the reservoir. It allows for production scheduling for detail history matching process. It lets the user to plan hundreds of runs in the form of a batch file that can be run over night.
The model has a unique feature that allows user to provide input parameters in the form of probability distribution functions with minimum, maximum, and, if they choose, most likely values instead of crisp numbers. The output in such cases will be probability distribution functions rather than crisp numbers. The WVU CBM model will be available to the industry through our web sites.
New PDC Bit Technology, Improved Drillability Analysis, and Operational Practices Improve Drilling Performance in Hard and Highly Heterogeneous Applications
Authors: Mensa-Wilmot Graham , Douglas Charles , Schell Eddie 
Published: December 2007

Abstract
The application envelopes of PDC bits have conventionally been defined by rock hardness. Although technologies1,2, 3, 4 aimed at improving PDC bit efficiencies in challenging drilling environments continue to be developed, performances in such applications still lack consistency. It has become apparent, from drilling performance evaluations, that formation hardness alone can not be used to categorize PDC bits.
In some instances, PDC bit performances have varied profoundly across given fields, even when formation types and tops, lithologies and hardness have been determined to be comparable. These performance differences, which continue to baffle the industry, amplify with increasing formation heterogeneity especially in hard rock environments.
This paper will present a three part process, which has been developed to address the challenges described above. First a new approach, which characterizes rocks by their drilling difficulty, is used to establish field trends. Considering offsets, or anticipated performance requirements, bit development and/or selection is done with the aid of two new parameters – stress and durability equivalencies. Finally, operational practices aimed at enhancing the effectiveness of this new process are developed and implemented. This paper will quantify and discuss the individual and combined effects of these processes.
Analytical, laboratory and field data, showing the effectiveness of this new methodology, will be presented.
Protecting Pipelines, Storage Fields, Wells and Other Facilities From Encroachments
Authors: Abbott Kevin C. , Bagnell Nicolle R. Snyder 
Published: December 2007

Abstract
Protecting pipelines, storage fields, wells and other facilities such as compressor stations, measurement and regulation stations and meters from encroachments is critical to all participants in today's natural gas industry. Unless this basic infrastructure is protected, the industry cannot fulfill its fundamental mission of delivering natural gas safely and reliably.
In the past, most major pipelines, wells, and surface facilities were located in remote locations and there was little chance of encroachments on those facilities. Today, however, the proliferation of development in and around major population centers has combined with the higher demand for natural gas service in those areas to increase the potential for conflict. At the same time, stricter regulation of pipeline has required natural gas pipeline companies to be ever more vigilant in protecting their facilities.1
This paper will explore what natural gas companies can do to protect their facilities and how the courts have reacted to those efforts.
Advances in the Production Mechanism Diagnosis of Gas Reservoirs through Material Balance Studies
Authors: Oscar Morán O. , Fernando Samaniego V. , Jorge A. Arévalo V. 
Published: December 2007

Abstract
The concept of diagnosis used in this paper has a similar meaning as it used in well test analysis, and essentially refers to the identification, and its sequence as the exploitation time increases, of the production mechanisms of a gas reservoir.
This paper discusses an approach for the diagnosis of the gas reservoir production mechanism, derived from a general gas material balance equation (GGMBE), that considers the possibility that the reservoir could be naturally fractured: z/p vs (z/p)Gp. This diagnosis of the production mechanisms can be especially very useful for conditions where the reservoir characterization is limited. Once this diagnosis process has been accomplished, the original gas in place (OGIP) can be more accurately estimated through the present methodology, especially when combined with the available techniques (specific graphs, such as p/z vs Gp, Havlena and Odeh, etc.). In addition, this method allows the estimation of the cumulative effective compressibility, ce(p), of the associated water volume ratio, M, and of the water influx, We(t). The new method is illustrated through its application to the most discussed gas field behavior examples published in the literature, among them the McEwen's water influx case, the volumetric Begg's case and the overpressured Duggan's Anderson L case.
Drilling Underbalanced in Hassi Messaoud
Authors: Moore D. D. , Bencheikh A. , Chopty J. R. 
Published: December 2007

Abstract
The Hassi Messaoud field, discovered in 1956, is the largest oilfield in Algeria, covering about 2000 km2 and currently including over 1000 wells. Production is from a thick, Cambrian age sandstone, at a vertical depth of approximately 3400 m. This sandstone is extremely hard, abrasive, and slow to drill. Sonatrach introduced Underbalanced Drilling (UBD), primarily in an effort to improve penetration rates, though the possibility of other benefits from UBD experienced elsewhere, such as improved production characteristics, was also acknowledged. Several factors requiring special consideration were addressed from candidate selection to equipment and procedures. The combination of depth and required bottomhole circulating pressure approach the limits of what is achievable with concentric gas injection, the only locally available UBD technology. The methods used in conducting this project are good examples of how to approach and successfully execute such a project.