bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Simulator Comparison Study for Enhanced Coalbed Methane Recovery Processes, Part I: Pure Carbon Dioxide Injection
Authors: Law David H.-S. , van der Meer L. G. H. , Gunter W. D. 
Published: December 2007

Abstract
The injection of carbon dioxide (CO2) in deep, unmineablecoalbeds can enhance the recovery of coalbed methane (CBM) and at the same timeit is a very attractive option for geologic CO2 storage asCO2 is strongly adsorbed onto the coal.
Existing CBM numerical simulators which are developed for the primary CBMrecovery process, have many important features such as: (1) a dual porositysystem; (2) Darcy flow in the natural fracture system; (3) pure gas diffusionand adsorption in the primary porosity system; and (4) coal shrinkage due togas desorption; taken into consideration. However, process mechanisms becomemore complex with CO2 injection. Additional features such as: (1)coal swelling due to CO2 adsorption on coal; (2) mixed gasadsorption; (3) mixed gas diffusion; and (4) non-isothermal effect for gasinjection; have to be considered.
This paper describes the first part of a comparison study between numericalsimulators for enhanced coalbed methane (ECBM) recovery with pureCO2 injection. The problems selected for comparison are intended toexercise many of the features of CBM simulators that are of practical andtheoretical interest and to identify areas of improvement for modeling of theECBM process. The first problem set deals with a single well test withCO2 injection and the second problem set deals with ECBM recoveryprocess with CO2 injection in an inverted five-spot pattern.
Simplified Correlations for Hydrocarbon Gas Viscosity and Gas Density – Validation and Correlation of Behavior Using a Large-Scale Database
Authors: Londono F. E. , Archer R. A. , Blasingame T. A. 
Published: December 2007

Abstract
The focus of this work is the behavior of gas viscosity and gas density for hydrocarbon gas mixtures. The viscosity of hydro-carbon gases is a function of pressure, temperature, density, and molecular weight, while the gas density is a function of pressure, temperature, and molecular weight. This work presents new approaches for the prediction of gas viscosity and gas density for hydrocarbon gases over practical ranges of pressure, temperature and composition. These correlations can be used for any hydrocarbon gas production or transportation operations.
In this work we created an extensive database of measured gas viscosity and gas density (&gt;5000 points for gas viscosity and &gt;8000 points for gas density). This database was used to evaluate existing models for gas viscosity and gas density. In this work we provide new models for gas density and gas viscosity, as well as optimization of existing models using this database.
The objectives of this research are: To create a large-scale database of measured gas viscosity and gas density data which contains all of the in-formation required to establish the applicability of various models for gas density and gas viscosity over a wide range of pressures and temperatures.To evaluate a number of existing models for gas viscosity and gas density.To develop new models for gas viscosity and gas density using our research database — these models are proposed, validated, and presented graphically.
For this study, we created a large-scale database of gas properties using existing sources available in the literature. Our data-base includes: composition, viscosity, density, temperature, pressure, pseudoreduced properties and the gas compressibility factor. We use this database to evaluate the applicability of the existing models used to estimate hydrocarbon gas viscosity and gas density (or more specifically, the z-factor). Finally, we provide new models and calculation procedures for estimating hydrocarbon gas viscosity and we also provide new optimizations of the existing equations-of-state (EOS) typically used for the calculation of the gas z-factor.
Integrated Modeling of a Field of Wells—An Evaluation of Western Shallow Oil Zone Completion Practices in the Elk Hills Field, Kern County, California
Authors: Callison Dave , Jones Joe , Shelley Bob , Lockman Rusty 
Published: December 2007

Abstract
A fresh or different perspective is essential to discovering new opportunity for successful field development. This paper summarizes a new type of analysis applied to reservoir, well, completion, and fracture stimulation information for the western shallow oil zone (WSOZ) completions in the Elk Hills Field of Kern County, California. The focus of this analysis was to identify parameters that are indicators of reservoir quality and to evaluate the effectiveness of stimulation/completion methods.
This evaluation used unstructured modeling methods supported by the use of standard engineering tools. Of particular interest was the identification of ways to help enhance the economic success of WSOZ completions at Elk Hills. When the information derived from this study was applied to new completions, well economics improved significantly. This improved success has justified additional infield development drilling. Specific objectives included:Developing a model or tool to predict production for wells in the fieldIdentifying parameters that are indicators of reservoir qualityDetermining which completion/stimulation methods and designs have been successful in the past and using this information to improve the success of future completionsUsing the above understandings to improve fracture candidate selection
A general objective was to test the applicability and benefits of holistic modeling methods, such as using artificial neural network (ANN) technology to model WSOZ wells at Elk Hills. In this instance, ANN modeling was used to differentiate the contributions of reservoir quality from the stimulation/completion method on a given well production result. The understanding derived from this study influenced decisions about pay selection, perforating practices, operational procedures, and stimulation fluid and proppant selection.
The Application of Pressure Isolated Multilateral Junction Improves Economics in Offshore Arabian Gulf
Authors: DeMong Karl , Al-Yami Hussein , Lambe Steven 
Published: December 2007

Abstract
The benefits of drilling multilateral wells in slot limited applications such as offshore platforms are well known. Using multilateral technology in a project can minimize facility costs, reduce drilling costs, maximize reservoir exposure and reach secondary targets. When a project is in the planning stage, there is often resistance to multilateral concepts due to a perception of increased operational risks and doubts that the economic benefits will be fully realized. The key to broadening the implementation of this technology is matching actual opportunities with robust, reliable multilateral systems.
In a project in the Arabian Gulf, an operator implemented the use of Technical Committee for the Advancement of Multi Laterals (TAML) level 5 pressure isolated junction systems with through tubing access to develop a single reservoir in a slot limited application. Both pre-milled and retrievable oriented milled window technology were used as a platform for the completed junction. This illuminates how this technology is used in new or existing wells.
A study of how the unique operational issues were solved illuminates the success of the application of this technology to this project. It will also provide an insight into best practices to aid in the planning and execution of other complex well types. Operational and economic results, as compared to single lateral wells on the same platform, provide insight into many advantages realized in this program.
Examination of Cement and Casing Evaluation Logs, a Field Study
Authors: Frisch Gary , O'Mahoney Larry , Mandal Bata 
Published: December 2007

Abstract
An analysis was undertaken to appraise the effectiveness of using the current logging program to evaluate both casing damage and the cement sheath for a major offshore field. The standard program consisted of a Conventional Bond Log (CBL) and rotating ultrasonic tool run in tandem. Four different casing sizes were evaluated, running from 5.5-in., 23 lb. to 9 5/8-in., lb. and including several different alloys ranging from standard steel to chrome alloys. These logs were acquired over several years. The suite of logs involved upgrades to both the acquisition software and to the rotating ultrasonic tools. These changes affected both the casing inspection and cement evaluation modes.
The overall correlation between the rotating ultrasonic log and the CBL log are excellent as shown in exa mples that will be provided. These logs demonstrate how two different cement evaluation tools complement each other to provide a detailed and complete zonal isolation study. The rotating ultrasonic may indicate channels while the CBL may not provide a direct indication of the channel.
Likewise, the rotating ultrasonic shows excellent repeatability in both casing inspection and cement evaluation data. Casing inspection consists of both internal diameter and casing thickness. While the casing size will affect the cement evaluation, the rotating ultrasonic tool requires careful head and frequency selection to optimize the casing inspection mode. The repeatability and accuracy of the casing inspection data is astonishing and exceeds that of any other casing inspection device in use today.
Several logs that will be described have questionable features, but some of these features appear to be caused by well conditions. In particular, it is believed that casing in contact with either the formation and/or outer casing string caused erroneous readings in both the cement and casing inspection data. This perceived wellbore artifact also appears to create errors in the CBL for cement evaluation. Casing centralizers and/or lack of centralizers are easily recognized on both the casing inspection data and cement evaluation.
In another case, improper head selection for the ultrasonic device generated an erroneous log. Changes were made to the real time quality control process on the device to prevent erroneous logging from happening thereafter.
Analytical Models for Design of Wellpath and BHA
Authors: Aadnoy Bernt S. , Huusgaard Petur P. 
Published: December 2007

Abstract
Directional drilling is costly. Roundtrips of the entire drillstring is often required to implement directional corrections. The directional driller is a specialist using numerical simulators for analysis. To simplify this, work was undertaken to derive simple analytical equations that would replace the simulators, and, to gain further insight into the controlling mechanisms.
The first part of the paper investigate the minimum weight and length of the BHA. Performing a force balance, including torque and drag (Coulomb friction), minimum BHA length are obtained both for rotating and sliding mode.
The second part of the paper is based on indeterminate beam theory. Explicit equations are derived to model the two key mechanisms; weight (gravity) and geometry (BHA deflection). The equations clearly shows that the build-rate depends on wellbore inclination. Using the insight from the models it is shown that a catenary (minimum friction) wellpath can be approximated by proper stabilizer placement, and can be drilled without altering the BHA, that is, no correction trips are required.
Several practical examples are provided, including a well drilled to 110 degrees inclination. It is shown that buckling defines the maximum bit force, and also shown is the design of such an operation, including optimal placement of stabilizers and drillcollars.
Hardbanding for Drilling Unconsolidated Sand Reservoirs
Authors: Barrios Juan , Alonso Claudine , Pedersen Eric , Bachelot Alain , Broucke Alain 
Published: December 2007

Abstract
Hardbanding materials are used to protect tool joint drillpipe against wear in drilling operations. Hardbanding shall resist wear in openhole conditions with a minimum damage to upper casing. Laying down drillpipe for hardbanding repair can significantly increase rig time and tubular costs. All hardbanding products applied for Sincor were wearing out completely after drilling 15,000 ft in 50 hours in the reservoir. It was necessary to search for new hardbanding alternatives with an extended lifetime. A field evaluation program was designed to compare wear resistance of different commercial hardbanding materials and to evaluate new techniques for welding tungsten carbide pellets with alloying wires and for testing of tungsten carbide spheres being laser applied. Hardbanding products were selected upon analysis of wear mechanisms occurring in drillpipe while drilling horizontal wells in Sincor. Wear resistance was monitored in terms of cumulative drilled footage until gauging complete wear of hardbanding on tooljoints. One of the newly developed hardbanding products was finally selected as the best option after considering its superior wear resistance, minimum expected casing damage, and moderate cost. This is the first reported successful application of tungsten carbide pellets welded within a hard matrix provided by an alloy wire for hardbanding purposes.
The Impact of HCl to HF Ratio on Hydrated Silica Formation During the Acidizing of a High Temperature Sandstone Gas Reservoir in Saudi Arabia
Authors: Thomas R. L. , Nasr-El-Din H. A. , Mehta S. , Hilab V. , Lynn J. D. 
Published: December 2007

Abstract
Since the mid-1990s the use of HCl/HF at a weight ratio of 9 to 1 has been used extensively in field operations to minimize precipitation during sandstone acidizing. Although it was perceived as applying to all secondary reactions, it was originally directed at fluosilicates. Field case histories have been reported to support this recommendation. However, little evidence is available to justify the use of 9 wt% HCl – 1 wt% HF (9-1 mud acid) at the 300°F temperature exhibited in the Jauf reservoir. Thus, a laboratory study incorporating HF systems with various HCl to HF ratios was performed to quantify the amount of precipitation in Jauf reservoir cores at 300°F, and the impact on permeability. The focus of this paper is on the silicon (Si) and aluminum (Al) concentrations in core flow test effluents that were corrected for post-core test precipitation of reaction products in collection tubes. This technique accounts for the Si and Al in the liquid and solid phases of core flow effluents.
The literature teaches that the Si/Al molar ratio of a core test effluent can be used as a diagnostic tool to quantify hydrated silica formation. It is assumed that hydrated silica precipitation increases as the Si/Al ratio decreases from the theoretical value as a result of a greater completion of the secondary and tertiary reactions of HF with silt and clays. The results of this study on short Jauf reservoir and Berea cores at 300°F indicate that cores treated with 9 wt% HCl – 1 wt% HF yield a lower Si/Al ratio than observed with 12 wt% HCl – 3 wt% HF. However, cores treated with 4 wt% HCl – 1 wt% HF yield the lowest Si/Al ratio. The Si/Al ratio is not the only diagnostic tool required to determine the amount of hydrated silica precipitation i.e. factors including the mud acid flow pattern (matrix vs. channel) have a significant impact on the Si/Al ratio.
Core flow test results are presented for acetic acid preflush followed by various mud acid systems. All cores were stimulated, although hydrated silica formed in all core tests and aluminum fluoride precipitated in core tests using 4-1 mud acid formulations at 300°F.
Filtercake Cleanup Techniques for Openhole Water Injectors with Sand Control: Lessons from Laboratory Experiments and Recommendations for Field Practices
Authors: Parlar M. , Brady M. E. , Morris L. , Ali S. A. , Twynam A. , Newberry P. , Svoboda C. , Foxenberg W. E. 
Published: December 2007

Abstract
Many water injection wells in sand control environments are being completed as open holes because of the higher injectivities attainable with open-hole completions. The sand control techniques used in these wells varies from standalone screens or slotted liners (including expandable screens) to gravel packing. In field practice, the drilling fluids used for injectors have also varied from water-based (either sized CaCO3/Polymer or sized-salt/polymer) fluids to oil-based systems. Although a cake cleanup followed by a production period is typically desirable to maximize injectivity, often this is not feasible either due to limited storage capacity on the rig or requirement for artificial lift due to low reservoir pressure. These limitations therefore necessitate direct injection after the completion is installed, which is not trivial as a complete and uniform filtercake removal, including drill solids as well as the bridging agents and polymers, is essential to ensure uniform injection profile in addition to maximizing injectivity index. Although exceeding the fracturing pressure can establish injectivity through bypassing of filtercake damage, this is typically not desirable from a sweep efficiency standpoint.
In this paper, we present details of a series of experiments conducted on core samples using both water-based and oil-based reservoir drilling fluid systems and various cleanup techniques involving displacements and soaks in standalone screen and gravel pack environments. It is shown that with the properly selected and designed cleanup treatments, uniform and high injectivities without producing the well is achievable in long open holes. The results from the experiments are discussed in detail, along with the lessons learned and recommendations for field practice.
A Practical Approach to Evaluating the Value of Information and Real Option Decisions in the Upstream Petroleum Industry
Authors: Coopersmith E. M. , Cunningham P. C. 
Published: December 2007

Abstract
The upstream oil industry lives in the world of Value of Information (VoI) or Real Options (RO) decisions, although many find the evaluation of these types of decisions difficult and/or cumbersome, at best. A shortage of time and calculation complexity are the common arguments used to negate a consistent decision approach to daily decisions spanning from reprocessing seismic, to selecting a development concept, to optimizing the completion technology for a given field. However, with the rapid advance of oilfield technology, and the higher cost of many oilfield decisions, the frequency, and importance, of embedded decisions (exercised after acquiring information) has increased tremendously.
This paper reviews the concepts associated with valuing information and introduces a practical methodology to both "frame" (set up) and value the acquisition of information and embedded decisions. The proposed methodology combines some classic and new decision analysis problem framing tools, Bayesian theory, and a few pragmatic steps - rigorously applied, to result in a repeatable approach, which organizations can readily adopt and disseminate.
The authors propose that both a pragmatic methodology and a sound understanding of the "anatomy", or pattern, of value of information decisions in the oil industry are vital to promoting efficiency and accuracy in asset management. For too long, our industry has claimed to understand how to value information, and embedded decisions, but lacked the consistent use of the methodologies discussed in any widespread and practical manner. Hence, the objective of this paper is to describe a pragmatic approach to evaluate upstream Value of Information ("VoI") or Real Option decisions - and share an illustrative example, using the proposed methodology. The case described will demonstrate the non-intuitive nature of these types of decisions, when taken without the use of some form of decision structure. It will also illustrate the benefit of both problem framing tools and practical decision analysis rigor to promote the right conversations and insights to information decisions.
New Technique Restores Initial Fluid Efficiency Observed in Mini-Frac and Results in Increased TSO Frac-Pack Success
Authors: Holcomb W. D. , Landry T. J. , Comeaux B. A. , Usie M. J. , Smith J. E. , Rivas L. F. 
Published: December 2007

Abstract
It has been observed that pumping a mini-frac prior to a TSO Frac-pack can impact the effectiveness of the frac-pack. The calculated fluid loss parameters determined in the diagnostic test are often not valid for the main fracture design due to the residual effect of the mini-frac and/or step-rate fluids. A technique will be presented in this paper which allows the calculated fluid loss parameters from the diagnostic test to be used reliably without excessive waiting time for the reservoir to recover to its original leak off characteristics. Fifty plus treatments were evaluated to develop a technique which makes this possible. The use of this technique resulted in a significant change in the success of the TSO designed treatments - success being a TSO type pressure increase while pumping. The success rate to achieve designed TSO, by incorporating the changes described in the paper, was increased over 20 percent with a reduction in time between diagnostic tests and the main frac.
In the wells associated with this paper, a borate-crosslinked fluid was used for a mini-frac treatment followed by a steprate test prior to the main proppant laden frac-pack. The fluid was designed with minimal polymer loading for the well conditions. The resulting mini-frac tests had low fluid efficiencies. It was originally thought that using this fluid, followed by injection of a linear step-rate fluid, would minimize the changes observed in fluid efficiency between the diagnostic test and the main fracture treatment. However, the effect of the diagnostic test on fluid leak off still resulted in less than desired TSO predictability.
A technique of adding a pH control additive into the final portion of the step-rate test fluid was found to successfully allow the use of the observed diagnostic test results, honoring the efficiency from the mini-frac test. The quantity and placement of the pH control agent in the step-rate protocol were dependent upon well conditions. The waiting time between the diagnostic test and the main treatment was reduced since a positive, controlled change was applied. The optimum pH reduction for the desired effect was determined in the laboratory and designed into each treatment depending upon well conditions.