bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design and Operational Factors for the Life of the Well and Abandonment
Authors: Tahmourpour Farzad , Exner Mike , Khallad Isaac 
Published: June 2008

Abstract
Zonal isolation throughout the life of the well is important to help ensure that health, safety, and environmental (HSE) standards are not compromised and that the well operates economically. The life expectancy of a well is dependent on the protection that the wellbore can receive from primary cementing operations.
A primary cement job design that provides zonal isolation and preserves structural integrity over the life of the well can reduce or eliminate the need for remedial operations. Achieving successful zonal isolation comprises three key mechanisms:
Design and delivery of a reliable cement system that can withstand the effects of the operational loading and cyclical stresses exerted on the well by drilling, completion, and production operations. An auto-seal feature in the cement sheath itself. In the event that the cement sheath fails and develops cracks and/or micro-annuli because of primary cementing job failure in the presence of a mud filter cake, the sealant sheath can then react and respond in an attempt to automatically seal itself if formation fluid enters the cemented annulus. This is a fail-safe technology mode that can be included in the design of the cement slurry. Employing a packer element as part of the casing/liner string that can swell and seal the annulus if formation fluid comes in contact with the element. This additional contingency can help prevent flow of the hydrocarbon past the packer element by creating an effective mechanical seal.
By applying these features, it is possible to effectively and successfully perform primary cementing operations with additional protective options and place sealants that will last throughout the life of the well (Fig. 1).
Integrating Multiple Production Analysis Techniques To Assess Tight Gas Sand Reserves: Defining a New Paradigm for Industry Best Practices
Authors: Ilk D. , Perego A. D. , Rushing J. A. , Blasingame T. A. 
Published: June 2008

Abstract
Decline curve analysis using the Arps rate-time equations has historically been the primary tool used for reserve evaluations in tight gas sands. However, characteristic tight gas sand properties often preclude accurate assessments using only or primarily decline curve analysis — especially early in the productive life. Moreover, the Arps models are essentially used as curve-fitting devices with (very) limited theoretical basis. As such, this paper presents a reserves appraisal process that complements traditional decline curve analyses with theoretically-based production analysis techniques.
Specifically, we incorporate multiple reserves estimation techniques ranging from simple extrapolation techniques to rigorous model-based analysis/interpretation methods, including:
Arps exponential and hyperbolic relations — rate-time and rate-cumulative plots, as well as other auxiliary plots, Semi-analytical rate-cumulative techniques for boundary-dominated flow, The "flowing material balance" approach in its various formulations, and Model-based analysis ("rate-transient" or "model-matching" approaches).
We provide both separate and combined analysis, including "diagnostic" plots which guide the evaluation process and help prevent erroneous reserve estimates resulting from use of single methods. Implementation of the proposed workflow will prevent unrealistic (either too low or high) reserve bookings by integrating multiple production analysis techniques. We demonstrate where and how each component technique should be used as well as their limitations. We also demonstrate how each technique can be used to reinforce/validate results from other techniques (i.e., multiple redundancies of methods).
The primary objectives of this work are to:
Provide a consistent workflow for integration of multiple reserve estimating techniques for tight gas sands, Provide an assessment of strengths and weaknesses of individual reserves estimation techniques, and. Provide demonstrative examples for implementing this workflow (including diagnostics).
Global Possibilities of Future Methane and Hydrogen Economies
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: June 2008

Abstract
There is concern within some factions of the energy industry about an approaching energy crisis. In the case of hydrocarbons, eventually there will be a maximum peak in global production. The question is if it will occur sooner or later, and if it will happen because of depletion or because of substitution to other energy sources - perhaps unconventional or non-fossil. This does not preclude hydrocarbon shortages that might still occur due to temporary factors such as political instability and lack of investment.
Although the past is not always an indication of the future, an analysis of global market shares (i.e. the mix) for solids, liquids and gases from the year 1850 to 2005, leads to a model that permits a reasonable forecast of the global possibilities of future methane and hydrogen economies.
It is concluded that if there is a supply problem in the future it will not be the result of depletion, but rather the failure of society to invest in the research and development of technology needed to provide conventional and unconventional hydrocarbons, as well as alternatives such as hydrogen, on a timely basis.
Proper development of these resources will lead to sustainable and efficient global economic growth.
Making the Most of Conventional Decline Analysis
Authors: Jordan Colin L. , Jackson Robert , Smith Cooper 
Published: June 2008

Abstract
Despite its many limitations, conventional decline analysis is still commonly used in gas production analysis due to its minimal data requirements and ease of application. Yet, there is strong desire and need for more sophisticated methods such as those loosely defined by the term advanced decline analysis. As a result, this paper presents an automated computer method for estimating original gas-in-place and other reservoir flow parameters. The method is semi-analytical in that it is based on a semi-empirical relationship between gas production and initial reservoir conditions, but is coupled with conventional decline analysis methods for ease adaptation into the workflow.
The procedure provides additional information comparable to flowing material balance analysis, but within the familiar Arps decline environment – a critical component that makes the procedure very amendable to traditional workflows. Another advantage is that the proposed methodology does not require a prior knowledge of net pay, formation and/or fluid compressibility, or reservoir pressure (other than initial conditions) for estimation of OGIP. Results will also show that the approach is generally accurate and robust (when used appropriately) and provide additional information such as effective permeability if a few volumetric parameters are provided. And that the procedure is extremely simple and can be implemented in desktop applications or spreadsheets with minimal computational effort.
Although there are limitations such as constant flowing pressure (as well as multiphase flow), it will be demonstrated that the procedure is generally versatile and can be applied to a number of gas systems including conventional sands and silts, thermogenic and biogenic shales, as well as (dry) coal bed methane. Results and observations are based on both simulated and field examples for a variety of operating conditions. In conclusion, a novel and rapid methodology has been introduced for estimating original gas-in-place, ultimate recovery (EUR), and other flow parameters with the simplicity of conventional decline.
Cementing Horizontal Wells: Complete Zonal Isolation Without Casing Rotation
Authors: Carrasco-Teja M. , Frigaard I. A. , Seymour B. 
Published: June 2008

Abstract
There is a common perception that displacing mud in horizontal wellbores is made ineffective by large density differences due to stratification of the fluid layers along the annulus. Hence the industry commonly employs methods such as casing rotation to move fluids around the annulus. Whilst such methods may be effective, they are not always necessary. Using a mathematical model of the process, we show that even with large density differences it is still possible to have a steadily advancing displacement front that displaces mud all around the annulus without casing rotation. The conditions when this is possible depend on the fluid rheologies, flow rate and hole geometry, but not the density difference. These conditions are easily quantified. Although density difference does not enter into the criteria for an effective displacement, the length of the interface along the wellbore does scale with the density difference. This means that, provided one is able to tolerate additional fluid volumes, we are able to effectively displace the mud even using fluids with large density differences. This new understanding of the displacement fluid mechanics opens up new opportunities for cementing difficult horizontal wells, (e.g. slimhole), where casing rotation is not possible.
Evaluating Crossflow Migration Drainage
Authors: Scholz J. , Sorensen F. , Hamp T. 
Published: June 2008

Abstract
Understanding the effects of lease-line drainage has always been a challenge facing natural gas producers. When approaching this issue, companies generally focus on gas migration caused by reservoir pressure gradients. However, ‘crossflow migration’ in multi-layered reservoirs also needs to be evaluated.
Crossflow migration occurs when wells produce at a flowing pressure higher than the near-wellbore reservoir pressure of a commingled and depleted high permeability zone. This can result in unexpected crossflow of gas from a low-permeability, high-pressured, high-reserves zone to the depleted zone, and, through this ‘thief zone’, migration of the gas to adjacent lands.
This study quantifies reserves and production impacts of crossflow migration, using a model of two neighbouring shallow gas properties in S.E. Alberta, and based on geological characteristics typical of the area around the Alderson, Suffield and Medicine Hat Fields (Figure 1).
The analysis showed that historical lease-line drainage of 1.9 BCF (55 e6m3) occurred during 1960–2007 over a one-mile boundary between two operators, one of which had aggressively developed its property through reduced operating pressure and infill drilling. Of this amount, approximately 45% was through the permeable Medicine Hat A (MHA) formation. Drainage through the MHA was supported by approximately 0.6 BCF (18 e6m3) of crossflow into that formation from other zones completed in the commingled wellbores. If left unaddressed, further drainage of 0.7 BCF (20 e6m3) was predicted to occur over the 30-year forecast period.
Using reservoir simulation, this study also identifies an optimal development strategy to minimize the impact of crossflow migration drainage.
Directional-Specific TCI Drill-Bit Design Features Allow for High Penetration Rates and Improved Durability in Tough Build Sections in Canadian Applications
Authors: Mason Chad , Rickabaugh Caleb , Olson Eric , Christensen Hughes 
Published: June 2008

Abstract
Regions of western Canada comprise tough interbedded formations of hard sandstone, siltstone, shale and chert, which create great challenges for directional drilling applications. Historically, using conventional tungsten carbide insert (TCI) rollercone drill bits to drill a directionally placed wellbore trajectory has resulted in low penetration rates and short runs due to the impact of high cyclic loading and damaging hole-wall contact on the bits. With WOB being preferentially loaded on the heel and adjacent heel area of the roller cone cutting structure during directional drilling, cutting structure breakdown is accelerated and seal failures occur. Additionally, rigorous hole-wall contact increases gauge and shirttail wear.
Extensive research, testing, and development have produced TCI rollercone bit designs that have addressed these major challenges. A multitude of design iterations have resulted in a new TCI rollercone drill bit that includes innovative cutting structures for improved durability and ROP, enhanced OD and leg protection to ensure bearing integrity and gauge-holding ability, and stronger materials and processes to withstand high cyclic loading of directional drilling. Drill bits designed with these features have been successful in increasing average footage per run by 121% while improving penetration rates modestly vs. offset drill bit runs in the western Canadian regions, which include Saskatchewan, Alberta, and British Columbia. Additionally, one-bit runs, as opposed to two or three, are now possible in builds to horizontal in many applications, thus reducing overall drilling time by over 25%, and significantly reducing drilling costs.
This paper will detail the directional TCI rollercone drill bit design features and technologies used as well as field results and case studies from Canadian-specific markets.
Fishing MWD Tools in Horizontal Wells Without Fluid Circulation
Authors: Frasure Gregg , Travis Deck , Montgomery Billy 
Published: June 2008

Abstract
The boom in horizontal drilling presents new problems that require innovative solutions. Typical drilling problems such as stuck drill pipe have only become more acute with the emergence of horizontal drilling. Formation instability, improper hole cleaning and break-out debris in the hole wedged beside the drill string can cause drill pipe to become stuck resulting in costly pipe recovery operations.
A new application of the electric wireline Well Tractor® has made possible the efficient recovery of MWD (Measurement While Drilling) tools and other stuck assemblies in horizontal and highly deviated wells.
This paper presents an alternative to conventional fishing methods by utilizing Well Tractor® Technology. In today's market, Operators face challenges in the conveyance of pipe recovery tools in the lateral section of a well if circulation is lost during the drilling process. This leaves the operator with few options, all of which are time consuming and expensive. In some cases, abandoning the hole and side tracking is required. In addition to drill pipe recovery services such as free point and back-off operations, MWD tools can be fished in highly deviated and horizontal wells, reducing overall operational and replacement costs of these exceptionally high priced MWD tools. With rising rig costs, it is crucial that fishing operations are conducted in the most efficient manner possible.
The Well Tractor® has fished MWD tools successfully at various well depths, inclinations, mud weights and different drilling assemblies. The Well Tractor® design is well suited for operation inside drill pipe and completion strings with varying Internal Diameter (ID) such as joint connections, or when going through cross-overs and landing nipples.
An overview of the Well Tractor® technology, used in these fishing operations, is presented. A summary of operational benefits related to this application is included along with case studies showing how the Well Tractor® technology has become a new solution for conveyance of fishing technology to retrieve MWD and other systems in deviated or horizontal pipe recovery operations.
Performance Paradigm Shift: Drilling Vertical and Directional Sections Through Abrasive Formations with Roller Cone Bits
Authors: Buske Robert , Rickabaugh Caleb , Bradford John , Lukasewich Heather , Overstreet Jim , Christensen Hughes 
Published: June 2008

Abstract
In several Canadian applications, operators have recognized the potential to replace standard roller cone products with a more viable solution that will drive down costs when drilling straight hole and curved sections. In these high-abrasive applications, roller cone bits are preferable because of their ability to increase ROP while maintaining a controlled direction and their relatively low price compared to polycrystalline diamond compact (PDC) bits. Typically, roller cone bits are removed from service because of damage or wear to the bearings or seals, and/or to the cutting structures. However, in these applications, the weakness occurs in the leg section.
Historically, wear protection on the leg outside diameter (OD) was achieved by placing tungsten carbide inserts in vulnerable locations. Although this increased wear resistance, the softer portion of the leg OD was still exposed to the damaging effects of hole-wall contact due to the required spacing between the tungsten carbide inserts. Also, the required drill holes for the inserts could become crack-propagation points in certain drilling environments.
To improve the durability of the leg while increasing seal and bearing reliability, abrasion-resistant hardfacing was incorporated onto the majority of the leg OD. Roller cone bits with the new hardfacing leg protection were field tested in several operators' wells with excellent results. The hardfacing leg protection proved to reduce OD wear more than TCI leg OD protection, therefore providing improved seal and bearing protection and thus reliability. Additionally, the hardfacing configuration stiffens the leg, increasing durability by reducing flexing and the potential of leg breakage. By preventing early bearing failure due to abrasive leg wear, this innovative technology has caused a performance paradigm shift and has significantly driven down drilling costs and non-productive time. The authors will present several case studies that document how the unique technology has increased the overall leg protection of roller cone products resulting in improved seal protection. This has led to an increase in total footage drilled in some applications and substantial cost savings to operators compared with standard roller cone products in those applications that do not have the new hardfacing.
Application of Stirling Cycle Generators in Production Operations
Authors: Dotson B. , Rochelle J. , Madden L. 
Published: June 2008

Abstract
Clean, inexpensive, and reliable on-site electric power generation for remote wellsites is an emerging need. There is a growing demand for electric power sources in the range of ½ to 1.5 kW to run pumping units and pumps on liquid loaded gas wells. To understand one possible option, a pilot project consisting of three 0.8 kW Stirling Cycle electric generators was conducted in Wyoming.
One generator was installed driving a conventional beam pump at the US Department of Energy's (DOE) Rocky Mountain Oilfield Testing Center (RMOTC). Two generators were installed for telemetry power service on well pads in the Wamsutter gas field. In addition to these two applications, small gas-fired generators could provide power for cathodic protection, chemical dosing systems, and other low rate pumping requirements.
The pilot demonstrated that a Stirling Cycle generator can pump a small well and provide SCADA power even in cold weather conditions. A simple fuel control and conditioning system provided reliable operation when properly installed. Operations and maintenance observations from the 1 year pilot will be presented.
Stirling Cycle engines are "external combustion engines" which offer some advantages over traditional "internal combustion engines": lower maintenance cost, low NOx emissions, and the recovery of heat for process uses. In fact, the current commercial equipment is best thought of as a ¾ kW cogeneration unit.
Practical Anisotropic Depth Migration
Authors: Schmid Ron , Stevenson Michael 
Published: June 2008

Abstract
In thrust belt areas along the margins of the continental Rocky Mountains and other environments with structural complexity, changes in subsurface lateral interval velocity requires depth migration of conventional surface seismic surveys to correctly position events. The presence of accompanying thick shale units overlying prospective drilling locations demand the depth migration procedure also compensate for anisotropic effects of wave propagation in a titled coordinate reference system. We start by briefly identifying the types of environments that are prospective candidates for depth migration. Then we observe the incremental improvements in subsurface imaging by following a continuum of conventional methods leading to anisotropic depth migration results. Seismic depths to well depths are compared. Finally, methods to derive the required anisotropic parameters are discussed.
As the technical understanding of anisotropic wave field propagation deepens and more examples are found in case histories the role of anisotropic depth migration will become more prominent. Increases in compute capabilities portend that this will become the new standard for structural seismic imaging.
This procedure significantly improves the imaging of faults, formations and reservoirs by correctly describing their lateral and vertical geometry. Thus it is a major risk mitigator. Moreover, it offers a means to invert seismic data into the depth domain to be used by the entire geoscience community.
Development of Coalbed Methane in Australia: Unique Approaches and Tools
Authors: Ham Y. , Kantzas A. 
Published: June 2008

Abstract
Coalbed Methane (CBM), also known as Coal Seam Gas (CSG) or Coal Seam Methane (CSM) in Australia is fast becoming a significant contributor to the country's energy needs. The potential coal seams for methane production in Australia are found in coal zones that are Jurassic to Permian in age with coal ranks ranging from sub-bituminous to low volatile bituminous coals. Many Australian coal seams contain high volumes of methane gas upto 25 m3 per tonne. Australia began producing CBM in 1988 but it was not until 1996 when the commercial CBM production started in the state of Queensland. Australia has total CBM reserves of about 300 to 500 Tcf (8.6 to 14.3 trillion m3).
With the total amount of CBM in-place reserves worldwide estimated to be between 3,500 and 95,000 Tcf (100 and 272 trillion m3), CBM is considered one of the world's largest sources of fossil fuel. In the United States, the total CBM in-place reserves are estimated at 749 Tcf (21.4 trillion m3), and CBM now represents almost 10% of its domestic natural gas production. Canada has just begun producing gas from CBM reservoirs and its estimated in-place CBM reserves are about 1,300 Tcf (37 trillion m3). In Australia, as CBM is seen as a clean and pipeline-quality energy, it is rapidly developing. Along with the large CBM resource, the main drivers for this move are the continuously reducing cost of coal seam gas production, and the depleting conventional energy resources.
A number of sophisticated CBM reservoir simulation and exploitation tools have been developed by the University of New South Wales and CSIRO to simulate the conventional CBM production as well as the CBM recovery using multi-component gases. In the field, Australia looks toward enhancing CBM recovery by injecting nitrogen and or carbon dioxide to increase CBM extraction. This paper will focus on how Australia is maximizing its CBM production.