bluuebunny/crossref_metadata_2025_split huggingface dataset:
From the "What Can I Do for You" to the "What Can You Do for Me" Generation: The Disconnect Between the Establishment and the Youth Culture in the Oil Industry
Authors: LeBas Renee , Edwards W. Jason 
Published: December 2007

Abstract
At no point in the history of the oil and gas industry has the disparity in age between management and entry-level engineers been greater than at the present time. With the rush to hire and educate young engineers occurring at a record-setting pace, salaries are shooting through the roof and attrition is taking place at such enormous rates that companies cannot keep up. With oil and gas prices sitting near all-time highs, the ability of young professionals in the industry to dictate how they wish to move forward and with whom just increases the problems seen by companies. These young engineers often see themselves as their own enterprise within the larger corporate infrastructure and tend to ask, "What can my company do for me?"
This is in contrast to what the established management structure witnessed when they entered the industry. The majority of current managers entered the oil and gas industry during the late 1970s and early 1980s, just as the price of oil was coming to rest at its lowest point. The attitude of most of these upper-level employees is indicative of this, in that they are more prone to ask the question, "What can I do for my company?" With company loyalty quickly becoming a thing of the past, the need to understand what motivates young engineers is vital. With a thorough understanding, adjustments can be made industry-wide to make employee retention easier and more cost efficient. Several young professionals and managers in multiple companies have been interviewed to better understand the conflicting styles of the two demographics and to develop some conclusions concerning how to best move the industry forward in this new era.
Waterflood Performance by Injection of Brine With Different Salinity for Reservoir Cores
Authors: Zhang Y. , Xie X. , Morrow N. R. 
Published: December 2007

Abstract
Both laboratory experiments and field tests indicate that waterflooding with low salinity brine can improve oil recovery. The brine composition and the extent of dilution along with the oil phase and rock properties are all important in the process. Two consolidated reservoir cores with permeability of about 600 md were waterflooded up to 5 cycles by injection of high salinity formation brine of 29,690 ppm, low salinity brine of 1,479 ppm, and two concentrations of sodium chloride. Each core was tested with two crude oils. Either the more viscous crude oil or a viscous mineral oil was used to establish the desired initial water saturation at which mixed wettability was subsequently induced by adsorption from crude oil at reservoir temperature. Displacement tests showed that tertiary recovery from mixed wettability cores by injection of the low salinity brine was significantly higher (7 to 14% OOIP) than given by injection of the high salinity brine. Increased oil recovery was accompanied by slight change in the pH of the effluent brine and sharp increase in the pressure drop across the cores followed by slower decline. No clay was observed in the production stream and the oil/brine interface in the oil/brine separator was clear. No tertiary response occurred when the injection brine was changed to 8000 ppm NaCl solution. Further lowering to 1500 ppm NaCl resulted in 13% OOIP recovery. An additional 4% OOIP recovery was obtained by injection of low salinity brine. For a core that gave strong tertiary response, after replacement of crude oil by refined oil there was only slight recovery and small pressure response to low salinity brine flooding, even though the core was mixed wet because an adsorbed film still remained on the rock surface. Reversion to crude oil as the oil phase restored strong tertiary recovery and pressure response. A large increase in oil recovery was observed for secondary recovery by injection of low versus high salinity brine. Increase in pressure drop across the core was closely related to increase in oil recovery for both secondary and tertiary modes.
Sorption-Induced Permeability Change of Coal During Gas-Injection Processes
Authors: Lin W. , Tang G. -Q. , Kovscek A. R. 
Published: December 2007

Abstract
Our study has two features. First, laboratory experiments measured the change of the absolute permeability of a coal pack as a function of pore pressure and injected gas composition at constant effective stress. Second, adsorption solution theory described adsorption equilibria and aided interpretation. The gases tested include pure methane (CH4), nitrogen (N2), and carbon dioxide (CO2), as well as N2 and CO2 binary mixtures. The coal pack was initially dry and free of gas, then saturated by each test gas at a series of increasing pore pressures and a constant effective stress until steady state. Thus, the amount of adsorption varied while the effective stress was held constant. Results show that (i) permeability decreases with an increase of pore pressure at fixed injection gas composition and (ii) permeability change is a function of the injected gas composition. As the concentration of CO2 in the injection gas increases, the permeability of the coal decreases. Pure CO2 leads to the greatest permeability reduction among all the gases tested. However, a small fraction of N2, 10% to 20% by mole, helps to preserve permeability significantly. According to the mixed-gas adsorption isotherms, adsorption and the selectivity of a particular gas species for a coal surfaces is a function of pressure and the gas composition. Therefore, we conclude that loading of coal surfaces with adsorbed gas at constant effective stress causes permeability reduction. Finally, gas adsorption and permeability of coal are correlated simply to extend the usefulness of study results.
Advanced Mud Gas Logging in Combination With Wireline Formation Testing and Geochemical Fingerprinting for an Improved Understanding of Reservoir Architecture
Authors: McKinney Daniel , Flannery Matthew , Elshahawi Hani , Stankiewicz Artur , Clarke Ed , Breviere Jerome , Sharma Sachin 
Published: December 2007

Abstract
Understanding reservoir architecture is one of the critical factors in successful appraisal and development of any oil/gas field. Increasing drilling costs and environmental challenges has led to the development of alternative appraisal approaches that compliment the more costly and traditional methods such as the drill stem or production test. Therefore, the challenge of obtaining sufficient reservoir and fluid data from complex wells, in short time frames and at manageable costs, has pushed game changing improvements to both mud logging and wire line testing technologies.
In the past, interpretation of wireline formation testing data (e.g., static pressure gradient analysis and downhole fluid analyses), PVT and geochemical fingerprinting have provided major inputs for reservoir modeling related to reservoir continuity. However, none of these tools or data sets provide hydrocarbon distributions or fingerprints during the drilling process of a given well; only after the well has reached final depth and LWD and e-logs have been obtained can one begin to speculate on such matters as reservoir continuity. Until recently, standard mud gas logging technologies did not offer the resolution and sensitivity necessary to provide quantitative hydrocarbon description. However, recent developments in advanced mud gas extractors and improved analytical detectors have increased the sensitivity, reliability and accuracy of mud gas fingerprinting. Thus, during the drilling of a given well, mud gas fluid fingerprints, or fluid facies, can be correlated within a given well and mapped to subsurface structural features such as faults and seals or different hydrocarbon bearing intervals. By providing this during the drilling process, anomalies observed in these fluid facies logs can be investigated in more detail during formation evaluation, sample collection, and geochemical fingerprinting techniques. In addition, by systematically combining and integrating these fundamentally different data streams, a much more robust picture of the reservoir fluid distribution becomes clear.
Advanced Technology Completion Strategies for Marginal Tight Gas Sand Reservoirs: A Production Optimization Case Study in South Texas
Authors: Fairhurst D. L. , Indriati S. , Reynolds B. W. , Lewis J. W. , Holcomb M. W. , Starr F. F. 
Published: December 2007

Abstract
In this case study we address the problems associated with fracturing tight gas sands when nearby water sands are present. Often times the problem is that the created fracture might intersect the water sands which can impede the gas production and in extreme cases can kill the well. Production forecasts based on calibrated permeability values can be performed to show the impact of water production to gas production. If the production forecast indicates that there is enough gas to unload and carry the water to surface then an optimized larger fracture treatment based on effective and relative permeabilities can be performed across both gas and water intervals. If there is not enough gas present to unload the water then the fracture treatment must be carefully designed such that the fracture length is still optimized and water penetration does not occur.
A process is described to optimize completion and stimulation design decisions while reducing uncertainty. Production forecasts are made based on a petrophysically advanced reservoir characterization and stimulation design based on a rock mechanical model adjusted for thin laminations. The actual production results have been compared with the forecasts and the process has been calibrated. These calibrations have led to improved economic results in the field. This production optimization process will apply where there are stacked and laminated tight gas sand sequences in close proximity to water sands. Field production can be increased by fracturing gas sands that are normally thought to be too close to water sands as well as gas sands with high interstitial water that would normally be bypassed. Within this case study, several wells were completed that produced a mixture of gas and water which normally would have been plugged or bypassed. Some wells produced more water than predicted and were not economical. Two wells were completed within 20 ft of obvious water sand by adjusting the job size and water was avoided completely. Six wells were stimulated within 30 ft of water and resulted in economical gas and negligible water production. The combination of magnetic resonance acquired permeability estimates and rock mechanical models adjusted by image enhanced petrophysics provided effective input to modify the stimulation design and enable economic completions for gas sands that were very close to stacked water sands.
Around the world, strands of tight natural gas resource lie unproduced next to and within water bearing sands. The production optimization process that is described combines several completion techniques that incorporate currently available technology to give the completion engineer one more tool to gain access to these reserves. This technique is not geographically limited and applies to any tight gas sand resource.
Pore-Level Analysis of the Relationship Between Porosity, Irreducible Water Saturation, and Permeability of Clastic Rocks
Authors: Torskaya T. , Jin G. , Torres-Verdín C. 
Published: December 2007

Abstract
Permeability is one of the most important, most spatially variable, most uncertain, and hence least predictable transport properties of porous media. Various empirical models, such as Tixier's, Timur's and Coates’ equations, are widely used to quantify permeability from well-log calculations of porosity and irreducible water saturation. However, these models do not explicitly include the role played by rock structure, spatial fluid distribution in the pore space, wettability, or clay mineral distribution on permeability. We present a pore-scale approach to investigate the influence of these factors on the permeability of clastic rocks for explicit pore geometries of brine-saturated granular rocks.
Synthetic pore-scale models are constructed to represent granular sands with variable grain-size distributions. These models include the structural effects of compaction, cementation, and distribution of dispersed hydrated clay minerals. Irreducible water is geometrically distributed on grain surfaces of the synthetic rocks. Permeability is calculated from lattice-Boltzmann flow simulations. A nonlinear relationship between permeability, porosity, and irreducible water saturation is established for these computer-generated rocks. We compare calculated permeability values of computer-generated rocks and laboratory measurements of core samples to those estimated from different empirical approaches, such as Tixier, Coates, and Timur models. It is found that the latter models cannot be applied to general cases of clastic rocks even if their free parameters are adjusted to fit core measurements. Our simulations also show that spatial distributions of clay minerals and irreducible water play a fundamental role in establishing an accurate correlation between permeability, porosity, and irreducible water saturation. Specific deterministic equations must be established for rock formations that exhibit distinct grain-size distributions, clay types, structural clay distributions, and grain cementation.
Estimation of Dry-Rock Elastic Moduli Based on the Simulation of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs
Authors: Odumosu Tobiloluwa , Torres-Verdín Carlos , Salazar Jesùs M. , Ma Jun , Voss Ben , Wang Gong Li 
Published: December 2007

Abstract
Reliable estimates of dry-rock elastic properties are critical to accurately interpreting the seismic response of hydrocarbon reservoirs. We describe a new method for estimating elastic moduli of rocks in-situ by simulating the effect of mud-filtrate invasion on resistivity and acoustic logs.
Simulations of mud-filtrate invasion account for the dynamic process of fluid displacement and mixing between mud-filtrate and hydrocarbons. The calculated spatial distributions of electrical resistivity are matched against resistivity logs by adjusting the underlying petrophysical properties. We then perform Biot-Gassmann fluid substitution on the two-dimensional spatial distributions of fluid saturation with initial estimates of dry-bulk (kdry) modulus and shear rigidity (μdry) and a constraint of Poisson's ratio (v) typical of the formation. This process generates two-dimensional spatial distributions of compressional and shear-wave velocities, and density. Subsequently, sonic waveforms are simulated to calculate shear-wave slowness. Initial estimates of the dry-bulk modulus are progressively adjusted using a modified Gregory-Pickett (1963) solution to Biot's (1956) equation to estimate a shear rigidity that converges on the log value of shear-wave slowness. The constraint on Poisson's ratio is then removed and a refined estimate of the dry-bulk modulus is obtained by both simulating the acoustic log (monopole) and matching the log-derived compressional-wave slowness.
This technique leads to reliable estimates of dry-bulk moduli and shear rigidity that compare well to laboratory core measurements. The resulting dry-rock elastic properties can be used to calculate seismic compressional-wave and shear-wave velocities devoid of mud-filtrate invasion effects for further seismic-driven reservoir-characterization studies.
Mad Dog Slot W1 Tubing Deformation Failure Analysis
Authors: Pattillo P. D. , Sathuvalli U. B. , Rahman S. M. , Prewett H. H. , Carmichael S. P. , Wydrinski R. 
Published: December 2007

Abstract
On 20Apr05, while bringing Mad Dog Slot W1 back on production after a brief shut-in, pressure developed on the A annulus and persisted despite repeated bleeds. Diagnostic pressure tests and logs eliminated a number of possible sources of the annulus pressure, eventually leading to the conclusion that the 9-7/8 in. production tieback had been breached. Further investigative logs led to the observation of ovalization of the production tubing.
This study summarizes the efforts of the team assigned to investigate the causes of the production tubing and casing deformation. The outcome of the analysis suggests a subtle failure mode, ultimately related to attempts at annular pressure build-up mitigation. The subtlety emphasizes the importance of (a) design considerations in uncemented annuli opposite salt, (b) the importance of creating a complete cement sheath and (c) the inherent difficulties in converting an appraisal well into a producing well.
The study concludes with a brief review of the changes implemented in the replacement well intended to eliminate a repeat of the identified failure mechanism(s).
Near-Wellbore Modeling: Sand Production Issues
Authors: Servant Guillaume , Marchina Philippe , Nauroy Jean-François 
Published: December 2007

Abstract
Sand production in an oil or gas well can cause additional operational difficulties, but contributes to production enhancement by improving the well inflow performance. In order to be able to assess the relatve magnitude of those two effects and to optimize the well completion and operation philosophy, a quantitative forecast of the expected amount and rate of sand production must be established. It requires a correct description of all the mechanisms involved in the phenomenon of sand production, sand transport in particular.
The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations which control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale.
Sand production experiments in the laboratory on cohesionless sand samples carried out under CT-scan are used to calibrate the model and show its ability to reproduce the main sand production features.
The results of this fully coupled scheme show the importance of the transport of sand within the reservoir, in particular the effect of a non homogeneous slurry viscosity, for a proper modeling of the sand production process.
Characterization of Arab Formation Carbonates Utilizing Real-Time Formation Pressure and Mobility Data
Authors: Seifert Douglas J. , Neumann Peter M. , Dossary Saleh M. , Chew Kuen Kong , Hahne Ulrich , Bacciarelli Mark , Pragt Jos 
Published: December 2007

Abstract
Wireline logging formation testing tools have long been used in the Arabian Peninsula for open hole formation pressure testing.Presently, a large number of wells are being drilled horizontally as producers and injectors, and often even as multilateral wells. This aggravates or prevents the use of conventional wireline logging technology. Formation pressure data are required to monitor the efficiency of production and injection for pressure maintenance.
The Arab formation is a very prolific producing formation that consists of several members deposited in a carbonate shelf environment. Besides formation pressure, a representative permeability is an important element of the data acquisition. The Arab formation porosity and permeability are variable and dependant on original facies, mineralogy and diagenesis. Highly porous rock can have variable permeability dependant on a number of these factors.
Conventional logs can show zones to be porous and hydrocarbon filled. These zones can be difficult to produce or inject due the presence of viscous heavy oil and tar. Therefore complicating the geosteering of the horizontal producers and injections. It has been found that the best way of recognizing such zones reliably, is through the utilization of real-time formation pressure testing data while drilling, preferably combined with magnetic resonance data.
This paper will discuss examples of carbonate reservoir characterization utilizing formation pressure testing in combination with a full LWD logging suite. Operating procedures were specifically optimized to allow quality control of each acquired data set. An extensive, highly detailed, data set was transmitted to the end user, displayed real time both on the rig-site as well as in the operator datacenter to properly place the horizontal well for its intended objective.
Complex Fracture Geometry Investigations Conducted on Western-Siberian Oil Fields at Rosneft Company
Authors: Nikitin A. , Shirnen A. , Maniere J. 
Published: December 2007

Abstract
The generalization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height, half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model where the height is indirectly obtained from coupling stress profile and fluid flow. Fracture azimuth is traditionally provided by the horizontal stress anisotropy from open hole sonic logging. Unfortunately, in West Siberia at depth of 2500-3000 meters, there is negligible tectonic and open hole sonic dipole did not provide obvious fracture orientation. Fracture height growth affect mostly fracture job size and cost. Height growth has also shown to be a cause of premature wellbore screen out. Fracture half-length and orientation can have a significant impact on the effectiveness of pressure maintenance and flood efficiency. A review of world publication of direct fracture geometry measurement has shown the validity of seismic methods and tilt indicators for tight rock, such as carbonates and tight sandstone. However, all experiments on soft sandstones, such as found in West Siberian, have shown more limited results.
Given the uncertainties in effective Fracture geometry and the negative impact that they could have on the field development, Rosneft decided to invest in a field research study denominated Fracture Geometry Investigation, to validate various method offered by the service industry. Two basic methods were tested and combined: wellbore logging and passive seismic. Wellbore logging is used to obtain an estimate of wellbore fracture height. It combines temperature log immediately after Minifrac or after Frac and Cased Hole Sonic Anisotropy (CHSA) which can be run at any time after frac. The direct estimate of fracture height is used to validate the result of a calibrated HF simulator using Net Pressure matching analysis. Passive Seismic monitoring (PSM) is used to obtain direct estimate of height, length and azimuth. PSM Acquisition must be done during hydraulic fracturing from the nearest well.
The main goal of this study was to validate each method's effectiveness and to construct a calibrated fracture model for the particular reservoir under investigation. The results of this investigation will be used to optimize fracture design, pressure maintenance strategy and pattern orientation.