bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kinetic Rate Expressions for Reactions of Selected Minerals with HCl and HF Mixtures
Authors: Lund K. , Fogler H.S. , McCune C.C. , Ault J.W. 
Published: December 2007

This paper was prepared for the Oilfield Chemistry Symposium of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., May 24–25, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The chemical kinetics of solid-liquid reactions were studied for different mud acid-mineral systems in a rotating disk apparatus. The minerals studied included calcite, dolomite, microcline, and albite. The kinetic rate equations, regimes of diffusion and reaction control, and possible mechanisms of dissolution are presented for these various minerals.
At temperatures above 100 degrees C, the rotating disk rate data show that the rate of reaction of HCl with dolomite is controlled by the mass transport of HCl to the dolomite surface. The HCl-dolomite reaction becomes surface reaction controlled at temperatures below 100 degrees C. At the conditions existing in petroleum reservoirs, the HCl-calcite reaction can be considered controlled exclusively by mass transport of HCl. The feldspar-mud acid reaction rate results reveal that the dissolution of feldspars is surface reaction rate limited and depends on both the HF and HCl concentrations in the mud acid.

Introduction
Acid stimulation of oil and gas reservoirs is concerned with the application of acids and acid mixtures to dissolve porous and non-porous minerals. It has great utility in enhancing the productivity of oil reservoirs through increasing the permeability of the formation by the permeability of the formation by the processes of matrix and fracture processes of matrix and fracture acidization. In matrix acidization, acid such as hydrochloric acid or a mud acid (HCl and HF) is forced to flow within the pore structure of the rock matrix. The reservoir rock characteristics are altered as the acid reacts with the clays and minerals present. In fracture acidization, the present. In fracture acidization, the acid is forced to flow along hydraulically induced fractures.
Solubility of Calcium Sulfate in Brine
Authors: Carlberg B.L. 
Published: December 2007

Abstract
Brine solubility of calcium sulfate is a function of several variables, including brine composition, temperature, and the hydration state of the precipitating phase. Solubility data covering these variables is included, and the need for inclusion of an additional variable—turbulence—is shown for temperatures above the normal boiling point. These data are then used to derive an expression for that solubility to about 250 degrees F.

Introduction
Calcium sulfate is one of several sparingly soluble salts commonly deposited from oil field waters. That deposition is the result of a supersaturated condition approaching equilibrium by precipitating some of its dissolved salt burden. Precipitation continues until stability has been achieved.
A number of parameters influence the solubility of calcium sulfate. Certainly one of these is the hydration state of the calcium sulfate molecule. Figure l shows solubility of the three most common forms in distilled water as a function of temperature. Solubility of calcium sulfate is also affected by temperature; salinity; excess common ion; concentration of magnesium ion; and, to some extent, pressure. This latter effect has been well covered by Vetter.
In this study of calcium sulfate solubility, we have searched the literature for data on the effects of the above-mentioned parameters. We have supplemented the available parameters. We have supplemented the available information with new, experimental data. The purpose of this paper is to present these purpose of this paper is to present these data, to note the trends revealed, and to use the information to improve prediction of calcium sulfate deposition over a wide range of temperatures, salinities, and magnesium ion concentrations. With this procedure, we can now calculate calcium sulfate scaling tendencies from waters with temperatures as high as 225 degrees F. At the elevated temperatures, an additional solubility parameter—turbulence— must also be considered.

CALCIUM SULFATE SOLUBILITY

Anhydrite
Solubilities of anhydrous calcium sulfate in water and in sodium chloride solutions are shown in Figures 2 and 3. The bulk of these data were taken from the literature shown in the attached bibliography.
Analysis of Alternate Gas Development and Market Plans by Optimizing Techniques
Authors: Wattenbarger Robert A. , Pacheco E.F. , Parsons Steven D. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
An economic study of development and market plans was performed on a complex area of oil and gas fields. The purpose of the study was to compare different plans for marketing gas and developing the fields prior to negotiating long term gas contracts prior to negotiating long term gas contracts for export to other countries. A nonlinear mathematical program for optimizing drilling and development schedules was applied to various cases. The study resulted in definite plans regarding minimum prices for negotiating purposes, a ranking of prices for negotiating purposes, a ranking of the desirability of each gas contract, and the order in which these negotiations should be approached.

Introduction
The problem of planning the development of multiple gas fields for a specified future market demand schedule is complicated because it requires the coordination of planning for development drilling, gathering planning for development drilling, gathering facilities, processing facilities and pipelines. The usual planning approach is pipelines. The usual planning approach is to use the "case study method" which normally involves a limited number of cases to reach the best solution possible within the available time.
The problem is complicated further when the market demand schedule has not yet been determined. Nevertheless it is a great advantage to an operator who has the responsibility for developing all aspects of the gas production and pipeline facilities, to be able to coordinate the entire planning problem prior to negotiating long term gas problem prior to negotiating long term gas contracts. A prior knowledge of optimal alternatives gives the operator an estimate of the cost of delivering gas and his ability to meet specified delivery schedules.
This paper reports a systematic approach to this type of planning problem by using a nonlinear programming computer system which has been developed for the purpose of optimizing oil and gas field purpose of optimizing oil and gas field investments.
Numerical Simulation of Edge Water Drive with Well Effect by Galerkin's Method
Authors: Vermuelen J.L. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
By using an Irons quadrature rule and a semi-implicit linearized scheme for relative permeabilities and capillary pressure, a permeabilities and capillary pressure, a three-dimensional two-phase variational simulator has been developed, which requires only a little more computation time than the standard finite difference models. However some difficulties arise in solving edge water drive problems by the Galerkin's methods.

Introduction
This paper presents a numerical simulator of "water tongue" displacement with well effect in a three-dimensional reservoir. Standard finite difference models do not fit to treat such problems. Indeed the three-dimensional models require many grid points for accurately describing the saturation distribution, which results in large computer times. Furthermore coning models cannot be used because of their radial symmetry.
Recently some authors tried a new approach, the Galerkin's variational method, to solve the flow equations. For classical flow problems this technique has been proved to be numerically superior to finite difference methods but it requires more computation time.
This work describes a variational simulator developed to solve the above edge water drive problem. It is a three-dimensional, problem. It is a three-dimensional, two-phase, compressible model which treats the reservoir as inhomogeneous and anisotropic. Substantially higher computing efficiency than in other known variational models has been obtained in two ways :Integrations have been more efficientlyperformed by using Irons quadraturerules. These formulae simpler than the standard gaussian rules having the sameorder of truncation error, highly reduce the computing time absorbed inintegrating the coefficients of the equations.Time-step sizes have been enlarged byusing a semi-implicit linearized scheme for relative permeabilities and capillary pressure.
Some problems have been treated and theirresults compared to those from a finitedifference model.
Development and Applications of a Downhole Tool to Detect Gas while Drilling
Authors: Tanguy D.R. , Kishel J.F. , Young D. , Kisling J. 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A new downhole tool has been developed to indicate the presence of gas in the mud immediately above the drill bit. The new tool has many potential applications beyond the early anticipation of a kick. For instance, under favorable conditions, shallow gas bearing sands can be located without interrupting drilling operations. Consequently, drilling schedules and mud programs can be optimized for safe and programs can be optimized for safe and efficient rig operation.
No electronics is used in the downhole gas detector and no modification of the drill string is necessary. operating the tool requires only a minor variation in routine drilling operations.

Introduction
Whenever formation gases flow into the well bore during drilling operations, a potentially hazardous condition exists. As the gas rises up the well with the drilling mud, it expands, reduces the apparent density of the well fluids and, consequently, reduces the pressure which the mud can exert pressure which the mud can exert against drilled formations. Most often, the reduction of hydrostatic pressure is small and the flow of gas into the well is quickly stopped by the buildup of a mud cake on the bore walls.
However, if the initial amount of gas which enters the well as the bit cuts into the formations is high or if the mud density is abnormally low, the reduction in the well fluid hydrostatic pressure caused by the expansion-of the pressure caused by the expansion-of the gas permits more gas to enter the mud system. The additional gas causes a further reduction in the hydrostatic pressure and a corresponding additional pressure and a corresponding additional flow of gas. Unless the well is closed off, a blowout situation quickly develops.
It is obviously very important to measure as accurately and as early as possible how much gas is being added to possible how much gas is being added to the mud stream near the bit in the process of drilling. If the amount is process of drilling. If the amount is small or if the flow is only temporary, the situation will correct itself and there is no reason to stop drilling operations. However, if the flow of gas is steady, it is inevitable that a dangerous condition is developing and immediate measures must be taken. Even when the gas kick is kept under control, the time required to correct the situation and the costs incurred to do so increase rapidly with the amount of gas which is permitted to enter the well bore. The laws of physics which apply to the expansion of formation gases in the well bore do not permit a simple and early detection of the kick.
In-situ Stress and Pore Pressure in the South Eugene Island Field, Gulf of Mexico
Authors: Finkbeiner T. , Zoback M.D. 
Published: December 2007

Abstract
Analysis of minifracs and pore pressure surveys from sand reservoirs in a Gulf of Mexico oil field show effective stress ratios, K, that scatter significantly and do not correlate with previously published fracture gradient models for this area. The lower-bound value of K is 0.33, which corresponds to the expected value for Coulomb failure for a coefficient of friction of 0.6 in normal faulting environments. However, in some sands K approaches unity, thus indicating an essentially isotropic stress field. Hence, the data indicate a highly variable state of stress that cannot be simply related to depth or pore pressure, but appears to reflect an interaction between deformational processes and material properties.
Borehole breakout analysis in vertical wells reveals stress orientations that are predominantly perpendicular to normal faults and, hence, consistent with an extensional stress regime. Analysis of breakouts in inclined wells in two sand reservoirs allows to constrain the magnitude of the maximum horizontal principal stress, SHmax. and further indicates an active normal faulting environment with a clear, but small degree of horizontal stress anisotropy (i.e., Sv&gt;SHmax&gt;Shmin).
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Tectonic Controls on Fault-Zone Permeability in a Geothermal Reservoir at Dixie Valley, Nevada
Authors: Hickman Stephen , Zoback Mark , Benoit Richard 
Published: December 2007

Abstract
To determine factors controlling permeability variations within and adjacent to a fault-hosted geothermal reservoir at Dixie Valley, Nevada, we conducted borehole televiewer observations of wellbore failure (breakouts and cooling cracks) together with hydraulic fracturing stress measurements in six wells drilled into the Stillwater fault zone at depths of 2 to 3 km. Measurements in highly permeable wells penetrating the main geothermal reservoir indicate that the local orientation of the least horizontal principal stress, Shmin, is nearly optimal for normal faulting on the Stillwater fault. Hydraulic fracturing tests from these wells further show that the magnitude of Shmin is low enough to lead to frictional failure on the Stillwater and nearby subparallel faults, suggesting that fault slip is responsible for the high reservoir productivity. Similar measurements were conducted in two wells penetrating a relatively impermeable segment of the Stillwater fault zone, located 8 and 20 km southwest of the geothermal reservoir (wells 66–21 and 45–14, respectively). The orientation of Shmin in well 66–21 is near optimal for normal faulting on the nearby Stillwater fault, but the magnitude of Shmin is too high to result in incipient frictional failure. In contrast, although the magnitude of Shmin, in well 45–14 is low enough to lead to normal faulting on optimally oriented faults, the orientation of the Stillwater fault near this well is rotated by 40 from the optimal orientation for normal faulting. This misorientation, coupled with an apparent increase in the magnitude of the greatest horizontal principal stress in going from the producing to nonproducing wells, acts to inhibit frictional failure on the Stillwater fault zone in proximity to well 45–14. Taken together, data from the nonproducing and producing wells thus suggest that a necessary condition for high reservoir permeability is that the Stillwater fault zone be critically stressed for frictional failure in the current stress field.
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Mitigation of Heavy Oil Production Environmental Impact through Large-Scale Slurry Fracture Injection of Wastes
Authors: Dusseault Maurice B. , Bilak Roman A. 
Published: December 2007

Abstract
Slurry fracture injection (SFI) involves placement of solid wastes and water wider fracture pressures into deep geological formations. Currently, materials permitted for SFI include oily waste sand, "slops", produced muds, and produced water or waste water. Five years field experience has led to a good understanding of the SFI technology, and a regulatory frame- work is evolving in Alberta to permit SFI projects to proceed in an environmentally secure manner to meet the goals of the regulatory bodies as well as the goals of the oil companies.
The approach to SFI operations is described, including geological arguments related to environmental security. Security is also based on careful regulatory control, design, site selection, and analysis. The application of SFI to other waste streams should help mitigate environmental issues for heavy oil development, as well as for other oil feld applications.
P. 87
Measurement of Stress Direction and Mechanical Damage Around Stressed Boreholes Using Dipole and Microsonic Techniques
Authors: Plona T.J. , Winkler K.W. , Sinha B.K. , D'Angelo R. 
Published: December 2007

Abstract
In this paper the effects of borehole stress concentrations on both dipole flexural waves and azimuthally resolved, axially propagating compressional waves (i.e., microsonic) are studied. Dipole sonic logging tools provide the capability to measure acoustic anisotropy in the borehole. However, one needs to distinguish between two forms of anisotropy: intrinsic or stress-induced. A method is presented, based on an analysis of dipole dispersion curves, which can make this distinction. Once stress-induced anisotropy is determined, then the fast shear direction is the maximum stress direction. In addition, an azimuthal microsonic measurement technique is used to measure the azimuthally resolved, axially propagating, refracted compressional wave which can identify both stress direction and detect mechanical damage (i.e., zone of plasticity). Laboratory borehole experiments are presented for both dipole and compressional measurements. The experiments compare favorably with the theory of acoustoelasticity. The maximum stress direction is important in hydraulic fracturing while detection of mechanical damage can be important for wellbore stability.
P. 123
High Horizontal Stress in the Visund Field, Norwegian North Sea: Consequences For Borehole Stability and Sand Production
Authors: Wiprut D.J. , Zoback M.D. 
Published: December 2007

Abstract
We examine drilling-induced tensile fractures in five vertical and inclined exploration wells in the Visund oil field in the northern North Sea. Each well yields a consistent azimuth of the maximum horizontal stress both laterally and with depth.
The magnitudes of the three principal stresses (Sv, Shmin, and Shmax) are consitent with depth and reflect a strike-slip faulting stress regime. The magnitude of the maximum horizontal stress is significantly higher than the vertical (Shmax = 1.3 Sv) and minimum horizontal stresses in our models.
We determine optimally stable trajectories for borehole stability during drilling, after reservoir pore pressure drawdown.
P. 199
Wellbore Stability Predictions Using a Modified Lade Criterion
Authors: Ewy Russell T. 
Published: December 2007

Abstract
The two most commonly used rock failure criteria in wellbore stability analyses are the Mohr-Coulomb criterion and the Drucker-Prager criterion. Neither of these is compatible with 3-dimensional rock strength measurements that have explored the influence of the intermediate principal stress. This paper presents a modified Lade criterion which has the following desirable qualities:
it correctly describes the influence of the intermediate stress on rock strength, and therefore on wellbore stability, it can be rearranged to give a closed-form solution for critical mud weight, for any wellbore orientation, and only two rock strength parameters are required, such as cohesion and friction angle.
The modified Lade criterion predicts critical mud weight values that are less conservative than those predicted by the Mohr-Coulomb criterion yet are not as unconservative as those predicted by the Drucker-Prager criterion. It also reveals that the required increase in mud weight when going from low hole angle to high hole angle is not as great as predicted by either the Mohr-Coulomb or Drucker-Prager criteria.
P. 247
Integrated Rock Mechanics and Drilling Fluid Design Approach to Manage Shale Instability
Authors: Tan C.P. , Rahman S.S. , Richards B.G. , Mody F.K. 
Published: December 2007

Abstract
In recognising the petroleum industry's need for a technology to design optimal drilling fluid (weight, type and chemistry) to solve and manage shale instability problems, a collaborative project has been undertaken to develop the technology which will provide the basis for state-of-the-ant drilling fluid design criteria. The key drilling fluid-shale interaction mechanisms included in the study are mud pressure penetration, chemical potential and swelling-hydrational stress.
Fundamental concepts, processes, models and a range of novel test equipment and procedures for laboratory simulation of the mechanisms were developed. The laboratory test results were used in the refinement and verification of the models. The verified models, which have been integrated in a wellbore stability analysis software, were used to conduct analyses to demonstrate the effects of shale and drilling fluid properties on time-dependent wellbore (in)stability.
The understanding of the drilling fluid-shale interaction mechanisms and the development of the capacity to model them enabled the development of drilling fluid design charts. These charts, together with a shale property database and property correlations, provide a pragmatic and effective approach for designing optimal drilling fluids to manage shale instability efficiently.
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