bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dielectric Dispersion: A New Wireline Petrophysical Measurement
Authors: Hizem Mehdi , Budan Henri , Devillé Benoit , Faivre Ollivier , Mossé Laurent , Simon Matthieu 
Published: September 2008

Abstract
Dielectric measurements and interpretation, introduced with great promise in the 1980s, have not found widespread use owing to measurement limitations, moderate accuracy, and insufficient quality control. This paper presents a new-generation dielectric tool that overcomes these limitations and brings extra information for more accurate petrophysical formation-evaluation.
One of the revolutionary advances offered by this tool is the continuous measurement of dielectric dispersion (variation of formation dielectric properties as a function of the frequency) at 1-in vertical resolution. The tool uses multi-spacings antenna arrays operating at multiple frequencies in the MHz to GHz range. Moreover, transmitter and receiver antennas have colocated longitudinal and transverse polarizations.
The wealth of recorded data will allow interpreters to both adapt the answer product to the reservoir fluids and geology, and also to provide acquisition quality-controls and error estimates on the results.
Carbonate and heavy oil reservoirs are becoming more and more important. In these two environments, the new tool provides unique answers to better characterize these reservoirs. This tool also addresses traditional dielectric formation-evaluation in fresh water and thinly laminated sands.
Answer products offered by this new tool can be classified in three categories. Pore-fluid analysis from the muti-spacings high frequency measurements•Hydrocarbon residual saturation and invaded zone water salinity•Invasion profile: hydrocarbon saturation profile in heavy oil reservoirMatrix analysis from dielectric dispersion•Carbonates: textural information (Archie m cementation factor)•Shaly sands: high resolution clay volume and anisotropyGeological structure analysis from the muti-polarizations and high resolution•Thin beds analysis•Structural anisotropy measurement in very thin beds•Geological features extraction•Carbonate classification
This paper reviews the dielectric dispersion physics, then describes the tool's architecture, measurements, and data processing chain. Field test examples illustrate the enhanced interpretation potential of dielectric dispersion measurements from this tool.
Acoustic Measurement and Calibration of In Situ Stress Anisotropy Around a Wellbore
Authors: Al-Tahini Ashraf , Abousleiman Younane 
Published: September 2008

Abstract
The acoustic techniques for estimating the in-situ stresses from downhole tools are being validated for sandstone, limestone (including chalk), and shale in an experimental laboratory setup using large cubic samples of each rock type subjected to stress-induced anisotropy. The experiments involve the measurement of: acoustic velocities (compressional and shear wave); radial, axial and transversal strains; and the corresponding displacements around the borehole along directions parallel and perpendicular to the applied stresses. We show that the stress magnitudes measured at the wellbore wall vary considerably depending on the type of rock being tested and thus velocities have to be calibrated according to rock type to take into account the specific rock mechanical properties and their stress anisotropy dependence when stresses are estimated from the compressional and shear wave velocities in and around the borehole. Our experimental results also show that the measured induced tangential compressive stresses at the borehole for the tested rock materials were found to be nonlinearly correlated with the external applied stress at the boundary. As a result, assumptions of a borehole stress concentration factor of 3 based on Kirsch's equations for a uniaxial stress field may under or over estimate the actual induced compressive stresses at the borehole wall in rocks. The applied boundary stress level at which tensile failure and breakouts occur in the borehole is observed to be correlated with the measured tensile strength from Brazilian tests and the uniaxial compressive strength of each tested rock, respectively.
Managing Operational Challenges in the Installation of an Intelligent Well Completion in a Deepwater Environment
Authors: Ajayi Arashi , Pace Shawn , Petrich Bryan , Adejuwon Adeyemi , Agbonaye Cardinal , Erumwunse Courage 
Published: September 2008

Abstract
Intelligent well completion has various applications in the subsea deepwater environment. The benefits from such applications can only be derived when the system is successfully deployed. A successful deployment requires effective interface management of different components of the completion process. Such management include communication, planning and logistics related issues
Deepwater environment posses its own development challenges. These include high development cost, constrains of existing technologies and issues relating to application of new ones. Implementation of intelligent well completion in this environment may result in additional challenges. Therefore, adequate attention must be placed on managing these challenges in order to achieve desired success. This involves identification and management of key operational success factors. These factors, can be classified under three major categories namely, people, process and product.
This paper offers an insight into how the challenges can be managed to achieve a successful project based on the experience obtained from the deployment of 2 zone intelligent well completion systems. The authors focus on major components of the key success factors and provide feasible solutions to managing the challenges. The information provided in the paper could be used to enhance the planning of the deployment of an intelligent well completion program. It can also be used to identify critical success factors for the deployment of intelligent well system.
The Minimum Required Gas-Injection Rate for Liquid Removal in Air/Gas Drilling
Authors: Tabatabaei M. , Ghalambor A. , Guo B. 
Published: September 2008

Abstract
Air/gas drilling is a technology used for increasing rate of penetration in hard formations and reducing fluid damage to low-pressure coal beds for methane production. It has been widely recognized that maintaining adequate air/gas injection rate is vitally important to achieving hole cleaning against both solid and liquid accumulations. However, it is unclear as what constitutes the "adequate" air/gas injection rate for removal of formation liquid influx. It is highly desirable to have a simple and accurate method that can estimate the critical air/gas injection rate required for cleaning formation liquid influx in air/gas drilling.
Based on Guo's minimum kinetic energy theory for liquid removal in gas production wells, an analytical model has been developed for estimating the minimum required air/gas injection rate to remove formation liquid influx in air/gas drilling. We have expanded Guo's model to include the effects of Reynolds number and droplet sphericity on the drag coefficient. The theory indicates that the minimum required air/gas injection rate depends mainly on liquid density, liquid-gas interfacial tension, hole size and depth, and rate of penetration. A calculation procedure has been developed for estimating the minimum required air/gas injection rate to remove a given rate of fluid influx from the formation. Engineering charts have also been generated for predicting liquid-carrying capacity of air/gas that is injected into the borehole at various rates. This paper provides drilling engineers the necessary knowledge and a useful tool for minimizing complications in air/gas drilling operations.
Remediation of Hydrate Plugs in Offshore Wells via Capillary Tubing—A Cost Effective Alternative
Authors: Gounah Tony , Renfro Kevin D. , Bolding Jeff , Embrey Mark 
Published: September 2008

Abstract
Description: A new, cost-effective, time-saving alternative for removing hydrate plugs offshore has been successfully applied three times in the Gulf of Mexico. By using 3/8" tubing and a capillary tubing unit, chemicals can be delivered directly to the top of the hydrate plug, allowing the plug to be dissolved.
Application: Gas hydrates have long been a concern for operators in offshore gas wells. In the Deepwater Gulf of Mexico, the water temperature at the mud line can be as low as 34 F. This presents a potential problematic area for hydrate plugs to form as a result of the extreme temperature changes experienced in the well. Many remedial actions have been used to remove hydrate plugs in the past. These former methods are very expensive due to high operational costs and many days of non-productive time (NPT). A new option provides operators with a high chance of success while saving a considerable amount of money and greatly reducing NPT.
Results, Observations, Conclusions: A capillary tubing unit was used to snub 3/8" OD stainless steel tubing into the well. Once the tubing reached the plug, methanol was pumped at a rate of 1-2 gallons per minute until the plug was completely dissolved over a distance of 160 ft. So far, this technology has been 100% successful. By delivering the chemical directly to the plug, the chance for success is greatly increased. Depending on the size of the production tubing, penetration rates into the hydrate plug average 20 ft/hr, which is much faster than the traditional method of bull-heading. Chemical costs can be reduced considerably because the method uses only 1 bbl of methanol per 10 feet of hydrate plug in 3-1/2" tubing. Rigging up can be accomplished in hours instead of days, reducing operational costs and NPT substantially.
Significance of Subject Matter: Many wells are being left off production for long periods of time due to the high costs and operational issues involved with bringing in large coiled tubing units or workover rigs to remove a single hydrate plug. This new method allows operators to safely and effectively remediate the obstruction with minimal lost production time.
A New Look at Wellbore Collision Probability
Authors: Brooks Andrew G. 
Published: September 2008

Abstract
Given the potentially catastrophic human and environmental results of an unplanned well collision, a meaningful estimate of the probability of wellbore intersections provides a valuable risk management tool. A number of estimation techniques are currently in use in the industry; however, all of these have limitations which may not be clearly understood. For example, many computations currently in use fail when the two wells are parallel, they ignore the fact that the drilled well may have reached its current location without collision, or they return an identical result regardless of whether the drilling well is thought to be approaching or departing from the existing well.
A rational approach to the problem begins by clearly defining the probability to be estimated. This paper presents a method to ascertain the probability that a particular interval of the well being drilled might intersect an existing adjacent wellbore. An overall collision probability can then be obtained by combining the probabilities associated with successive intervals along the reference well. The estimates of probability are based on knowledge of the surveyed wellpaths and their survey uncertainties, expressed in the form of position covariance matrices.
A body of relevant research exists in the field of astrodynamics, concerned with estimating the risk of collision between orbiting satellites. This paper draws on prior work from both the oilfield and aerospace in developing a more rigorous assessment of collision probability, overcoming the limitation of previous methods. Examples demonstrate that the new method agrees with analytic results for both parallel and non-parallel wellpaths in simple cases where both wells are straight in the region of interest.
PVT Data Quality: Round Robin Results
Authors: Stephen A. G. , Bergman D. , Dodd T. , Kriel W. 
Published: September 2008

Abstract
Compositional data is a vital input to many engineering models, including the calculation of the mud free properties of reservoir fluids sampled by repeat formation testers and calculating the value of gas sold on a calorific value basis. For all such applications, the quality of compositional data is of critical importance. The impact can be material in a wide range of issues, including reserves estimation, facilities design, gas hydrates prediction and sales gas valuation. The main aim of this study was to set quantitative criteria for screening laboratories prior to tendering for a PVT contract.
Reliance on contractor quality assurance procedures is not sufficient. Routine internal consistency checks may not identify some of the errors. Evaluation based on analyses of identical field samples relies on one data set being of high quality, an assumption that may not be correct. There is a need for an independent supplier of high quality gas, liquid and live fluid samples of accurately known compositions that can be used by laboratories to demonstrate the quality they can achieve to the oil companies before unique and valuable samples are sent to them for analysis.
The results of a "Round Robin" evaluation of PVT laboratories around the world are presented. A set of identical samples was sent to each laboratory – 3 dry gases, 3 stock tank liquids and one live sample. There was considerable variation in the quality of compositional analyses reported. A small minority of the laboratories tested generated compositional data that fully met the highest quality measures for both gas and liquid analysis. A similar number were close to meeting these standards, but the majority generated data that was deeply flawed in some respects. In one case, interpretation errors resulted in 24% reduction in C4+ in all the gases. The resulting calculated calorific values were as much as 5% low – a large potential loss of value if used to calculate the value of sales gas. All laboratories were given feedback, and some are actively engaged in resolving the problems identified.
Numerical Modeling of the Slit Mode of Cavity Evolution Associated with Sand Production
Authors: Detournay C. 
Published: September 2008

Abstract
The development of localized bands associated with concentration of compressive strain has been linked to the slit mode of cavity expansion observed in hollow cylinder tests to study the mechanism of sand production. A comprehensive numerical model should account for this compaction mode of failure to predict the amount and rate of sand production with some confidence. This paper documents progress in the development of a numerical model to predict the amount and rate of sand production at a macro-scale (wellbore or perforation) using a continuum hydro-mechanical description of the rock mass. First, we review the general conditions for the compaction mode of failure to occur in the context of a simple cap constitutive law and give examples of numerical simulations that illustrate band formation in a (dry) Hollow Cylinder test. Then, using numerical experiments, we show that the sand production model, enhanced with a cap constitutive law, is able to reproduce qualitatively the slit mode of cavity evolution that has been observed in laboratory settings. In the simulations, the slit mechanism develops as a combination of volumetric collapse (compaction band formation) and transport of failed material by hydrodynamic forces. The sand production curve for this particular simulation shows a monotonic increase in sand-mass versus simulation-time. With the documented enhancement, the sand production model can reproduce three main modes of failure: tension, shear and compaction. The sand production model needs to be validated further and calibrated using laboratory experiments. However, at this stage, it shows good potential as an engineering tool to help characterize the impact of rock strength on sand production associated with oil production.
DTS Monitoring of Hydraulic Fracturing: Experiences and Lessons Learned
Authors: Sierra Jose , Kaura Jiten , Gualtieri Dan , Glasbergen Gerard , Sarker Diptabhas , Johnson David 
Published: September 2008

Abstract
Real-time monitoring of hydraulic fracturing using fiber optic distributed temperature sensing (DTS) is starting to be used to estimate fracture initiation depth, vertical coverage and number of generated fractures, effects of diverting agents, and undesired flow behind casing. DTS monitoring of flowback and production can also help to assess the effectiveness of the stimulation treatment.
To successfully achieve the monitoring objectives, aspects such as fiber deployment, fiber integrity at high injection rates, location and thermal coupling of fiber with respect to flow path, frequency of data acquisition and resolution, and real-time visualization and modeling need to be carefully considered.
This paper presents experiences in the analysis of transient DTS data acquired during high-rate, multi-stage hydraulic fracturing in vertical, deviated, and horizontal oil and gas wells. The location of fiber, conveyed with coiled tubing inside the flow path or cemented behind casing, has a major impact in the temperature response, depending of the thermal conductivity between the fiber cable and the injected fluid path.
When the fiber is hung inside casing, the fluid distribution can be challenging, especially if the deepest fluid leak is closer to the bottom of the treated interval, because the temperature along the fiber very quickly becomes equal to the fluid temperature with a minimum gradient straight-line pattern due to high fluid rate and velocity. To overcome this condition the use of induced hot/cold thermal tracers together with temperature modeling has been introduced, allowing the calculation of fluid rate distribution along the perforated intervals.
Where the fiber is cemented behind casing, well defined patterns, based on the temperature value, can be recognized to discriminate between flow inside and behind casing, allowing out-of-zone fracture assessment. The thermal coupling of the fracturing fluid inside the casing and the fiber can be very weak at certain levels where small gas "insulation" pockets occur around the fiber, keeping the fiber temperature closer to the geothermal than fluid temperature. At clamp depths or well cemented zones, fiber temperature is much closer to fluid temperature, because the thermal coupling is strong at these levels. When the fracturing fluid flows behind casing, due to bad cement isolation, reaches the fiber cable, the temperature becomes essentially equal to fluid temperature.
The advantages and limitations of both cases are discussed based on the type of well, length of gross pay, fracture design, treatment rate, and type of fluids.
Development and Field Application of a Low pH, Efficient Fracturing Fluid for Tight Gas Fields in the Greater Green River Basin, Wyoming
Authors: Gupta D. V. S. , Jackson T. L. , Hlavinka G. J. , Evans J. B. , Le H. V. , Batrashkin A. , Shaefer M. T. 
Published: September 2008

Abstract
Hydraulic fracturing has proven to be one of the best technologies to improve productivity from tight gas wells. In such low-permeability reservoirs, careful consideration must be given to fracturing fluid selection. Some reservoirs are under-pressured and require the use of energized fluids, while others are sensitive to water-based fluids due to clay swelling and migration.
Proppant pack damage due to gel residue is one the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and therefore maximize production, a new premium highly efficient fracturing fluid was developed. This premium system incorporates low polymer loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep well fracturing and coiled tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide (CO2) and nitrogen (N2) or may also be used in binary foam systems.
This paper will provide details on the new fracturing fluid system, in terms of proppant pack cleanup, rheological properties and fluid loss as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop; fluid leak-off testing; and proppant pack conductivity and regain permeability evaluations are presented.
Field case histories will evaluate fracturing treatments using new fracturing fluid and comparable treatments using conventional fluid. Normalized production data of the treated wells of both systems are also compared.
Corroded Casing: Testing of Sealing Capability and Retrievability of a Swelling Elastomer Packer
Authors: Pradie Emmanuel , Jaafar M. Rushdan , Barnes Chris , Gjelstad Geir , Smith Peter E. 
Published: September 2008

Abstract
Globally, many thousands of potentially productive oil and gas wells suffer internal corrosion due to H2S, CO2, and other produced gases and liquids. This limits their capability to provide a packer sealing area suitable for traditional mechanical production packers. Total E&P Qatar planned a recompletion using intelligent well technology in a well in which they expected to find some corrosion. Before initiating the recompletion, they investigated the use of alternative packer technology.
Swelling elastomer packers have been used worldwide in many applications, but verification was required in this case to assess whether such packers would hold pressure in a corroded section of casing. In addition, testing was also was needed to assess whether the completion could be pulled in the event that it became necessary to retrieve the components from the well.
A swellable packer with multiple cable feed-through was designed and manufactured to approximately two-thirds size of the originally specified packer. A sample of corroded casing, supplied by Total E&P Qatar, was used to build a test jig. The jig was equipped to simulate and record pressure, temperature, and other downhole conditions. Theoretical simulations were performed to assess the force required to overcome the anchoring forces applied by the swelled elastomer and were verified by a pull test.
It is expected that with a reliable sealing mechanism for these older wells, technically and financially viable workovers and re-completions can be performed, thereby extending field life and adding to recoverable reserves.
This paper describes the application and test procedures along with the verification and results of the testing performed.