bluuebunny/crossref_metadata_2025_split huggingface dataset:
Calculation of Friction Factors For Use In Flowing Gas Wells
Authors: Dranchuk P.M. , Abou-Kassem J.H. 
Published: March 2010

Abstract
A study of test data for a number of Alberta gas wells has revealed that flow during such tests is seldom in the "fully developed" turbulence region. Because computer programs used to calculate pressure profiles usually assume "fully developed" turbulent flow, they tend to underestimate the friction factor, and as a. result the pressure drop due to friction, in such wells. In order to avoid such bias, a subroutine, which generates the Moody friction factor chart, is present and recommended for use in computer calculation.
THE CALCULATION of bottom-hole pressures or pressure profiles in flowing gas wells may be effected by various methods.(1–3) Despite the differences between these methods, they have one thing in common they all require the estimation or calculation of a friction factor.
(Equation in full paper.)
Although these approximate methods are handy and appropriate to desk calculation, the modern practice of calculating pressure profiles by means of high-speed computers has made such approximations unnecessary and in some instances inappropriate. For example, one may set up a simple subroutine for calculating friction factors, using the expressions employed by Moody, as is indicated in Figure 1. Such a program will permit the use of absolute roughness values other than 0＿0006 in., and will do away with approximation error.
Because the Colebrook equation approaches the von Karman expression asymptotically, the point at which one changes from the former to the latter depends on the percentage error one is willing to accept at that point. Thus, if one is willing to accept a 1% error at the change-over point one should select the point Re=1600 d/E. On the other hand, one may use Re=3200 d/E for a 0.5% maximum error, as suggested by Moody, or Re = 16,000 d/E when the maximum permissible difference is 0.1 %＿ If, however, one is willing to incur the added cost of iteration in the region where f is essentially insensitive to further changes in Re, he may use the Colebrook equation for all values of Re greater than 4000. This is, in fact, the method that was employed by Aziz, Govier and Fogarasi(8).
The subroutine shown in Figure 1 was tested against the Cullender – Binckley and Cullender-Smith methods at 12 points, as shown in Tables 1 and 2. This comparison showed that:friction factor remains reasonably constant over the length of the well, thereby verifying the common assumption that such is the case;flow in gas wells, of the type found in Alberta, is not usually in the fully developed turbulent region;the Cullender-Binckley method provides a reasonable estimate of friction factor in the transition region, whereas the Cullender-Smith method consistently underestimates the friction factor when turbulence is not fully developed.
In addition, the comparison showed that the cost of application of the subroutine exceeds that of the Cullender-Smith method by less than 2 cents per hundred factors calculated.
This subroutine was also compared to that proposed by Aziz-Govier-Fogarasi.
Further On the Calculation of Friction Factors For Use In Flowing Gas Wells
Authors: Fogarasi Maria 
Published: March 2010

Abstract
A comparison of two computer subroutines to calculate friction factors from the Moody(2) chart has been made. The comparison shows that, contrary to the claim of Dranchuk and Abou-Kassem(1), their method and that of Aziz et al.(5) give identical results in the partially-rough-wall and the fully-rough-wall turbulence regions. The transition from the former to the latter is predicted to occur at slightly different Reynolds numbers in the two methods because of the choice by Dranchuk and Abou-Kassem of an arbitrary transition criterion. Both routines are suitable for computer calculation of friction factors, but the Aziz et al. method is more efficient, requiring fewer iterations.
IN A RECENT TECHNICAL NOTE, Dranchuk and Abou Kassem(l) recommend the use of the Moody chart(2) instead of approximate relationships to determine friction factors in pressure-drop calculations for flowing gas wells. Without doubt, fundamental equations with a properly chosen friction factor based on the correct reynolds number and the best estimate of the relative roughness will yield more accurate pressure-drop predictions than equations incorporating approximations for the friction factor(3).
(Equation in full paper)
Dranchuk and Abou-Kassem compare Darcy-Weisbach friction factors calculated by their own and the Aziz et al. method and arrive at the following conclusions:
The Aziz-Govier-Fogarasi method:generates Fanning friction factors;yields values which are higher than Colebrook at low values of Re and lower than Colebrook at high values of Re;yields values which are higher than Moody at low values of Re and lower than Moody at high values of Re when flow is in the transition zone) but higher than Moody at low values of Re and lower than Moody for high values of Re when flow is fully turbulent;cannot generate values for smooth pipe."
These conclusions seem unwarranted. Table 1 shows a comparison of Darcy-Weisbach friction factors calculated by the two methods for a wide range of relative roughnesses and Reynolds numbers. The comparison shows that:the friction factors are exactly the same in the PRW and FRW regions, as they should be, because both routines use the same equations;a slight difference (half a per cent or less) at the transition from PRW to FRW turbulence due to the difference in the transition criterion chosen by Dranchuk and Abou-Kassem and the assymptotic approach used in the Aziz et al. routine;the Aziz et al. routine is more efficient, requiring fewer iterations.
(Table in full paper)
Keeping in mind that Moody indicated that his chart would predict friction factors with no better than 10 per cent accuracy, the small differences are insignificant. The friction factors, for practical purposes, are the same.
Finally, the Aziz et al. method was not intended for the calculation of friction factors in smooth pipes. It was designed only to deal with the practical problem of estimating pressure drops in actual gas wells, which may always be expected
Calculation of Z Factors For Natural Gases Using Equations of State
Authors: Dranchuk P.M. , Abou-Kassem H. 
Published: March 2010

Abstract
The generalized Starling equation of state has been fitted to the Standing and Katz Z-factor correlation and a computer program is presented for the ge11eration of Z factors by means of this equation. A comparison is made of the performance of the Hall and Yarborough, Dranchuk et al. and above-mentioned methods, and the results are discussed.
COMPRESSIBILITY FACTORS have been calculated by means of computer for almost twenty-five years(1). During this period, the techniques available for effecting such calculations have been gradually improved and refined. In the recent past, experimental data have been fitted with various equations of state and these fitted equations have been used to generate Z factors(2,3,4,5). These equations represent a significant step forward in that they may be used as algebraic expressions for Z in dealing with its functions.
As most of these fittings have been made using the Standing and Katz correlation or data in the same region, their application would appear to be restricted to that region. However, there are occasions when Z is required outside this region. Consequently, the object of this study was to examine the extent to which these equations could be extrapolated and to try modified fittings which would extend the region of application.
Preliminary examination showed that the Redlich Kwong equation could not be generally compared with the Standing and Katz correlation, because it is not expressed in reduced form. Furthermore, this equation could not be tested against experimental data where critical properties rather than gas analyses are reported. In view of these problems, this equation was eliminated from further study.
It was observed that the Hankinson et al. fitting of the BWR equation was restricted to the region 1.1 ≤ Tr ≤3.0 and that the manner of fitting was such that errors in Z in the fitted region were considerably higher than those produced by either the Hall and Yarborough or Dranchuk et al. methods. On the basis of this observation, the Hankinson et al. fitting was eliminated from further examination.
A comparison of the Hall and Yarborough fitting of the Starling-Carnahan equation of state and the Dranchuk et al. fitting of the BWR with each other and with experimental data showed that both are reasonably accurate when extrapolated to Pr values in excess of 20. However, neither equation is valid at Tr = 1.0 in the vicinity of the critical, and both show marked error increases when extrapolated into the region of Tr &lt; 1.0.
The Starling equation of state may be written as
(Equation in full paper)
and may be generalized and rearranged to express the Z factor as
(Equation in full paper)
This equation has been shown to be valid in the extended regions for pure components and has been recommended for mixtures(7). In view of this and the equation"s similarity to the BWR equation used in the Dranchuk et at fitting, it was decided to fit Equation (2) to the 1500 data points used in the Dranchuk et al. fitting.
Analysis of ''Slug Test'' Or DST Flow Period Data
Authors: Ramey Henry J. , Agarwal Ram G. , Martin Ian 
Published: March 2010

Abstract
In recent years, there has been a great interest in the "slug test" which involves the instantaneous removal of a specific quantity of fluid from a wellbore and measurement of the resulting pressure-time response.
Although a skin effect term was introduced by Jaeger, most recent studies have not considered a skin effect in analyzing slug test data. A new approach to conventional well-test analysis by Earlougher and Kersch was used to prepare type curves for the slug tech which include the skin effect. This study includes: results presented in both tabular and graphical form to aid application, a new material on the radius investigated and the time of duration of slug test, and the presentation of field example illustrating the application and important limitations of the method, as well as limitations of conventional DST analyses. The main application of the slug test method is in the analysis of pressure data for cases wherein the fluid influx into the drill pipe tends to kill the flow (sometimes even before the tester valve is closed). On the other hand, many field test have been observed wherein the phenomena of critical (acoustic velocity) flow destroys the application of the method. The slug test, as currently developed, does not consider critical flow.
Verification of the Gladfelter-Tracy-Wilsey Concept For Wellbore Storage-Dominated Transient Pressures During Production
Authors: Ramey Henry J. 
Published: March 2010

Introduction
The fact that real wells have finite volumes leads to inertia in the sandface response of a well to a production rate change at the surface. The duration of wellbore storage (sometimes called "afterflow" for buildup or "annulus unloading" for production tests) rate changes is not often more than a few days. It may be as short as a few minutes. Perhaps for this reason, and also because it usually impossible to determine the sandface production rate with much accuracy, the Gladfelter-Tracy-Wilsey(2) afterflow correction for pressure buildup tests received minimal application. Actually, the Gladfelter et al. idea has a broad and important application in handling production rate change effects in general – rather than the specific production rate changes during pressure buildup. In 1965(1), the Gladfelter et al. pressure buildup afterflow correction was extended to production testing for the special case of an exponential production rate (starting from a zero producing rate and increasing toward the constant rate, q). Because of publication of both production pressure drops and sandface production rates(3, 4) for the classic wellbore storage boundary conditions(5, 3), it is possible to test the Gladfelter et al. idea for the wellbore storage case as well. Winestock and Colpitts(6) Carter(7), Aron and Scotts(9, 10), and others have also noticed that the reciprocal productivity index, (Δp/q), is often a linear function of the logarithm of producing time. This is a simple alternative to superposition to match production rate changes.
The Toxicity of Some Formation Fluids And Methods of Rehabilitation Subsequent to Their Spillage
Authors: Shaw D.R. 
Published: March 2010

Abstract
This paper deals with the effects that formation fluids have on animal and plant life. Crude oil is a mixture-not only of hydrocarbons, but of suspended salts and of sulphur compounds. The toxicity of some of the hydrocarbons and some of the sulphur compounds is discussed, as is the toxicity of salt. Consideration is also given to the complexity of the hydrocarbon components and the influence of refining methods on toxicity. Some mechanisms by which an animal system may attempt to overcome injurious effects are outlined. Finally, methods of aiding recovery are suggested.

Introduction
Formation or connate fluids consist of mixtures of hydrocarbons and salt water, and mal' also contain various amounts of sulphur compounds, such as hydrogen sulphide and rnercaptans. These components may be present in almost all conceivable proportions-some formation fluids contain no water, some are all water, some consist of only light hydrocarbons (i.e. natural gas) and some contain only very heavy hydrocarbons. Also, these fluids may be sour (containing sulphur compounds) or they may contain no sulphur compounds and are referred to as being sweet., This is largely dependent on the formation of origin. Unfortunately, therefore, a spill of formation fluid will often present more than a crude oil spill problem. Each of the major components of the connate fluid can generate its own set of unique problems. The causes of these problems often obscure each other to the extent that what appears to be a simple oil spill may not respond to treatment. Examination and analysis may show, for example, that the oil spill also contained a salt spill. The salt could have been present in the crude oil as free brine, as emulsified salt water or as suspended micro-crystals in the oil. A high concentration of salt in the oil could have a serious effect on he rehabilitation program. Crude oils have been tested hich contained 20,000 lbs of salt per 1000 barrels of oil.
A crude oil spill may therefore consist of three intertwined problems:a hydrocarbon problem;a mercaptan and hydrogen sulphide problem;a salt problem.

The Hydrocarbon Problem
The hydrocarbons in crude oil are present in a variety of forms; some are volatile, some are waxy solids and some are tarry solids, depending on the kind of crude oil that is involved. Crude oils may be categorized as several types:paraffinic - straight-chain saturated hydrocarbons.naphthenic - cyclic compounds, partially saturated.aromatic - having benzene rings in their structure.asphaltic - generally containing some of the above, but having greater chain length, and having other elements.
Each of these types of crude oils has a light (gasoline-like) fraction and several heavy (oily, tarry or waxy) fractions. Each fraction has a different solubility in water, and usually this appears to modify the over-all undesirable effects on various species of animals and plants encountering the crude oil.
These undesirable effects will be referred to throughout this paper generally as toxicity.
Fireflooding Shallow Tar Sands - A Case History
Authors: Terwilliger P.L. 
Published: March 2010

Abstract
A field pilot test of forward combustion utilizing fracturing techniques was conducted in a shallow tar sand deposit in central Kentucky. The tar sand at a depth of 100 ft had an average porosity of 22%, an oil saturation of 64% (6.4% tar by weight) and a permeability after extraction of about 2000 md. The tar had an API gravity of 10.4 º and a viscosity of 150,000 cps at a reservoir temperature of 561JF. The pilot area, was a small inverted fivespot 107 ft on a side. Horizontal fractures were created on the four producing wells by breaking down the formation with air pressure, and these fractures were propped to a calculated radius of 25 ft by injecting water-base gel carrying 4–8 mesh sand. A pneumatic fracture was created in the central injection well, which was held open by the continuedinjection of air. A down-hole burner was used to initiate the combustion zone.
Oil production responded to the movement of the combustion zone ten days after the fireflood was started. The average oil production was 24 barrels per day for the four months required to complete the test. The total oil production of 8100 barrels was 54% of the 5700 barrels originally in place in the pattern area. The injected air produced oil ratio was 42,000 cu. ft/bbl. The produced oil was upgraded to 14.5 API and 2000 cps at 60 ºF, compared to 10.6 º API and 90,000 cps for the original tar at the same temperature. The major problems encountered were the lack of complete oxygen consumption, the unsymmetrical advance of the fireflood and the tendency of the combustion zone to move toward the top of the reservoir.

Introduction
During 1959 and 1960, Gulf Research & Development Co, conducted a fireflood field pilot test in a shallow tar sand deposit lying about halfway between the towns of Brownsville and Leitchfield, Kentucky. The property had been leased from the Kentucky Rock Asphalt Co., hence the name KYROCK. The fireflooding or forward combustion method has been adequately described elsewhere.(1, 2, 3, 4) and the modification tested at the Kyrock site was the utilization of both pneumatically and mechanically propped fractures. Earlier reverse combustion experiments in the tar sand deposit had indicated that horizontal fractures could be extended at constant depth over considerable distances and that a forward combustion reaction zone could be maintained using these fractures for a major part of the fluid flow.
Although the results of these tests were encouraging, neither further development of the method nor publication of the results was warranted at that time because tar sand production could not compete economically with the adequate supplies of conventional crude. In the last few years, that situation has changed and now supplies of hydrocarbons from any and all sources are needed to augment the declining rate of domestic production.
Thermal Recovery In The Venezuelan Heavy Oil Belt
Authors: Ballard J.R. , lanfranchi E.E. , Vanags P.A. 
Published: March 2010

Abstract
This paper describes a successful cyclic stea1n injection program in the Jobo Field, located on the northeastern edge of the Venezuelan Heavy Oil Belt. The program was commenced in 1974 by Amoco International Oil Company. It is being continued, following reversion, by Amoven, S.A., a subsidiary of Petroleos de Venezuela. The Jobo reservoirs are highly unconsolidated sandstones at a depth of approximately 3,800 feet. The crude gravities range from 9 to 13.5 °API. Wells were completed on 64-acre spacing utilizing techniques designed to withstand thermal processes.
A portable steam generator rated at 30 MMBtu per hour is used and the steamed wells have received between 4,000 and 8,000 metric tons each. This corresponds to between 150 and 200 MMBtu per foot of pay. The wells are placed on production after soak periods varying from one week to one month. In the eleven wells which have been steamed at this writing, peak oil producing rates ranging from two to five times the pre-steam rates have been realized almost immediately on commencement of production.
The techniques described herein have permitted injection of high-quality steam at appreciable depths while avoiding m.ost of the common problems normally expected, such as bottom-hole equipment failures, casing cement and liner failures, and surface equipment malfunctions.

Introduction
STEAM STIMULATION is a well-established technique developed in the early sixties. It has found extensive application in Venezuela, mostly in shallow heavy oil reservoirs ranging in depth from 300 to 3,000 feet and containing oil of moderate gravity ranging from 14 ° to 20 °API. Success has been notable in several areas, mostly along the Juseping trend in eastern Venezuela and the Bolivar Coast on the eastern shore of Lake Maracaibo.
The technique has not been very successful where the reservoir and crude oil properties vary appreciably from the ranges given above. This is the case in the northern portion of the Orinoco Heavy Oil Belt; the reservoir depth is between 3,600 and 4,000 feet, the oil viscosity averages 1,800 SFS and the oil gravity ranges between 8.5 and 13 °API.
This paper describes a successful steam stimulation project in the Jobo Field, located on the extreme northeastern edge of the Orinoco Heavy Oil Belt. The project is notable as a demonstration of the successful application of steam stimulation under conditions of extreme depth, viscosity and gravity.

Field Description
Figure 1 is a map of Venezuela, showing the location of the Jobo Field with respect to the vast Orinoco Heavy Oil Belt. The heavy oil belt contains some 700 billion barrels of oil in place, but has seen only scattered development on the extreme northern fringe. Jobo underlies a 5,500-acre concession originally granted to Amoco Venezuela Oil Company and now under the administration of Amoven, S.A., a wholly owned subsidiary of Petroleos de Venezuela, S.A.
The productive Oficina Sandstone at Jobo is separated into two distinct reservoirs, designated Group I and II.