bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbon Dioxide Transport and Sorption Behavior in Confined Coal Cores for Enhanced Coalbed Methane and CO2 Sequestration
Authors: Jikich Sinisha A. , McLendon Robert , Seshadri Kal , Irdi Gino , Smith Duane H. 
Published: December 2007

Abstract
Measurements of sorption isotherms and transport properties of CO2 in coal cores are important for designing enhanced coalbed methane/CO2 sequestration field projects. Sorption isotherms measured in the lab can provide the upper limit on the amount of CO2 that might be sorbed in these projects.
Because sequestration sites will most likely be in unmineable coals, many of the coals will be deep and under considerable lithostatic and hydrostatic pressures. These lithostatic pressures may significantly reduce the sorption capacities and/or transport rates. Consequently, we have studied apparent sorption and diffusion in a coal core under confining pressure. A core from the important bituminous coal Pittsburgh #8 was kept under a constant, threedimensional external stress; the sample was scanned by X-ray computer tomography (CT) before, then while it sorbed, CO2. Increases in sample density due to sorption were calculated from the CT images. Moreover, density distributions for small volume elements inside the core were calculated and analyzed. Qualitatively, the computerized tomography showed that gas sorption advanced at different rates in different regions of the core, and that diffusion and sorption progressed slowly. The amounts of CO2 sorbed were plotted vs. position (at fixed times) and vs. time (for various locations in the sample). The resulting sorption isotherms were compared to isotherms obtained from powdered coal from the same Pittsburgh #8 extended sample.
The results showed that for this single coal at specified times, the apparent sorption isotherms were dependent on position of the volume element in the core and the distance from the CO2 source. Also, the calculated isotherms showed that less CO2 was sorbed than by a powdered (and unconfined) sample of the coal. Changes in density distributions during the experiment were also observed. After desorption, the density distribution of calculated volume elements differed from the initial distribution, suggesting hysteresis and a possible rearrangement of coal structure due to CO2 sorption.
A Dual-Grid Automatic History-Matching Technique With Applications to 3D Formation Testing in the Presence of Oil-Based Muds
Authors: Malik Mayank , Torres-Verdín Carlos , Sepehrnoori Kamy 
Published: December 2007

Abstract
Probe-type formation testers are often used to estimate permeability and permeability anisotropy from pressure transient measurements. The interpretation of these measurements is not trivial in the presence of oil-base mudfiltrate invasion due to miscibility with formation oil and gas. Simple analytical expressions of spherical and linear singlephase flow may not give correct estimates of permeability in miscible or partially miscible flow regimes. A computationally demanding three-dimensional (3D) numerical model is required to provide accurate and reliable estimates of formation properties. Because pressure transients are nonlinearly dependent on the permeability of the formation, repeated 3D numerical simulations are necessary to match the measured pressure transients.
We describe the development and successful implementation of a new inversion method that efficiently estimates permeability and permeability anisotropy with a cascade sequence of least-squares minimizations. Measurements consist of pressure transients acquired at the sand face with a probe-type wireline formation tester (WFT). The new inversion method executes the forward 3D problem only in an outer loop. In the inner loop, we perform fast minimizations with an equivalent two-dimensional (2D) cylindrical grid. Transient measurements of pressure at the sand face simulated with the 2D cylindrical grid are correlated to the corresponding measurements simulated with the 3D grid. Once the 2D minimization is completed, we perform a 3D simulation of transient pressure to update the 2D-3D correlation parameter and a new 2D minimization is performed until convergence is reached. The process repeats itself until the simulated 3D pressure transients reproduce the field measurements within pre-stipulated error bounds.
We perform tests of the new inversion algorithm on synthetic and field data sets acquired in the presence of oil-base mudfiltrate invasion. Results successfully confirm that our coupled 2D/3D hybrid inversion approach enables significant savings in computer time and provides reliable and accurate estimates of permeability and anisotropy. In most cases, we are able to estimate permeability under 2% error within 20% of the computational time required by 3D minimization. Sensitivity analysis indicates that permeability estimates may be biased by noisy measurements and uncertainty in (a) flow rates, (b) relative permeability, (c) radial extent of invasion, (d) formation damage, and (e) location of bed boundaries.
Low-Salinity Waterflooding to Improve Oil Recovery—Historical Field Evidence
Authors: Robertson Eric P 
Published: December 2007

Abstract
Waterflooding is by far the most widely applied method of improved oil recovery. Crude oil/water/rock interactions can lead to large variations in the displacement efficiency of waterfloods. Laboratory waterflood tests and single-well tracer tests in the field have shown that injection of low-salinity water can increase oil recovery, but work designed to test the method on a multi-well field scale has not yet been under-taken. Historical waterflood records could unintentionally provide some evidence of improved recovery from water-flooding with lower salinity water. Numerous fields in the Powder River basin of Wyoming have been waterflooded using low salinity water (about 1000 ppm) obtained from the Madison limestone or Fox Hills sandstone. Three Minnelusa formation fields in the basin were identified as candidates for waterflood comparisons based on the salinity of the formation and injection water and reservoir characteristics. Historical production and injection data for these fields were obtained from public records. Field waterflood data were manipulated to display oil recovery in the same format as laboratory core-flood results. Recovery from fields using lower salinity injection water was greater than that using higher salinity injection water—matching recovery trends for laboratory and single-well tests.
A New Environmentally Acceptable Technique for Determination of Propped Fracture Height and Width
Authors: McDaniel R. R. , Borges J. F. , Dakshindas S. S. 
Published: December 2007

Abstract
For years, radioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a fracturing treatment. These issues, along with regulations concerning the transportation of radioactive materials, have impacted the application of this technology in international markets.
This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height, as well as insight into propped fracture width. In this new technology, a non-radioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous, environmentally safe, coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. Once the proppant is placed in the well, a gamma spectroscopy logging tool is used together with a fast neutron source to activate the tagging additive. The additive then becomes temporarily radioactive, emitting characteristic gamma rays that are visible to the logging tool's spectrometer.
The detected gamma ray response not only identifies the presence of the proppant, but in addition, the strength of the response is proportional to the amount of the additive/proppant that is present in the fracture, thereby providing insight on fracture width. Since the additive only responds when stimulated by the neutron source, the logging process can be completed free of any of the timing constraints associated with the half-life of presently used radioactive tracers and can be repeated as often as desired.
The additive used in this technology has been selected for a number of reasons, not the least of which is its very short half-life after being irradiated. By the time the logging process is complete and the well is ready to be placed in production, the additive will no longer emit a detectable level of radiation. This paper will describe this technology and its use in some detail. It will also present the results of initial field tests that utilized this new technology to determine aspects of propped fracture geometry.
The Challenges of Designing HP/HT Equipment
Authors: Forsyth Andrew , Saucier Brian , More Daniel , Stawaisz Ray A. , Gill Dave , Younger Ray 
Published: December 2007

Abstract
The Paper presents an overview of the main design activities for the Completion and Intervention Landing String System that was deployed in the Tahiti field in the Gulf of Mexico. The functional and structural design challenges encountered due to the high operating pressures and temperatures are reviewed. The Paper also illustrates how analysis tools were used to quantify the observations found during test, and subsequently assist in determining a design solution. A key aspect of the design process was to view the design and operations from a holistic perspective by evaluating the design throughout its operational life. This paper will therefore present how this design process established a design solution that increased the reliability and confidence of the Landing String System and therefore reduced the operational risk.
Application of the CPA Equation of State to Reservoir Fluids in Presence of Water and Polar Chemicals
Authors: Yan Wei , Kontogeorgis Georgios M. , Stenby Erling H. 
Published: December 2007

Abstract
The complex phase equilibrium between reservoir fluids and associating compounds like water, methanol and glycols has become more and more important as the increasing global energy demand pushes the oil industry to target reservoirs with extreme or complicated conditions, such as deep or offshore reservoirs. Conventional equations of state (EoS) with classical mixing rules can not satisfactorily predict or even correlate the phase equilibrium of those systems. A promising model for such systems is the Cubic-Plus-Association (CPA) EoS which has been successfully applied to well-defined systems containing associating compounds. In this work, CPA is extended to reservoir fluids in presence of water and polar chemicals by using a newly developed characterization procedure for ill-defined C7+ fractions. Satisfactory results are obtained for multicomponent systems using a minimum number of adjustable parameters which are obtained from binary systems. Modeling of mutual solubility between light hydrocarbons and water is also addressed.
Gannet A: Critical New Reservoir Insight Through Seamless Cross-Discipline Integration
Authors: de Jonge Joanne , van Waarde Jakko 
Published: December 2007

Abstract
The thin oil rim of the Gannet-A turbidite field in the Central North Sea has been produced since 1993 though 11 long horizontal wells supported by a strong aquifer and sizeable gas cap. The original zero development strategy called for zero net-voidage of gas through re-injection of produced gas into the gas cap.
A full gas cap blowdown is currently being planned to commence in 2008. In order to predict field behaviour in this high production rate environment, and maximise oil and gas recovery, significant effort has gone into the static and dynamic re-modelling of the reservoir.
This effort has demonstrated that over the production life, complexity of the high quality reservoir has been underestimated, leading to inadequate historical data acquisition and integration efforts, particularly in the low oil price world in the late 90s.
This paper describes how all available subsurface data have been (re-)analysed and integrated, resulting in a range of realistic dynamic reservoir models and how the remaining uncertainty was dealt with during the selection of the optimum further field development plan.
The key to success in this study has been the seamless cross discipline integration that enabled maximum extraction of information from the available data. The same discipline integration led to a thorough understanding of the critical remaining uncertainties in the project and a tailor made surveillance plan that aims at rapidly reducing these.
Certification Process Built on Required Engineering Competency Standards Ensures Consistent Performance Levels and Defines Employee Development
Authors: Scotchman A. D. , Redshaw J. P. , Laing R. , Forstner I. , Trichel D. K. , Dwyer J. P. 
Published: December 2007

Abstract
In today's robust hydrocarbon markets, complexity and volume of drilling and evaluation activity have grown to unprecedented levels. This is driving technology development and new application practices at a record pace. At the same time, the industry is struggling to grow the talent base to manage the increased workload. These issues have resulted in a need to track and ensure application engineer and geoscientist competency levels. To solve this challenge, the company developed a detailed process for individual competency assessment and employee development for various application disciplines. Certification is awarded in set disciplines when the necessary criteria have been met and competence has been successfully demonstrated to a technical experts’ review panel.
The required competencies for each discipline were developed from the expanded job functions expected of the experienced senior applications engineers and geoscientists, as well as expectations of the services provided in each discipline. From this, a competency assessment and tracking methodology was created. The methodology enables the assessment of an individual engineer's competency level so a tailored development program of training and mentoring can be developed. A formal mentoring system plays a vital role in the certification process. Assigned mentors offer valuable engineering and process guidance.
The authors will describe a certification process and a methodology for competency assessment and tracking for application engineers and geoscientists. Finally, the authors will discuss how the program benefits raise the level of the company's technical expertise.
Applying Hydraulic Fracture Diagnostics to Optimize Stimulations in the Woodford Shale
Authors: Vulgamore Travis , Clawson Tim , Pope Charles , Wolhart Steve , Mayerhofer Mike , Machovoe Sean , Waltman Charlie 
Published: December 2007

Abstract
The success of the Barnett Shale has many operators in search of similar producing formations. One such formation is the Woodford Shale which stretches from Kansas to west Texas. The Woodford is an ultra-low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. Once a formation that was drilled through on the way to deeper horizons, this shale play now dominates drilling activity in southeast Oklahoma.
Like the Barnett, initial testing of the Woodford Shale was from existing vertical wells that penetrated deeper horizons. Currently, the main exploitation of the Woodford Shale is from long horizontal wells with some lateral lengths exceeding 4000 ft. The wells are stimulated in stages with large hydraulic fracture treatments. Successful shale plays have demonstrated that production is directly related to the size of the stimulated reservoir volume. Techniques to optimize hydraulic fracturing effectiveness have been evolving in the area the last few years.
Over 100 frac stages have been mapped in the Woodford Shale using surface tiltmeters, offset-well microseismic and treatment-well microseismic mapping techniques. This paper will examine the effect of lateral azimuth, formation dip and its influence on asymmetric fracture growth; the effect of existing faults and its interaction with the fracture stimulation. Additionally, stimulation size, number of stages, perforation clusters and fracture initiation problems will be discussed. Finally, a comparison to Barnett Shale type fracture networks will be made.
Understanding fracture growth in the Woodford Shale will enhance the development of the play by helping operators optimize fracture completion and well placement strategies.
Well-Stimulation Technology Progression in Horizontal Frontier Wells, Tip Top/Hogsback Field, Wyoming
Authors: Romer M. C. , Phi M. V. , Barber R. C. , Huynh D. V. 
Published: December 2007

Abstract
Fracturing work conducted on the 2006 Tip Top/Hogsback (TTHB) field horizontal well program proved that sand plug isolation will work in horizontal wells, even when the stimulation treatment calls for fracturing with a high energy fluid. The TTHB field is a tight gas field in southwestern Wyoming, and the wells will not produce without a fracture stimulation treatment. This paper will describe the evaluation process of various fracturing technologies considered for the program, and how learnings from a 1995 horizontal program were used to build the final pinpoint stimulation design. In addition, this paper will discuss the stimulation execution and the learnings generated from the program.
The fractured horizontal wells were drilled to 11,000 ft measured depth (MD), 7,200 ft true vertical depth (TVD), with the laterals being approximately 3,800 ft of the total measured depth. Eight fracture treatments were planned for each horizontal. The foam stimulation treatments contained 60-quality CO2 and averaged 235,000 lbm total proppant per zone. The basic stimulation procedure consisted of cutting perforation holes by use of a hydrajet tool on the end of coiled tubing (CT), pumping a fracture treatment down the production casing, and setting a sand plug with CT in the lateral to provide zonal isolation. This process allowed continuous treatment of successive intervals without shutting down to set a mechanical plug or perforate the next interval.
Although several challenges were encountered during the execution of the stimulation treatment, the stimulation design did prove to be a more time efficient and cost effective option than conventional horizontal well fracturing treatments. The paper will discuss learnings on setting sand plugs between fracs, frac designs, and equipment operation/limitations. As a result of the learnings, the average treatment time decreased from 24 hr/zone on the first well to 13 hr/zone on the second.
The paper will also discuss additional changes made during the stimulation execution to increase the effectiveness of the hydrajet tool and increase the probability of setting a successful sand plug.
The process for designing and placing successful sand plugs was optimized from well to well and can furthermore be tailored to fit other fields. Learnings and techniques applied in this work can be used to improve and optimize fracturing treatments of similar nature in other geographic/geologic areas.
Different Methods to Avoid Annular Pressure Buildup by Appropriate Engineered Sealant and Applying Best Practices (Cementing and Drilling)
Authors: Tahmourpour Farzad , Hashki Khaled , Hassan Hassan 
Published: December 2007

Abstract
Many wells that have been successfully cemented initially are showing annulus pressure buildup due to damaged cement sheath integrity by post-cementing operations/conditions. This has been a concern by many operators where wellbores may be exposed to severe conditions and/or production regimes over a period of time. Sometimes this problem can be temporarily dealt with by releasing the annulus pressure, if environmental conditions and well type will allow. However, this method of annular gas production relief is not a long-term solution to the problem. In addition, it is not always possible to reduce the annulus pressure by releasing the trapped pressure into the environment on a regular basis, even if all other conditions permit this operation. An engineered cement slurry system can save the operator from facing this situation by applying a lifetime zonal isolation remedy through the proper cement job design.
Gas injection in specific areas in the United Arab Emirates is performed to help maximize the production from these development fields. This paper will discuss the process of engineering a cementing system for these gas injection wells and the development of a solution that has successfully protected wellbores in gas injection areas where high pressures are applied to the wellbore. By treating the cement under defined wellbore conditions and studying the mechanical behavior of the cement sheath, it was possible to design a cement slurry system that could withstand the high pressures applied through gas injection operations. The mechanical behavior was evaluated using three-dimensional finite element analysis that considers mechanical properties such as Young's modulus, Poisson's ratio, and tensile strength in addition to confined compressive strength. The importance of complete zonal isolation is of high order. Elastic cement designs have provided a resilient nonfoamed, or conventional, system that successfully isolated the wellbores for more than a dozen gas injection wells.