bluuebunny/crossref_metadata_2025_split huggingface dataset:
Trends and Strategies for Drilling Computing
Authors: Payne M. L. , Church C. J. , Ng F. W. 
Published: December 2007

Abstract
There is currently considerable activity focused on implementing computing technology in the petroleum industry. In drilling, projects have included real-time field data acquisition for enhanced operations monitoring, databases for management of drilling information, drilling accounting systems for better cost control, drilling simulation for performance optimization, advanced numerical techniques for specific problems, office automation for personnel efficiency, and expert systems for solving rule based problems.
Priorities in these areas vary between operators. As a result, much more technology exists than has been implemented by any single operator. Because costs for these systems are substantial, most majors are incrementally building drilling computing systems on a priority basis that will ultimately address the full scope of the above functions. This paper reviews general background and current technology for drilling computing and details ARCO's current drilling computing environment and its visions for the future in the area.
The Effects of Quasi-Random Drill Bit Vibrations Upon Drillstring Dynamic Behavior
Authors: Skaugen E. 
Published: December 2007

ABSTRACT
One of the main sources of drillstring vibrations is the interaction between the drill bit and the formation. Downhole measurements of forces and accelerations within the bottom hole assembly have shown that the vibrations at the bit have large quasi-random components, both for axial and rotational movements. These quasi-random vibrations are probably due to unevenness of the formation strength, random breakage of rock, and amplification of these effects by vibration mode coupling.
A drillstring dynamic model operating in the time domain has been developed in order to investigate the effects of these quasi-random vibrations upon drillstring behaviour.
It is shown that by including the observed, quasi-random vibrations, the drillstring dynamic behaviour may be substantially different from the behaviour predicted by the deterministic drillstring models used in earlier investigations. In particular, these models predict sharply increased vibration amplitudes when rotary speed is a certain subharmonic of resonance frequences in the drillstring. The model presented here shows that these resonance peaks are considerably reduced and smoothed out when the observed quasi-random nature of the drill bit vibrations is taken into account. The results of the model are compared to drillstring vibrations observed during drilling, and when using a downhole exciter.
A Petrophysical-Mechanlcal Math Model for Real-Time Wellsite Pore Pressure/Fracture Gradient Prediction
Authors: Holbrook P. W. , Hauck M. L. 
Published: December 2007

Abstract
Petrophysical-mechanical math modeling is an entirely new approach to Pore Pressure/Fracture Gradient prediction. Traditional petrophysical techniques are used to estimate rock porosity, (ϕ) and relative shale volume (Vshale). In this new methodology, pore pressure is calculated from earth stresses rather than empirical fluid pressure relationships.
Overburden stress is an integrated bulk density log derived from porosity, (ϕ) and Vshale. Effective vertical stress is calculated from porosity, (ϕ) for each lithology (Vshale) using the Rubey & Hubbert (1959) relationship. Pore Pressure is the difference between overburden and effective vertical stress, following the Terzaghi (1923) relationship. Fracture propagation pressure is the sum of effective horizontal stress and pore pressure. In relaxed sedimentary basins, effective horizontal stress is calculated from effective vertical stress for each lithology (Vshale). Visco-plastic rather than elastic rock properties are used to calculate effective horizontal stress.
This new methodology has been used on 17 wells in the Gulf of Mexico. Well planning is done by batch processing of log data. Drilling operations are supported by real-time processing of MWD log data at the wellsite. Accuracy has been better than 1/2 ppg where lithologic discrimination was good and stress modeling assumptions were met.
Estimation of Parameters for Drilling in Arctic and Offshore Environment in the Presence of Hydrates
Authors: Roadifer R. D. , Godbole S. P. , Kamath V. A. 
Published: December 2007

ABSTRACT
The presence of gas hydrates in Arctic and subsea regions is well documented. Hydrate cores have been obtained from the Gulf of Mexico, the western coast of Guatemala, and in 1972, ARC0/EXX0N recovered a hydrate core sample near Prudhoe Bay, Alaska (Holder et al, 1984). In addition, hydrate deposits in the Canadian and Russian Arctic are known to exist (Makogon, 1965; Bily and Dick, 1974).
Irrespective of the location, drilling through hydrate formations can cause well control problems due to severe mud gasification if proper drilling procedures are not followed. Sizable gas kicks and potential blowout conditions have been reported in the literature (Davidson et al, 1978; Franklin, 1979). The potential for well control problems due to hydrates is expected to increase in the future as further exploratory drilling occurs in known or potential hydrate stability areas; e.g., drilling activities in offshore and onshore Alaska can significantly increase in the future when ANWR (Arctic National Wildlife Refuge) is opened for oil and gas leasing (OGJ, 1986A, B).
Currently, two different methods are used to drill through hydrate containing formations. Predominately, cool drilling fluid with higher mud weight at high circulation rates is used to slow or prevent hydrate dissociation in the formation. Panarctic Oils Ltd., alternatively, tries to promote the dissociation at early times while the drill pipe is in the hole by using low weight muds with proper degassing equipment at the surface (Franklin, 1980).
A thermal simulator developed earlier (Roadifer, et al, 1987) is modified to model the dissociation of hydrates under a wide range of drilling conditions. Major new features include the coupling of wellbore heat transfer and hydraulics with the hydrate dissociation model. Well configuration and makeup are user specified and included in the wellbore calculations. Either arctic or subsea locations and corresponding geothermal and pressure gradients may be specified. For arctic regions, the melting of permafrost may be modeled concurrently with the hydrate dissociation.
The results are presented in a series of nomograms and plots for both arctic and subsea hydrate locations. These nomograms can be used quickly and easily to determine drilling parameters required to keep hydrate dissociation within the limits of the surface gas equipment, or alternatively, given the drilling fluid parameters, design criteria for the surface equipment can be established.
A New Class of Filtration Control Polymers Offer Exceptional Electrolyte Tolerance
Authors: Clements W. R. , Jarrett M. A. , Morton E. K. 
Published: December 2007

ABSTRACT
This paper describes a new polyanionic lignin (PAL) filtration control polymer. The material imparts filtration control to a wide variety of water base drilling fluids. It is very temperature stable and contaminant tolerant.
The chemistry and structure of this polymer is compared to existing filtration control materials. Laboratory data is presented to show a relative comparison of PAL to other common filtration control additives.
PAL has been used in South Texas, the Gulf of Mexico, Italy and the North Sea. Field applications and observations are discussed. This material has broad application in environmentally sensitive areas because of the absence of heavy metals including chrome. A combination of PAL and polymeric deflocculants can be formulated to give more cost effective systems than traditional lignite-lignosulfonate systems.
New Chemical Package Produces an Improved Shale Inhibitive Water-Based Drilling Fluid System
Authors: Wingrave J. A. , Kubena E. , Douty C. F. , Whitfill D. L. , Cords D. P. 
Published: December 2007

ABSTRACT
Quantitative shale stability performance data based on a new testing procedure (Dynamic Pellet Test or DPT) were used to quantitatively rank the shale stability performance of over 30 chemical species. Shale stability performance of over 3500 aqueous solutions or muds on over 20 different shale or clay samples was done. The test results allowed the following four conclusions about shale stability induced by inorganic and polymeric chemicals to be drawn: –inorganics alone are inadequate,–potassium ion is significantly better than any other cation in shale stability performance,–hydrogen bonding polymers are most effective and,–high molecular weight polymers (up to the limit of solubility) are most effective.
From the results of this work, a particularly effective shale stabilizing additive package for aqueous muds was identified. The exceptional shale stabilizing performance of these chemical structures is based on a chemical synergism uncovered through DPT testing. Typical drilling fluid formulations and their laboratory properties will be discussed, including tests conducted on a heated/pressurized flow loop.
Flow Patterns Under a Tricone Bit Determined From Pulsed Wire Anemometry and Flow Visualization
Authors: White D. B. , Escudier M. P. , Gavignet A. H. 
Published: December 2007

ABSTRACT
At present, the optimization of drilling hydraulics consists of selecting nozzle sizes that maximize either jet impact or hydraulic power at the nozzle, whilst ensuring that the flow rate is sufficient to transport cuttings to the surface. If this crude approach is to be improved upon, what is required is an understanding of the cleaning mechanism at the work face, i.e. the action of hydraulic forces on the crushed rock. Previous investigations of the problem have focussed on the measurement of the mean and fluctuating pressure field under the bit, and on the distribution of fluid velocities.
We report here measurements of the mean and fluctuating shear stresses on the surface under a 8 1/2 in. roller J jet bit for a number of different nozzle geometries. The shear-stress maps obtained are shown to be consistent with the results of surface flow visualisation performed for the same bit. For a given configuration, the flow patterns observed were independent of nozzle size, and the measured shear stresses scaled with the momentum flux (at the nozzle).
The values of shear stress measured are two orders of magnitude greater than that required to move a chip and suggest that it is an important mechanism for bit cleaning. In a two-nozzle configuration, a major stagnation region is found to be situated at, about 2/3 radius whereas in the three nozzle case the stagnation zone is at the center of the hole. Since the flow pattern rotates with the bit, in the two nozzle case the areas of low shear stress are immediately followed by high shear stress and this sequence may prevent the build up of cuttings. This suggests a possible explanation for the observation that two nozzles can lead to faster drilling rates than three.
Optimizing Journal Bearing Insert Bit Runs Using a Bearing Life Model
Authors: Doiron H. H. , Tompkins L. B. , Watts T. 
Published: December 2007

ABSTRACT
Advances in journal bearing insert bit technology have yielded very versatile bits which can often be run cost effectively at weight-on-bit (WOB) and RPM combinations which exceed manufacturers' catalogue recommendations. Insert breakage rather than tooth wear is the primary cutting structure concern at high mechanical horsepower levels. Field experimentation yields data on allowable WOB and RPM to avoid insert breakage. Below these WOB and RPM restrictions, insert wear is negligible, so the remaining unknown in WOB and RPM optimization is bearing life. This paper presents a semi-empirical bearing life model for journal bearing bits and a method for field implementation which has been useful in predicting bit life for insert bits. The model expresses expected bearing life within a given formation and depth range as a function of WOB and RPM. The model is also suitable for predicting bearing life for bits run on downhole motors.
Data are presented to show statistical correlation of the bearing life model with actual field results. A method for using the model to select WOB and RPM to minimize cost-per-foot of bit runs is presented. A successful case history using the bearing life model to predict bit life on high WOB and RPM downhole motor runs is also presented.
Use of Torque Analysis To Determine Tricone Bit Bearing Failure
Authors: Peltier B. P. , Cooper G. A. , Curry D. A. 
Published: December 2007

ABSTRACT
The early stages of roller cone bit bearing failure have been detected by using a moving window to analyse changes in torque and weight on bit. Choice of window width enables other effects, such as changes in rock properties, to be tuned out of the diagnosis.
Simulation of Compositional Flooding Using Third-Order Difference Techniques
Authors: Taggart I. J. , Pinczewski W. V. 
Published: December 2007

ABSTRACT
Conventional compositional simulators based on low order discretization techniques introduce unacceptably high levels of numerical dispersion and anisotropies (grid orientation sensitivity) when applied to miscible or multicontact miscible displacement processes. A simple, uniformly third order finite-difference scheme is developed which successfully overcomes these problems. A novel modification to the leading truncation term allows solutions to be obtained which are insensitive to grid orientation without reducing the order of accuracy of the solution.
The high order schemes developed are applied to one-dimensional multicontact miscible displacements where they are shown to predict recoveries considerably different to those obtained with low order schemes. In two-dimensional miscible displacements the high order method is used to study the growth of viscous fingers and the effect of gravity segregation in the presence of strong compositional effects. Comparisons with results obtained using low order methods suggest that the high order scheme has the potential to significantly reduce the computational effort involved in compositional simulation.
The Effects of CO2 Flooding on Wettability of West Texas Dolomitic Formations
Authors: Potter G. F. 
Published: December 2007

ABSTRACT
Reduced water injectivity after CO2 injection has frequently occurred in West Texas oil fields. One explanation proposed for this phenomena was a a change in rock wettability by the CO2 and crude oil miscible bank. This paper describes an experimental study to determine the effects of CO2 flooding on the wettability of West Texas dolomitic cores.
This study examined the relative permeability characteristics of fresh-state San Andres and Grayburg dolomite core samples before and after passing a crude oil/CO2 miscible front through the test core. Changes in the relative permeability characteristics were used to infer the effects of CO2 flooding on rock wettability. The cores chosen were intermediate oil wet, intermediate, and intermediate water wet. The results showed that the cores became slightly more water wet. However, this change in wettability was near the limit of statistical confidence. Some data suggests that the tendency to becoming water wet was cause by slight rock dissolution by the CO2 and brine. Some observations concerning the compatibility of brines used in laboratory core floods with dolomites containing anhydrite are discussed.
Existence of a Secondary Optimal Salinity in Microemulsion Systems
Authors: Mehmet C. S. , Fuseni A. B. , Al-Hashim H. S. , Menouar H. 
Published: December 2007

ABSTRACT
The optimal salinity has become the most important criterion for structuring surfactants to maximize solubilization of oil and water in microemulsion systems. Laboratory corefloods have demonstrated that surfactant systems show maximum oil recovery at this optimal salinity which also corresponds to a minimum interfacial tension. However, many oil reservoirs exhibit high salinities over 200,000 ppm and temperatures above 90°C. Since most surfactants produce low optimal salinities, the interfacial tension under such severe conditions is expected to be rather high.
In this study, we have found the existence of a secondary optimal salinity which occurs, at a salinity higher than the primary optimal salinity (previously known as the optimal salinity). The presence of a secondary optimal salinity has been tested for ethoxylated sulfonates of varying ethoxylation (EO) number with an alkene and also with crude oil. For example, for EO=8 while the primary optimal salinity with dodecane at 90°C takes place at 8% salinity, the secondary optimal salinity occurs at 14% salinity. Increasing the EO number shifts both the primary and secondary optimal salinities indicating that the secondary optimal salinity is not an artifact. Moreover, the data obtained so far reveal that the secondary optimal salinity yields even lower interfacial tension. The mechanism governing this phenomenon is elucidated on the basis of partition coefficients, phase inversion temperature and infrared data.
These results in addition to their theoretical interest are expected to open new avenues in the design of surfactant formulations for high-salinity and high-temperature oil reservoirs.
Improving Waterflood Performance in Oil Reservoirs with Bottomwater
Authors: Islam M. R. , Ali S. M. Farouq 
Published: December 2007

ABSTRACT
This research addresses the problem of waterflooding a medium gravity oil-bearing formation with a water leg, and offers recommendations for process selection. In many reservoirs the presence of a bottom water zone results in very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil recovery technique for these reservoirs. Waterflood performance in such reservoirs can be improved greatly with effective methods of partially plugging the bottom-water zone. Some of these methods were developed in this study with a large flow model, by using a series of mobility control agents.
Polymer, emulsion, biopolymer, air, silica gel and foam, in various slug sizes, were used as mobility control agents for waterflooding an oil saturated reservoir model with a bottom-water layer. More than 80 model experiments were conducted to study the effect of permeability contrast, water-oil layer thickness ratio, oil viscosity, slug size, etc. Also, a series of runs were conducted with an artificial barrier of different lengths. Oils of viscosities ranging from one to 200 mPa.s were used in the displacement tests. A qualitative comparison is made to show the relative merits of the various mobility control agents. The blocking mechanism for each mobility control agent is investigated in detail and a comparison is made. It is shown that the choice of one mobility control agent over others depends on variables such as permeability contrast, oil-water layer thickness ratio, oil viscosity, injection interval (as a function of time). The effect of slug size is discussed for various mobility control agents and an optimum slug size is proposed. It is shown that for polymer, emulsion, foam and silica gel the poorer the conventional waterflood performance is, the more efficient the mobility control agents are. For instance, in the case of bottom water zone as thick and permeable as the oil zone, only about 15% 10IP may be recovered by a waterflood, whereas by the use of polymer, emulsion, foam or silica gel as mobility control agent, as much as 70% of the IOIP may be recoverable.
Laboratory Evaluation of Foaming Additives Used to Improve Steam Efficiency
Authors: Robin M. 
Published: December 2007

ABSTRACT
During steam injection operations, the sweep efficiency is detrimentally affected by gravity effects or reservoir heterogeneities. In order to increase the sweep efficiency, research is being done on combined steam and surfactant flooding, causing the generation of foam; this would plug off the preferential flow paths, reduce the gas mobility, and enable the steam to invade a larger portion of the reservoir.
A laboratory study was carried out to determine and follow the evolution of foamability from ambient conditions up to about 300°C and 10 MPa (572°F and 1450 psi), corresponding to high pressure steam injection. Foam efficiency was evaluated by displacement tests in porous media.
For most of the currently used surfactants, foam stability is dramatically affected by the presence of a residual oil phase. Moreover, the efficiency of foams decreases considerably when temperature increases.
Testing various surfactants in the presence of oil enabled us to screen some chemicals that form foams whose stability is not affected by the contact with a hydrocarbon phase. The pressure drop during foam injection is studied versus temperature and foam quality, in a homogeneous porous medium.
Blocking properties of foams generated by different surfactants are compared under various conditions.
Work has been done under laboratory conditions to visualize the mechanisms of foam action for increasing oil recovery, in cores which are either homogeneous or constist in two layers with different permeabilities. A considerable difference is noticed between the usual surfactants and certain chemicals which are not affected by the presence of oil.
It can be observed that foam stability decreases severely with rising temperature. This effect can be reduced by adding some appropriate compounds to the surfactant solution, prior to injection.
Results of displacement tests performed in cores with crude oils, under steamflood conditions, show a significant increase in recovery due to foam efficiency. These experiments were mainly conducted under isothermal conditions.
Simulation of Field Results of Cyclic Steam/Gas Injection in the Bolivar Coast, Western Venezuela
Authors: Salazar A. , Sánchez N. , Martínez C. , Colonomos P. 
Published: December 2007

ABSTRACT
The injection of a small slug of natural gas immediately after the injection of steam, has been proposed as a method for improving the oil production of a cycle of steam stimulation. This approach is being tested by MARAVEN in an area traditionally exploited by cyclic steam injection.
Results of pilot tests of cyclic steam followed by gas injection in heavy oil reservoirs (9–12°API) in the Tía Juana and East Tía Juana Fields of the Bolivar Coast in Western Venezuela are presented. The tests in the Tía Juana Field were performed during a first cycle, with an increase of 20% in the oil production due to the gas injection. The tests in the East Tía Juana Field were performed during a fourth cycle, with no significant change in the oil recovery.
To understand the observed behavior and the merits of the gas-slug injection, the pilot tests were successfully simulated with a three-dimensional compositional thermal numerical model. In the East Tía Juana fields this involved simulating 36 years of production during depletion and the three cycles prior to the steam/gas stimulation. In the Tía Juana Field it involved only the steam/gas stimulation cycle.
To study the parameters that affect the recovery due to the injection of gas, a sensitivity study with varying gas injection conditions, and reservoir conditions at the start of the steam/gas stimulation was conducted. Results indicate that the extra production due to the injection of gas, is highly sensitive to the pressure of the reservoir at the start of the injection. This result confirms the observed field behavior.
The main mechanism responsible for the increase of production due to the injection of gas is solution gas-drive. This effect is more important at the higher pressures normally present during the first stimulation cycles. Other factors such as changes in saturations, pressure, and temperature are deemed to be of relatively minor importance.