bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Evaluation of New Aspaltene Inhibitors; Laboratory Study and Field Testing
Authors: Bouts M.N. , Wiersma R.J. , Muijs H.M. , Samuel A.J. 
Published: December 2007

Abstract
Three candidate asphaltene inhibitors have been laboratory tested for their effectiveness on a Canadian crude. One inhibitor, an oil-soluble polymeric dispersant developed by Shell Chemicals, showed superior behaviour compared to the others: flocculation titrations with n-heptane resulted in an optimum concentration of 1300 ppm. PVT calculations, however, indicated that the prevailing conditions downhole can be quite favourable with respect to the amount of effective inhibitor compared to the atmospheric laboratory titrations which appear to be quite severe tests. Therefore, lower initial concentrations were recommended for a field trial. The chemical could be continuously injected through a capillary string, thereby avoiding the lost oil production associated with solvent cleaning operations. It has proved to be very effective at concentrations as low as 66 ppm, resulting in both a technically and an economically successful trial.

Introduction
Precipitation of asphaltenes in reservoirs, wells and facilities has a severe detrimental impact on the economics of oil production because of a reduction well productivity and/or clogging of the production facilities. The nature and behaviour of asphaltenes in crude oils is complex. Asphaltenes are heterocyclic macromolecules mainly consisting of carbon and hydrogen and minor components such as sulphur, nitrogen, and oxygen. It is generally accepted that resins and maltenes (these structures are comparable to asphaltenes but with a much lower molecular weight) are responsible for keeping the asphaltene particles in dispersion. The asphaltenes are surrounded by the polar head groups of the resins and maltenes while the nonpolar alkyl tails interact with the oil phase. So, crudes with a high ratio of resins to asphaltenes are less subject to asphaltene deposition whereas crudes with large amounts of non-polar saturates compared to aromatics are more prone to exhibit asphaltene precipitation problems. At "normal" reservoir conditions the asphaltenes, resins, maltenes and oil phase are in thermodynamic equilibrium. This equilibrium can be disturbed by a number of factors: decline of the reservoir pressure towards the bubble point, change in temperature or addition of a miscible solvent to the oil as applied in various EOR techniques.
Much research has been focused on modelling the deposition behaviour of asphaltenes in reservoir crudes upon changes in pressure, temperature or composition. These models are based on the Flory-Huggins theory for colloidal systems and calculate the chemical potential for large molecules in the various phases. They require solubility parameters as input. In addition, the industry has made a substantial effort to develop pragmatic solutions to the problem of asphaltene deposition in producing wells.
The Use of Open Flow Potential Test Data in Determining Formation Capacity and Skin Factor
Authors: Essis B. A.E. , Thomas G.W. 
Published: December 2007

Introduction
A knowledge of formation flow capacity and damage is necessary to determine reliable values of gas well deliverability. This information is usually acquired by pressure buildup or drawdown tests. However, in low-permeability reservoirs, the long time required to conduct such tests is frequently prohibitive. For this reason attention has been directed toward employing variable-rate tests that do not require well shut-down. In 1965, Odeh and Jones developed a generalized variable-rate procedure that can be used to analyze four-point backpressure data from gas wells. This procedure makes it possible in some cases to obtain formation flow capacities from backpressure surveys without resorting to further well tests. Since data from such surveys are frequently available, an evaluation of the Odeh-Jones technique is needful.
Fraser attempted to use the Odeh-Jones technique to predict gas well deliverability in West Texas reservoirs. He found the method useful for detecting invalid backpressure test data. For long-term prediction of gas well deliverability, however, the results he obtained were not satisfactory. He concludes that this could be attributed to "problems in basic data rather than failure of the theory". Fraser's study is limited by the assumptions of small pressure gradients and gas ideality; further, he made no comparisons with results obtained from drawdown or buildup tests.
In this work, using real gas theory, we present the results of an Odeh-Jones analysis of backpressure test data from 16 new gas wells. Flow capacities so derived are compared with those obtained from pressure buildup tests. We have tried to categorize the wells and interpret observed anomalies in terms of formation characteristics within each category, and to delineate where the technique is applicable. Also, we demonstrate the importance of using real gas flow theory and obtaining reliable test data.

ProcedureProcedure Development of Equations
In the treatment of isothermal flow of gases through porous media, it has been standard practice to assume that the gas is ideal to the extent that viscosity and the gas law deviation factor z remain constant. This gives rise to flow-rate expressions that involve squared pressure terms. For example, the pressure drawdown for radial gas flow at constant rate in an infinite system is described by
(1)
where m = 1,637 zT/kh, s = log (kpi/ rw2) − 3.23+0.87 s, and D is the Ramey non-Darcy flow constant, and log t means log10 t. (Eq. 1 is presented in a form slightly different from that given in Ref. 1 For details, see the Appendix.)
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A Solution to Ground Subsidence Problems In Casing Strings and Wellheads
Authors: Burley J.D. , Drouin Andre H. 
Published: December 2007

A new wellhead assembly and method for restoring casing string tension provides a fast, economical solution to well problems created by ground subsidence. The new design permits one man, using simple and easily transportable equipment, to make casing string tension corrections rapidly and with minimum interruption of well production.

Introduction
Subsidence has produced buckling of casing strings and wellhead failures due to force reversals in the production casing strings of oil and gas wells. Detection of active or potential subsidence in oil and gas producing areas has prompted development of remedial operations and techniques to control and relieve the resultant well problems.
We shall introduce here a new approach developed for combating subsidence problems in producing wells in the Houston-Galveston area of the Texas Gulf Coast. The advantages of this new solution have been substantiated by field tests.

Subsidence in the Houston-Galveston Area
Land subsidence has been recognized in the Houston-Galveston area for quite some time.1,2 Beginning in 1905–1906 the U. S. Coast and Geodetic Survey established nets of first- and second-order level lines covering the area. Major releveling surveys conducted in 1942–1943, 1953–1954 and 1964 have been used to develop maps of generalized surface subsidence (Fig. 1).4,5 Ground settlement has been continuous since it was originally identified. By 1964 maximum total subsidence had reached 5 to 6 ft. The area within which subsidence was 1 ft or more had increased from an 8-×18-mile oval shape of the 1906–1943 surveys to more than 40 miles in diameter with an additional extension to the southeast that included the Texas City vicinity.

Subsidence Problems in Oil Producing Operations
Humble has experienced subsidence problems in Houston-Galveston area fields involving approximately 500 total oil and gas wells. Other operators have also recognized these problems and have been active in repairing them. To understand the problem and forces involved, consider a line diagram of a typical well (Fig. 2). Many of the wells in this area were drilled 25 to 30 years ago. The surface pipe, consisting of 1,000 to 1,500 it of 9 5/8-in. casing, was cemented throughout the entire length while the pipe was in tension. The production string, consisting of 6,000 ft of 5 1/2-in. casing, was landed in tension with the bottom 1,000 ft cemented. When the production string was landed in the casinghead, the upper portion of the surface casing was placed in compressive loading. Under normal conditions there should be no appreciable change with time in the forces involved. However, when the wells have been re-entered it has been found that the forces originally in the casing strings have been reversed. The surface casing at the top of the ground is in tension, whereas the oil string is in compression. There has been no detectable movement of the casinghead relative to the ground surface.
Well-Test Model Identification With Self-Organizing Feature Map
Authors: Sinha Sandeep , Panda M. N. 
Published: December 2007

Summary
Well-test data have been used traditionally for determining a variety of reservoir parameters, such as average permeability, storage capacity, reservoir damage, presence of faults and fractures, and reservoir mechanism. A number of techniques, both conventional methods, such as type-curve matching and numerical simulation, and artificial intelligence (AI) methods, have been used for identifying well-test models. These methods are laborious and time-consuming and at times give incorrect results.
Artificial neural networks (ANN's) are recent developments in computer vision and image analysis. These networks are specialized computer software that generate a strategy to produce nonlinear mapping functions for complex problems. ANN's are commonly used as a tool for recognizing an object or predicting an event given an associated pattern. Only a limited number of applications of ANN for analyzing well-test data have been reported. These applications are mostly model-specific (developed for specific reservoir models) and, hence, are not general enough.
This paper presents a new method based on ANN's that uses Ko-honen's self-organizing feature (SOF) mapping technique to identify well-test interpretation models. By grouping well-test data into distinct categories, the SOF algorithm produces a general mapping function. This method can help analyze well-test data from a large variety of reservoirs (including reservoirs with faults, fractures, boundaries, etc.) more efficiently and inexpensively than was feasible previously.
Parachors Based on Modern Physics and Their Uses in IFT Prediction of Reservoir Fluids
Authors: Schechter D. S. , Guo Boyun 
Published: December 2007

SummaryPrediction of interfacial tension (IFT) is essential for modeling many secondary and tertiary oil recovery processes. The parachor method (PM) has been widely used to predict IFT. There has been considerable confusion in the literature concerning the PM for estimating IFT. The confusion is based primarily on the lack of clarity concerning the scaling exponent and parachors derived from this exponent.According to modern physics, the theoretical value ofthe scaling exponent is 3.88 for all pure substances, although several values may be found in the literature, usually altered to match existing data. This paper addresses clarification of the confusion about the scaling exponent, derivation of parachors for pure species occurring in petroleum fluids and oil cuts, and verification of the validity of these derived parachors in IFT prediction of reservoir fluids.We have analyzed experimental data for various compounds occurring in reservoir fluids and found that 3.88 is a valid scaling exponent for pure species inside and outside, to some large extension, of the critical region. Taking 3.88 as a fixed scaling exponent, parachors of 139 crude oil components are back-calculated by means of surface tension and density data obtained from experiments by previous investigators. These parachors are compared with three selected parachor correlations for IFT prediction of six crude oil and CO2 mixtures and are found to be more accurate.
Miscible Gas Displacement of Multicomponent Oils
Authors: Johns R. T. , Orr F. M. 
Published: December 2007

Summary
This paper extends the theory of multicontact miscible displacements in four-component systems to displacements by a single gas component of an oil containing any number of components. Multicomponent solutions are developed using the method of characteristics in the absence of dispersion and are shown to consist of a series of successive pseudoternary displacements. Example analytical solutions are constructed and compared to experimental results for a synthetic ten-component oil displaced by CO2 as given by Metcalfe and Yarborough1.
The minimum pressure for miscibility (MMP) for the synthetic oil is determined to be substantially below pressures used in the experiments and is below the bubble-point pressure. We show that multicontact miscibility (MCM) can be achieved even when an oil exists as two phases. The displacement of the synthetic oil by CO2 is demonstrated to have features of both condensing and vaporizing mechanisms (C/V). Furthermore, the key tie line that controls development of miscibility is the crossover tie line that divides the condensing and vaporizing portions of the displacement path (composition route).
Extension of the theory for displacements of real oils with an arbitrary number of components is also discussed. For displacements by CO2 of an oil that contains only methane (CH4), ethane (C2) and heavier components, we demonstrate that the most downstream crossover tie line will control the development of miscibility. For displacements by the most volatile component (i.e. pure N2 or CH4 injection) of the same oil, however, displacements are purely vaporizing and miscibility is controlled by the tie line that extends through the oil. A comparison of the component volatilities of the oil relative to the injection gas determines which one of the tie lines will control the development of miscibility. A procedure is given that can be used to find the key tie line that controls miscibility and also to estimate the MMP from an equation-of-state (EOS).
Thermal Stresses Around a Wellbore and Their Small Effect on Velocity Logging
Authors: Tuman V.S. 
Published: December 2007

TUMAN, V.S., MEMBER AIME, U. OF ILLINOIS, URBANA, ILL.

Abstract
In the first part of this paper, an estimate is made of the magnitude and extent of the thermal stresses which result from mud circulation. Our study is made for the period of relaxation, i.e., when the drilling operations are terminated and mud circulation is discontinued. In the second part, we have shown how the thermal stress can affect the wave propagation. An example is worked out for a Carbondale sandstone (Illinois basin). It is concluded that, in extreme cases when differential temperature is about 100 degrees F, the travel time will be affected by about 2 microsec/ft. For more refined permeability studies, such corrections would be desirable.

MAGNITUDE AND EXTENT OF THERMAL STRESSES RESULTING FROM MUD CIRCULATION
When geological beds are penetrated by boreholes, it is observed that the formation temperatures increase with depth; however, the temperature profile varies considerably from place to place. During drilling operations, mud pumped from a pit at atmospheric temperature absorbs heat from the lower beds. As a result, the drilling fluid returning to the surface is at a higher temperature than the surrounding beds. The temperature gradient in a well depends on the rate of mud circulation and other factors; normally, this temperature gradient is smaller than the natural gradient in the formations. (See Fig. 1.)The temperature difference between the mud column and the surrounding beds gives rise to thermal stresses (which are also important in the phenomenon of fracturing), and it is expected that they will affect the transit time of the sonic front in velocity logging. It is evident that beds near the surface will undergo various cycles and will have a complicated dynamical and thermal-stress history. A limestone bed which is just penetrated will act as a source of heat, warming up the cold mud pumped down a few minutes earlier from the surface pit. The same limestone bed a week later will act as a sink, absorbing heat from the drilling mud which has already warmed up sufficiently to be at a higher temperature than the bed in question. No doubt a large section of the hole will undergo a heat treatment, which will make the calculation of the exact magnitude of the thermal stresses very difficult. In the solution of wellbore thermal equation, it is assumed that the rock around the wellbore is elastic and isotropic, and that the system is radially symmetrical. A complete dynamical solution of the thermal stresses set up at different horizons during the drilling operations would require a comprehensive history of the mud circulation, the surface temperature of the pit and the number of hours in which mud was not circulated.
SPEJ
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Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing
Authors: Fredd C. N. , Fogler H. Scott 
Published: December 2007

Abstract
Acidizing treatments are commonly used to remove near-wellbore damage and create artificial flow channels in carbonate formations. Matrix acidizing treatments are most useful when fracture acidizing is undesirable, such as when a shale break or other natural boundary must be maintained to prevent water or gas production1 or where fracture acidizing is ineffective, such as in soft chalk formations.2 Unfortunately, matrix treatments often require low injection rates to prevent fracturing the formation rock. These treatments may also be required in heterogeneous formations with zones of low conductivity (which need stimulation the most) that accept acid at low rates. It is at these low injection rates that the problem of rapid acid spending severely limits the acid penetration distance. The injection of hydrochloric acid (HCl) into carbonate formations at low rates results in face dissolution, or complete dissolution of the carbonate matrix near the wellbore. This face dissolution consumes large volumes of acid and provides negligible increases in the conductivity of the formation.
Various acid systems have been used to reduce the limitations of rapid acid spending at low injection rates. A few of the acids include: weak acids, such as acetic and formic acid, which have relatively low H+ concentrations and therefore react with carbonates at a slower rate than HCl3,4; chemically retarded acids, such as oil external microemulsion systems containing HCl, that retard acid diffusion to the carbonate surface and thus allow deeper penetration of live acid2; and foamed acids (nitrogen gas and aqueous HCl) that prevent acid from spending outside the primary dissolution channel, thereby promoting the growth of wormholes.5
Although retarded and foamed acid systems can stimulate carbonate formations at lower injection rates, strong acids such as HCl induce the precipitation of asphaltic sludge from crude oil. This sludge can plug the formation and restrict production after an acidizing treatment. When ferric ions are present, this problem is even more severe.6 Thus, adequate corrosion protection becomes more essential. Acetic acid (HAc), an iron chelating agent, does not reduce sludging tendencies in the presence of ferric and ferrous iron.6 A variety of acid additives (antisludging agents, corrosion inhibitors, and iron-reducing agents) have been used to prevent the sludging problem. However, their effectiveness is limited by the need to obtain a compatible combination of additives and a lack of understanding of the complex chemistries involved in the precipitation reactions. These limitations demonstrate the need for an alternative stimulation fluid that combines the ability to stimulate at low injection rates with fluid properties that are not conducive to asphaltic sludge precipitation or corrosion problems.
A Ten-Pound Cement Slurry for Oil Wells
Authors: Coffer Henry F. , Reynolds J.J. , Clark Roscoe C. 
Published: December 2007

Abstract
A cement slurry lightweight additive has been adapted in the Conoco laboratories for use in oil well cements. This additive makes possible the use of air to lighten oil well cement slurries. Specifically, the additive consists of small clay bubbles of air having sufficient strength to resist crushing by bottom hole pressures. Clay bubble cement slurry weights can be safely reduced to 10 lbs/gal. In addition, the clay bubbles tend to act as lost circulation materials and to provide a cement texture which should produce good perforating characteristics. Clay bubble cement is relatively impermeable.

Introduction
In many areas in Oklahoma, Texas, Wyoming, and California, difficulties are experienced during casing cementing operations with lost returns caused by the high density of the cement slurries. Wells in these areas are ordinarily drilled with 9 to 11 lbs/gal. drilling mud while neat cement slurries may range in densities from 14.5 to 17 lbs/gal. In these areas, cement slurry weights are at present being successfully reduced to around 12 lbs/gal. (under bottom-hole conditions) by the use of additives in the cement. Since the use of additives will decrease the strength which the cement will develop, the amount of additives which can be used must be based on the minimum cement strength which is acceptable; and thus the maximum slurry weight can be reduced. At present, the minimum tensile strength generally acceptable is 50 lbs/sq in. cured for 24 hours under bottom-hole temperature. This figure is based on laboratory tests and on a large number of cement jobs which have been conducted using cement which will not develop more than 50 psi tensile strength in 24 hours under bottom-hole conditions.
Interfacial Tension of the Methane-Normal Heptane System
Authors: Warren H.G. , Hough E.W. 
Published: December 2007

The interfacial tension values for the methane-n heptane two-phase system were determined by the pendeant-drop method on eight isotherms from 100 degrees pendeant-drop method on eight isotherms from 100 degrees to 310 degrees F. The pressure range was from 215 to 3,415 psia. Direct measurements of the maximum and minimum drop diameters were made. The tables of Winkel and the density difference data of Reamer et al. were used to calculate experimental values of interfacial tension. The experimental data varied from 16.64 dynes/cm at 217 psia at 100 degrees F to 0.081 dynes/cm at 3,415 psia at 130 degrees F. The smooth data is given in Table 1. Fig. 1 is a plot of smoothed data at 0.1, 1.0, 5.0 and 10.0 dynes/cm over the range of 100 degrees to 310 degrees F and 0 to 3,618 psia. The dashed lines are extrapolation of the data. A correlation of these data along with other hydrocarbon systems has been published. The data are taken from the PhD dissertation of one of the authors.
The supplement of the American Chemical Society Research Fund Grant No. 635-A is gratefully acknowledged.
TABLE 1 - INTERFACIAL TENSION OF THE METHANE - NORMAL HEPTANE SYSTEM SMOOTHED DATA
Interfacial Tension (dynes/cm) Pressure Pressure psia 100 F 130 F 160F 190 F 220 F 250 F 280 F 310 F psia 100 F 130 F 160F 190 F 220 F 250 F 280 F 310 F
400 14.88 13.75 12.50 11.28 9.97 8.83 7.74 6.60800 11.33 10.60 9.88 8.96 7.96 6.98 6.07 5.111,200 8.50 8.00 7.55 6.88 6.18 5.32 4.55 3.711,600 6.16 5.85 5.53 5.04 4.54 3.80 3.16 2.482,000 4.21 4.06 3.83 3.47 3.04 0.45 1.90 1.352,200 3.35 3.83 3.47 3.04 2.37 1.85 1.39 0.872,400 2.57 2.50 2.36 2.13 1.76 1.30 0.91 0.472,600 1.85 1.82 1.73 1.54 1.23 0.83 0.50 0.132,800 1.22 1.22 1.15 1.00 0.74 0.41 0.17 2709*3,000 0.73 0.73 0.67 0.56 0.34 0.13 2927*3,100 0.53 0.53 0.47 0.37 0.19 0.033,200 0.35 0.35 0.31 0.23 0.07 3122*3,300 0.22 0.22 0.19 0.12 3298*3,400 0.13 0.13 0.10 0.033,500 0.06 0.02 3549*3,600 3606* 3618*
*Critical pressure at temperature.
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