bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Test of a Downhole-Activated Centralizer To Reduce Casing Drag
Authors: Kinzel Holger , Calderoni Angelo 
Published: December 2007

Abstract
A good cementation is based on an adequate centralization. Conventional bow-type centralizers create a drag force, which is not acceptable under certain conditions. The downhole-activated centralizer (DACTM ) was developed for use in highly inclined wells and whenever restrictions in the wellbore like close tolerance wellheads have to be passed. It can be released by external hydraulic pressure, by temperature or by a chemical reaction.
The first downhole-activated centralizers with pressure released locking mechanism were field tested in two wells offshore Italy.
These field tests proved the function and the effectiveness of the downhole-activated centralizers under operational conditions.
Comparison and Verification of Electric-Log-Derived Rock Stresses and Rock Stresses Determined From the Mohr Failure Envelope
Authors: Hareland Geir , Harikrishnan Ramesh 
Published: December 2007

Summary
This paper evaluates the correlation between values of minimum principal in-situ stress derived from sonic logs and those obtained from triaxial core tests and coefficient for earth at rest correlations. The minimum principal in-situ stress is then compared to actual field mini-frac test data, which accurately determine the minimum principal in-situ stress and are used to verify the accuracy of the correlations. The cores and the mini-frac stress test were obtained from two wells, the Gas Research Inst.'s (GRI's) Staged Field Experiment (SFE) #1 well through the Travis Peak Formation in the East Texas Basin, and the U.S. Dept. of Energy's Multiwell Experiment (MWX) wells located west-southwest of the town of Rifle, Colorado, near the Rulison gas field. Results from this study indicate that of the two approaches used in obtaining the minimum principal in-situ stress, the normalized Mohr failure envelope approach is in better agreement with the measured stress values (from mini-frac tests) in sandstone, while the sonic log approach gives closer match in shale.
A Study of Formation Damage of Selective Clay and Other Minerals Caused By Bacterial Plugging
Authors: Hayatdavoudi Asadollah , Ghalambor Ali 
Published: December 2007

Summary
In this study, we investigate the nature of formation damage caused by growth of bacteria on formation minerals. The bacteria growth results in plugging the pores with consequent reduction in permeability. We performed experiments by injecting live bacteria cells through pipettes packed separately with different clay and nonclay minerals. We tested a total of eight minerals: nonclay (quartz, feldspar, calcite, and olivine) and clay (illite, kaolinite, calcium montmorillonite, and sodium montmorillonite). Bacteria used for the experiment was Bacillus Cereus. A 10% trypticase soy broth (TSB) solution as a brine was passed through packed minerals, and the flow rates were recorded periodically before and after the bacteria injection. The flow pressure, temperature, and the concentration of bacteria cells were held constant during these experiments. The absolute permeability of packed porous media was determined with Darcy's equation. The pore plugging effects were analyzed with the percentage ratio of reduced absolute permeability to the initial absolute permeability vs. the injection PV.
We measured the zeta potential for each mineral under test before and after its interaction with bacteria. This was another way of testing the affinity of bacteria with a negative charge toward any particular mineral and their subsequent accumulation around that mineral in the pore space. For this purpose, we used a particle microelectrophoresis instrument to measure the zeta potential of the bacteria, the minerals under test, as well as the cumulative zeta potential of mineral-bacteria assemblage.
Permeability measurements and zeta potential readings indicate that the type of mineral present has a significant effect on plugging characteristics of the porous media. We determined that olivine as compared with other minerals had the highest tendency to attract bacteria. The reason for this appears to be the abundance of magnesium and iron as nutrient sources for bacteria. These studies also showed that both clays (calcium and sodium montmorillinite) carry a larger net negative charge than other clay minerals after interaction with bacteria. To be certain about the accuracy of the results of mineral-bacterial interaction, we measured the optical density of solutions as well with a third testing before and after injection of bacteria into porous column. Furthermore, we verified the growth and plugging effect of bacteria in the minerals porous column through the use of a scanning electron microscope (SEM). As remedial measures, although not a part of this work, we have recommended a few techniques.
Application of a Microbial Selective-Plugging Process at the North Burbank Unit: Prepilot Tests
Authors: Jenneman G. E. , Moffitt P. D. , Young G. R. 
Published: December 2007

Summary
Microbial enhanced-oil-recovery (MEOR) nutrients were injected in an injection well at North Burbank unit (NBU) in Oklahoma to plug off high-permeability layers through the growth of indigenous microorganisms and to divert injection fluid to lower-permeability, higher-oil-saturation zones. Several different types of treatments were performed using both sequential and co-injection of nutrients. Pressure falloff/injection tests and vertical injection profiles were conducted before and after nutrient injection. The results of pressure injection tests following co-injection of nutrients and an incubation period indicated a 33% drop in the effective permeability to the injection fluid and a negative skin factor, while injection profile surveys showed a 33% reduction in the zone taking water. Swabbed samples from the injector following shut in revealed abundant bacterial concentrations and products as well as oil and inorganic solids. Although significant in-depth permeability reduction was observed following nutrient co-injection tests, the unstable behavior of the plug suggested that insufficient biomass was being formed to effectively seal off the higher-permeability zones.
Recent Advances in Understanding Perforator Penetration and Flow Performance
Authors: Halleck P. M. 
Published: December 2007

SummaryDriven by the importance of perforation performance in both natural and stimulated completions, our understanding of the factors that control penetration depth and formation damage has improved significantly over the last 10 years. Improved test procedures and their tabulated results are now available to predict downhole penetration as a function of rock properties and overburden stress. Progress has also been made in understanding the nature of permeability damage around perforations and how to prevent, remove, or bypass it. In particular, the mechanisms behind underbalanced perforating are being clarified, leading to better engineering of perforating procedures and better prediction of their results.
A New Unfree Fluid Index in Sandstones Through NMR Studies
Authors: Borgia G. C. 
Published: December 2007

Summary
Nuclear magnetic resonance (NMR) of 1H nuclei of liquids in saturated porous rocks furnishes an increasingly important tool in core analysis as well as in well-logging. In particular, there are several basic questions regarding NMR downhole logging in reservoir sandstones. For this reason, it is of interest to investigate the laboratory NMR properties to identify some important basic mechanisms. This paper presents new correlations among porosity, ϕ, irreducible water saturation, Swi, formation resistivity factor, F, and the geometric mean longitudinal relaxation time, T1g. Equilibrium magnetization and longitudinal relaxation, T1, measurements were performed on 57 clean sandstone samples from 12 oil and gas reservoirs. NMR measurements ϕNMR of ϕ agreed very well with conventional porosity measurements. The product of porosity and irreducible water saturation is approximately equal to an unfree fluid index, UFFI=(ϕNMR/T1g)2/3, giving an error-of-estimate factor of 1.24. The best estimate of Swi based on a simple cut-off relaxation time (35 ms) gave an error factor of 1.6. The present correlation of Swi with ϕNMR and Tig is nearly as good as the correlation using T1g and F, and it has the advantage of requiring only NMR measurements on fully saturated samples. No further improvement in correlation with Swi was obtained by using T1g with both ϕ and F over that with T1g and F only. The correlation with F was slightly better than that with ϕ. The effectiveness of using both T1 and either F or ϕNMR is plausible, since T1, being sensitive to surface-to-volume ratio, gives some information on pore or pore channel dimensions, while ϕNMR, being correlated with F, gives some information on connectivity within a sandstone. Large pores connected only by very small channels contribute to long T1 but contribute also to Swi. The above use of ϕNMR and T1 should be useful for laboratory measurements on cores; furthermore, since T2 is closely related to T1 at the low measurement frequencies used in nuclear magnetism logging, it is very likely that a similar relationship (probably with different parameters) may relate Swi to ϕNMR and T2 obtained in downhole measurements.
Characterization of a Complex Fluvial-Deltaic Reservoir for Simulation
Authors: Begg S. H. , Kay Alex , Gustason E. R. , Angert P. F. 
Published: December 2007

Summary
Lithotype is shown to be the main geological control on the spatial distribution of reservoir flow properties. The distribution of lithotypes is in turn controlled by lithofacies. Using core data, assemblages of lithotypes were grouped into major facies associations (MFA's). Log signatures were used to pick MFA's in uncored wells to provide conditioning data for a stochastic description of their interwell distribution using the sequential indicator simulation (SIS) technique. Deterministic correlation was not enforced.
Characteristic object-models of the distribution of lithotypes within each MFA were then generated and converted to fine-scale poro-perm models using core-plug data. These models were ups-caled to yield characteristic poro-perm distributions at the reservoir simulation scale. Finally, the MFA model was used as a template to distribute the upscaled poro-perm within the simulation model. The model history-matched rapidly and accurately, even though the wells were conditioned only to the MFA's and not to foot-by-foot data. Multiple MFA realizations were generated to provide some understanding of the uncertainty in thickness and other rock properties between wells.
A Wellbore/Reservoir Simulator for Testing Gas Wells in High-Temperature Reservoirs
Authors: Kabir C. S. , Hasan A. R. , Jordan D. L. , Wang Xiaowei 
Published: December 2007

Summary
Gas wells frequently exhibit changing storage during a transient test because of high fluid compressibility. Further complications may arise owing to heat exchange between the wellbore fluid and the formation, especially in high-temperature reservoirs. Thus, fluid temperature changes during a transient test, thereby complicating test interpretation when surface measurements must be used in a hostile downhole environment.
This paper describes the application of a wellbore/reservoir simulator. This simulator can be run in two modes. In forward modeling, the wellhead pressure, temperature, and bottomhole pressure can be computed as a function of time, given reservoir parameters and well-completion details. In contrast, reverse simulation directly translates measured wellhead pressure (WHP) and temperature (WHT) to bottomhole pressure (BHP) for subsequent analysis.
Forward simulation of wellbore pressure and temperature is a valuable tool for designing transient well tests. In particular, in a hostile downhole environment, the ability to estimate BHP accurately from wellhead measurements is an invaluable asset where downhole measurements may not be cost effective. Even in favorable situations, the simulator can aid both test design and interpretation.
Application of the simulator to field examples has helped us gain considerable insight into the mechanics of transient flow in the wellbore. For example, we observe a denser fluid toward the wellhead rather than at the bottom of the well because of the temperature effect. Consequently, decreasing storage behavior is observed at the bottom of the well.
Two field examples obtained from a Gulf Coast gas field are used to illustrate the capabilities of the simulators. Good agreement is noted between the computed and measured BHP's during both types of simulations.
The Role of Geology in the Behavior and Choice of Permeability Predictors
Authors: Ball L. D. , Corbett P. W. M. , Jensen J. L. , Lewis J. J. M. 
Published: December 2007

Summary
For effective flow-simulation models, it may be important to estimate permeability accurately over several scales of geological heterogeneity. Critical to the data analysis and permeability prediction are the volume of investigation and sampling interval of each petrophysical tool and how each relates to these geological scales. We examine these issues in the context of the As Sarah Field, Sirte Basin, Libya.
A geological study of this braided fluvial reservoir has revealed heterogeneity at a series of scales. This geological hierarchy in turn possessed a corresponding hierarchy of permeability variation. The link between the geology and permeability was found to be very important in understanding well logs and core data and subsequent permeability upscaling.
We found that the small scale (cm) permeability variability was better predicted using a flushed-zone resistivity, Rxo, tool, rather than a wireline porosity measurement. The perm-resistivity correlation was strongest when the probe permeabilities were averaged to best match the "window size" of the wireline Rxo. This behavior was explained by the geological variation present at this scale. For the larger scale geological heterogeneity, the production flowmeter highlighted discrepancies between flow data and averaged permeability. This yielded a layered sedimentological model interpretation and a change in averaging for permeability prediction at the bedset scale (ms-10 × ms).
Effects of Viscous Fingering on Fracture Conductivity
Authors: Pope D. S. , Leung L. K. , Gulbis J. , Constien V. G. 
Published: December 2007

Summary
Understanding the causes of damage to fracture conductivity is vital in design of fracture treatments for maximum economic value and to analyze the actual well performance. High-viscosity fluids, resulting from retention of polymer within the proppant pack during closure, play a major role in proppant-pack damage. Viscous fluids are not effectively displaced during flowback and production of hydrocarbon unless the viscosities of the phases are similar. The consequences of viscous fingering in the fracture are discussed, and a method is presented for predicting the retained permeability of proppant packs in which guar-based hydraulic fracturing fluids have been broken. Data required for the method are temperature, polymer molecular weight, and final polymer concentration.
An Experimental Study on Downward Slug Flow in Inclined Pipes
Authors: Roumazeilles P. M. , Yang Jiede , Sarica Cem , Chen X. T. , Wilson J. F. , Brill J. P. 
Published: December 2007

Summary
The downward simultaneous flow of gas and liquid is often encountered in hilly terrain pipelines and injection wells. Most of the methods for predicting pressure drop in gas/liquid, two-phase flow in pipes have been developed for either upward vertical or upward inclined pipes. This study experimentally investigates downward co-current slug flow in inclined pipes. A new test facility was designed and built to acquire data for the entire range of pipe inclination angles. A series of slug flow experiments was conducted in a 2-in. diameter, 65-ft long clear PVC pipe installed on an inclinable structure. Liquid holdup and pressure drop measurements were obtained for downward inclination angles from 0° to −30° at different flow conditions. Translational velocity and liquid-slug holdup correlations were investigated based on the acquired data for different inclination angles.
Real-Time Monitoring of Matrix Acidizing Including the Effects of Diverting Agents
Authors: Hill A. D. , Zhu Ding 
Published: December 2007

Summary
Real-time monitoring of the injection rate and pressure during matrix acidizing provides operators with a way to determine the changing skin factor as stimulation proceeds. Current methods are based either on the assumption of steady-state flow in the region around the wellbore affected by acid injection or on computer solution of the transient flow equations describing the unsteady reservoir flow process occurring during acidizing. In this paper, a new method for real-time monitoring of matrix acidizing, the inverse injectivity vs. superposition time function plot, is presented. This new method can be applied with a spreadsheet computer program or a programmable calculator and accounts for the transient flow effects occurring during matrix acidizing at multiple rates and injection pressures. The evolving skin factor during a matrix treatment is readily obtained from the diagnostic plot. Hypothetical examples show how the inverse injectivity plot can be used to assess the efficiency of stimulation and diversion. Comparisons with previously presented field cases show the new method to be a simple and accurate means of monitoring the evolving skin factor during matrix acidizing.
Fracture-Injection-Test Interpretation: Leakoff Coefficient vs. Permeability
Authors: Mayerhofer M. J. , Economides M. J. 
Published: December 2007

SummaryDetermining the leakoff coefficient from a minifracture pressure decline has become a relatively common industrial procedure. A main assumption of the method, which is often referred to as the Nolte analysis, is a constant leakoff coefficient. Frequently there is no constant leakoff coefficient. The definition of the coefficient is based on a constant pressure differential and a prescribed mode of leakoff. In contrast, the analysis for fracture-pressure decline, introduced by Mayerhofer et al.,10 couples unsteady-state linear flow from the fracture with a varying skin effect at the fracture face, and superposes the leakoff history on the pressure decline. This guarantees a correct rate convolution to account for pressure-dependent fluid loss. The reservoir permeability, fracture-face resistance, and leakoff area can be determined. A comparison of the two methods and their relationship is presented in this paper, using real field cases. We show that the use of modern well-testing log-log diagnostic plots to determine fracture closure pressure is superior to drawing a straight line on a G-function plot or a square-root-of-time plot.
Wettability and Spreading: Two Key Parameters in Oil Recovery With Three-Phase Gravity Drainage
Authors: Vizika Olga , Lombard J. -M. 
Published: December 2007

Summary
The objective of this paper is to show that the porous medium wettability and the spreading characteristics of the fluid system hold the key roles in three-phase gas injection, and to study to which extent these two parameters affect oil recovery and phase distributions. To this end gravity assisted inert gas injection experiments have been performed in water-wet, oil-wet and fractionally-wet porous media for spreading and nonspreading conditions. The experiments are simulated and the oil and gas relative permeabilities for three-phase flow are calculated by history matching. It is proved that the existence of wettingandspreading oil films—caused by wettability and spreading—greatly affects the flow mechanisms and consequently the recovery kinetics and the process efficiency. The results are interpreted in terms of physicochemical parameters on the basis of pore scale mechanisms.
Offshore Application of a Novel Technology for Drilling Vertical Boreholes
Authors: Foster P. E. , Aitken A. 
Published: December 2007

Summary
A new concept for automatically drilling vertical boreholes was recently implemented by Elf Enterprise Caledonia - the Vertical Drilling System. The VDS was used to drill the 16" hole section of a North Sea exploration well. This was the first time this technology had been used offshore, drilling from a semi-submersible drilling unit. The VDS was shown to have an application in penetrating a drilling target that required a near vertical wellbore. Technical functioning of the tool and field experience is reported along with performance comparisons to offset wells.
Lateral-Jet Hydraulics and Oval-Cutter Technology Combine To Improve PDC Performance, North Sea Scott Field
Authors: Lewis J. P. , Begbie R. J. , Simpson Neil 
Published: December 2007

SummaryThe successful implementation of lateral-jet polycrystalline diamond cutter (PDC) hydraulics has emerged over the last few years with quantifiable results. Lateral jets set into the blades of the bit improve the cutter cleaning efficiency, thereby increasing the rate of production (ROP). In addition to cleaning the plenum in front of the jet, fluid entrainment creates a Venturi effect, drawing the fluid across the blades serviced by the downward jets. This flow is then ejected at high speed to the junk slots.The operators of the North Sea Scott field took a major initiative in this development, and in conjunction with the lateral-jet company, expanded the technology to initiate a new cutter design and the second generation of lateral-jet-type bits, the fully lateral-jet PDC drill bit.This paper will track the development of the technology from the initial trials of lateral jets in the Scott field, the rationale and design criteria that initiated oval PDC cutters, and most recently the fully lateral-jet bit.
Causes and Solutions to Surface Facilities Upsets Following Acid Stimulation in the Gulf of Mexico
Authors: Durham D. K. , Ali S. A. , Stone P. J. 
Published: December 2007

Summary
Severe upsets frequently occur in surface treating facilities following acid stimulation in the Gulf of Mexico. Such upsets usually occur after fluids from the stimulated well are commingled with fluids in the system. Often the emulsions formed are extremely difficult to treat, requiring either large amounts of chemicals or unusually long separation times. These problems, combined with the more stringent discharge limits on produced water in the Gulf of Mexico, make the control of acid flowbacks a vital consideration in maintaining an acceptable and consistent discharge water quality.
This paper presents test data on the effects of acid and acid additives on emulsion and water treating in the Gulf of Mexico. This work also discusses the test methods developed to select acid additives and treating chemicals that will allow the producer to treat both oil and water more consistently and cost effectively while the acid flowback is in the system. It also presents system results that confirm the importance of the joint selection of acid and surface treating additives and show that significant cost savings can be gained by use of this process.
Also discussed are the proper system application techniques for treating chemicals that can minimize surface treating problems caused by acid flowbacks. The results show that the proper selection and use of acid additives and surface treating products can eliminate or significantly reduce costly upsets in oil- and water-treating systems. Data on individual acid additives that impact water and oil treating are also presented. The results of this work are currently being used to solve produced-water- and oil-treating problems on offshore and onshore facilities in and around the Gulf of Mexico by reduction of production losses resulting from acid-flowback-related problems; reduction of the use and cost of tanks and barges used to segregate acid flowbacks; and development of effective methodology to select acid and surface treating additives that have resulted in lower overall treating costs.