bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer Calculations Of Compressibility Of Natural Gas
Authors: Abou-Kassem J.H. , Mattar L. , Dranchuk P.M. 
Published: March 2010

Abstract
An alternative method for the calculation of pseudo reduced compressibility of natural gas is presented. The method applies the definition of reduced compressibility (Equation Available In Full Paper), where both Pr and (Equation Available In Full Paper) are variables available as DR and DP in both the Dranchuk et al. and Dranchuk and Abou-Kassem Z-Jactor subroutines. This method is incorporated into these routines by adding a single FORTRAN statement CR = O.270/(DR*DP}before the RETURN statement. This method is suitable for computer and hand-held calculator applications. It produces the same reduced compressibility as other available methods but is computationally superior.

Methodology
The methods of calculating compressibility of natural gas are derived from the following relationship between C and Z:
Equation (Available In Full Paper)
Trube(1) presented a graphical correlation of cr as a function of Pr and Tr based on equation (2) using the Brown et al. (2) Z-factor chart. While this correlation is useful for hand calculation, it is not suited to computer usage. Mattar et al. (3) used the following expression for cr that was based on the manipulation of equation (2)
Equation (Available In Full Paper)
Although the last two methods are suited to computer usage; they require the Dranchuk et al.(4) Z-factor subroutine that calculates Z which in turn would be used to calculate Pro Both Z and P, are used in equations (2), (4), (5), (7) and (8). Close examination of the Dranchuk et al.(4) Z-factor routine reveals that this routine solves for Pr for a given Tr and Pr using the Newton-Raphson iteration. The form of the equation used is
Equation (Available In Full Paper)
The suggested approach is applicable to all equation-of-state based romines for calculating Z-factor (e.g. Hall and Yarborough(6), Dranchuk and Abou-Kassem(7). Because of the similarity between the Dranchuk et al. (4) equation and the Dranchuk and Abou-Kassem(7) equation (based on BWR EOS), and the wide-spread use of these two routines for predicting Z-factor, the following is an account of why and where to incorporate necessary modifications to calculate cr in both routines using the suggested approach. These two equations can be expressed in a general form as:
Equation (Available In Full Paper)
Finally, the numerator in the right-hand-side of equation (13) is represented by DP in these routines. Therefore, A statement for Cr that is based on equation (11), may be incorporated in both routines by inserting the following FORTRAN Statement before the RETURN statement:
Equation (Available In Full Paper)
The modified versions or both the Dranchuk el al. (4) and Dranchuk and Abou-Kassern(7) routines, which were tested and verified to reproduce the Mattar et al.(3) graphical correlation for er are presented in Appendix I and Appendix 2 respectively. The results of the various method considered in this paper are compared in Table 2 for T, = 1.05, l.5, 2.5 and 3.
Wellbore Flow Resistance In Steam-Assisted Gravity Drainage
Authors: Ong Tee S. , Butler R.M. 
Published: March 2010

Abstract
The potential for the more economic recovery of heavy oil has encouraged many researchers to investigate the steam-assisted gravity drainage process. These studies have usually involved physical models. One problem which is encountered is in the scaling of a field well to a laboratory well. In this paper, from considerations of the pressure gradient along the well, it is shown that the scaling factor for the radius of the horizontal well Is not proportional to the geometrical ratio for the laboratory model and the field but to the one-fourth power of this ratio.
A computer program was developed to predict the pressure profile of the production well, the oil flow rate along the well and the gravity head of the heated oil backed up by the flow resistance of the well. The computer program was used to study the effect of the viscosity of the fluids (or the wellbore temperature) within the well, the well size and the well length. Calculations performed by the computer program shows that the drainage of the produced fluids can be Impeded if the wellbore temperature is too low or if the well size is too small.

Introduction
Canada has abundant deposits of heavy oil. The potential of using horizontal wells for the recovery of these deposits has encouraged many researchers to investigate the steam-assisted gravity drainage (SAGD) process using physical models. In the SAGD process steam is injected continuously so as to form a "steam chamber". Oil drains from around the perimeter of the chamber to a production well which is located below. Gravity provides the driving force which causes the heated oil to flow. Because gravity drainage is relatively slow, a horizontal production well is employed so as to provide more reservoir contact and greater production. As the steam condenses the condensateis removed along with the draining oil. The steam chamber grows in size as the process continues. The process is illustrated in Figure 1.
he principal driving force for the drainage of produced fluids toward the perforated horizontal well from around a constant pressure steam chamber is the fluid static head (or gravity head). Some of the available head must be used to drain the produced liquids that flow along the wellbore. It is crucial that the size of the horizontal well be sufficiently large so that the head dissipated in moving the produced fluids along the well is not excessive. Erroneous experimental results (oil production rate or steam chamber propagation rate) can be obtained in laboratory models if the wellbore flow resistance is excessive compared to that in the field.
In this paper, the effect of wellbore flow resistance has been studied and it is found that laboratory models require surprisingly large wellbore radii.

Scaling the Horizontal Well
For scaling of field conditions to laboratory conditions, Butler(1) proposed that the dimensionless number. B3 and the dimensionless time, T', must be equal for both field and laboratory conditions.
The Changing Nature Of The Canadian Oil And Gas Business
Authors: Slagorsky C. , Fraser B. 
Published: March 2010

Introduction
The international petroleum industry ranks as one of the most important industries in the world. In 1989, the value of total world trade in crude oils and refined products alone exceeded US$2.0 trillion. More than 11 billion barrels of crude and products were traded internationally. In addition, more than 10 Tcf of natural gas crossed international boundaries (Fig. 1).
Over the last 20 years, the industry has gone through a series of unprecedented changes. The structure of the industry has evolved from an ordered world managed by the majors, through a transitional period in which OPEC controlled prices, to the uncontrolled and highly volatile world of commodity pricing today. Over this period, oil has also become less important to the industrialized economies as an energy source. Between 1973 and 1988, the OECD countries cut their energy use as a proportion of output by 25%. Their oil use as a percentage of output fell by 40%.
These changes have had a profound impact on the North American industry. For instance, in the U.S., one half of the 25 largest oil companies in 1950 were no longer in that grouping by 1980. Of the 25 companies listed in 1980, only 17 exist today. In Canada, concentration of reserves ownership increased. The largest companies controlled 68% of total oil reserves and 53% of total gas reserves in 1984. By 1988 these figures had increased to 80% and 63%, respectively.
The two price shocks in 1973/74 and 1979/80 gave the North American upstream industry a boost. In the U.S., higher prices perpetuated oil exploration in a region which ranks as one of the highest cost producing areas in the world and is the world's most drilled up geological province. In Canada, exploration expenditures and reserves increased. The oil price collapse of 1986 again changed the business fundamentals. In a "low-price world ", it forced industry to change once more and embark on a long and painful process of restructuring, asset rationalization and cost cutting.
The considerable challenge for the North American industry is that the bulk of world proven reserves can be produced profitably at US$15.00/bbl or less. This sets a target long-run cost ceiling for the North American oil industry. This is a tremendous challenge. Both oil finding costs and the cost of doing business generally are higher in North America relative to the rest of the world. Thus, the main challenge facing the North American oil industry is how to prosper in a low oil price environment.
In Canada, the policy response to the two oil price shocks during the 1970s was a sharp rise in industry regulation. The federal government followed a policy of "made in Canada" pricing (i.e. an oil price lower than the world price). This generated bitter disputes over fiscal transfers between the producing provinces which owned the resource and the consuming provinces, and between the federal and provincial governments. It also discouraged exploration and development investment in conventional areas.
Well Testing In Alberta — 1990s Style
Authors: Warren A. 
Published: March 2010

Abstract
This paper presents the highlights of a new guide for well pressure and deliverability testing in Alberta. The guide was developed by a joint Industry-ERCB committee to reduce test costs, improve test quality, and clarify testing regulations. New requirements define quality pressure survey methods, and the minimum number of tests that should be run for prudent reservoir management. Relief from testing is provided for advanced depletion, small reserves, low permeability, heavy oil, low productivity, and reduced spacing. In addition, testing costs are reduced by accepting pressures from shut-in wells, acoustic methods, and drill-stem tests, under certain conditions. Operators can choose the type of deliverability test they run: single- vs multi-point. Tests can be scheduled to optimize field operations. The new well testing environment for the 1990s should become less regulated but this requires that the operating industry be committed to quality testing in accordance with the new guide. The industry, the ERCB, and the public stand to gain from this new approach to data gathering.

Introduction
In 1989, it cost over $250 million dollars to run pressure and deliverability tests for Alberta's oil and gas wells. This cost is expected to increase significantly, throughout the 1990s, as more wells are needed to supply existing and new markets for oil and gas. The time has come to ensure that we get the most from future testing dollars by carefully examining our data needs and test procedures.
The Energy Resources Conservation Board (ERCB) has a mandate(1) to provide for the gathering and dissemination of information regarding the energy resources of Alberta. Accordingly, it developed regulations(2), as early as 1961, for the taking and reporting of well tests. The purpose of these regulations is to ensure adequate quality pressure and deliverability data, for use in engineering and economic studies of Alberta's oil and gas pools. Over the years, these regulations were revised a number of times in response to the changing needs of the ERCB, and the operating industry.
In 1987, a joint Industry-ERCB technical committee (the committee) was formed to review the ERCB's well testing regulations. The review has resulted in the development of a new guide for well testing(3). A draft of the new guide was distributed to several industry associations: IPAC, CPA, SEPAC, and CIM, for their comments. Their responses suggest that the guide was well received but that further effort is needed to clarify its contents.
The ERCB decided to release a first edition of the guide in the second quarter of 1990. This was done to give both the ERCB and the industry an opportunity to work with the revised requirements, and benefit from them without delay. The ERCB has asked the committee for a review of well testing under the new guide in mid-1991. Any problems encountered can be addressed in a second edition of the guide. Assuming no major problems remain, the ERCB will formally adopt the second edition or the guide as part of its regulations.
Correlations Developed To Predict Two-Phase Flow Through Wellhead Chokes
Authors: Abdul-Majeed Ghassan H. , Maha R. Abdul-Ameer 
Published: March 2010

Abstract
The predictive accuracy of ten critical two-phase flow correlations in combination with four PVT property correlations, is tested against field measured production data, from 210 well tests, covering a broad range of production rates, choke sizes, upstream pressures, gas-liquid ratios and oil API gravities. Test data are divided into four selected categories based on choke size (D) : D &lt;6, 6 ≤D &lt;10, 10 ≤D &lt;30, and D ≥30/64 ".
The average per cent error, absolute average per cent error and standard deviation are computed for each correlation combination.
It is observed that the choice of empirical PVT correlation appears to have only a minor effect on final calculated statistical results. Also it is found that most of the compared correlations yielded unsatisfactory results, therefore an attempt is made to find correlations that best fit the measured data. As a result, four new correlations are developed (a correlation for each diameter category).
Based on the statistical results, the new correlations clearly outperformed the original correlations.

Introduction
Several correlations have been published for describing critical two-phase flow through wellhead chokes. Most of these correlations were based on limited ranges of flow variables. Their validity is limited by the quality and scope of the data upon which they are based.
The objectives of this study are:to determine the optimal combination of critical flow and PVT correlations for predicting flow rates; andto modify the existing correlations if necessary or develop new correlations that best fit the measured data.
The correlations compared are those of Gilbert(1), Ros(2), Baxendall(3), Achong(4), Poettmann-Beck(5), Omana(6), Ashford(7), Pilehvari(8), Sachdeva et al.(9) and Hazim-Ghassan(10). Some of the correlations require values of fluid physical properties, combinations of the following PVT correlations are used to estimate them:
Oil FVFStanding(11)Vazquez-Beggs(12)Ghassan-Naeema(13)
Solution GORStanding(11)Lasater(14)Vazquez-Beggs(12)
In addition, other PVT properties are calculated using the following correlations:
Gas Compressibility : Hall-Yarborough(15)
Gas-Oil Surface Tension : Baker-Swerdloff(16)
The performance of each critical flow/PVT correlations was checked against the measured well data. Statistical tools were used to determine the optimum correlation combination for predicting flow rates.

Well Test Data
Fifty-six tests from Iraq wells, 108 from Poettmann's study(5), 27 from Ashford's study and 37 from Omana's study are combined in a data bank for this investigation. The approach developed by Sachdeva et al.(9) (Eq. 1) is used to verify that the test data collected are within the critical flow regime rather than subcritical flow regime.
Equation (1) (Available In Full Paper)
Where
Yc = critical pressure ratio
x1 = free gas quality
VG = gas specific volume, ft3/lbm
VL = liquid specific volume, ft3/lbm
Gravity Drainage To Horizontal Wells
Authors: Butler R.M. 
Published: March 2010

Abstract
Pressure depletion and high water-oil ratios limit the recovery which can be obtained from many oil reservoirs using conventional methods, to disappointingly low values.
The maintenance of pressure by water injection (waterflooding) or by gas injection can be relatively ineffective because of the tendency of the injected materials to finger through the oil.
Although the density difference between oil and gas allows gravity segregation to improve the picture for downward f/ooding with attic gas injection, the tendency for the gas to finger down to the production well for practical production rates, limits the improvement with conventional wells. Horizontal wells can change the picture because of their much lower drawdown requirements.
In this paper, the production of heavy oil reservoirs by gravity drainage with a gas cap advancing down toward horizontal wells is analyzed theoretically. It is assumed that reservoir pressure is maintained by the injection of gas at the top of the reservoir and that the production rate is controlled to just below the critical rate for gas coning. The theory indicates that, for such conditions, recovery rates of the order of several hundred B/day are possible and that relatively high recoveries can be achieved. By maintaining the pressure of the production well equal to that of a lower aquifer, it is possible to carry out the above operation without excessive water production.

Introduction
This paper discusses the production of oil by displacement created by the downward expansion of a gas cap. The displaced oil flows to parallel horizontal wells located near to the base of the reservoir. It is assumed that the gas pressure is maintained constant by injection and that the low viscosity of the gas, compared to that of the oil, maintains a constant pressure within the cap. The conditions are chosen so that gravity effects prevent the flow of free gas to the production wells; i.e. the process is carried. out below the critical coning velocity(l). The process is one of gravity drainage and can be expected to give high recovery(2,3).
While such a process can be carried out using arrays of vertical wells, it is much more effective with horizontal ones, particularly if they are closely spaced. The effect of pattern size and shape for horizontal wells has been analyzed in recent papers(4,5) and it has been shown that for close spacings (but not so close as to be economically unfeasible) the productivity index for pseudo steady-state flow to horizontal wells can be as high as 50 to 100 times that for vertical wells drilled on the same aereal spacing.
The practical significance of this, for the situation considered here, is that operation below the critical production rate may be feasible for horizontal wells in situations where it would be impractical with vertical ones. In such situations, the gas injection which is required for pressure maintenance is simply that to replace the produced oil on a volume basis plus a minor amount which is dissolved.
Applications Of Mixed-Wet Pastes In Gravity Drainage Experiments
Authors: Catalan L. , Dullien F.A.L. 
Published: March 2010

Abstract
Mixed-wet pastes consisting of a mixture of water-wet grains, oil-wet grains, brine, and oil can be used to overcome some of the limitations generally associated with gravity drainge experiments in the laboratory. Semi-permeable membranes made with mixed-wet pastes having grain sizes no larger than a few microns are able to prevent the gas breakthrough and eliminate capillary end effects. Pastes with larger grains are suitable to establish capillary continuity at the junction between short reservoir plugs in a composite core.

Prevention of the Gas Breakthrough and Elimination of Capillary End Effects
During gravity drainage experiments assisted by inert gas injection and carred out in vertical cores initially saturated with oil and brine it has been shown that the gas breakthrough occurs before the totality of the oil bank has been produced, even if the production rate is kept very small(1,2). After gas has broken through, some additional oil can be produced, but nevertheless, a part of the oil initially present will remain in the bottom part of the core. Experiments done in our laboratory with a four-fool long vertical Berea sandstone core have shown that the oil saturation at the bottom end is approximately 80% at gas breakthrough, and it decreases with height. Naylor and Frorup(2) used radioactive tracer techniques to measure fluid saturations within a 0.885 m long aeolian sandstone core during a tertiary gravity drainage experiment in which nitrogen under low pressure was flowed continuously through the core. After 86 days of gasflood, the oil saturation was 8% in the top half of the core and increased in the bottom half to reach 31% at the bottom end. The phenomenon of this oil retention in the bottom pan of the core is a capillary end effect. It is due to the gas pressure and therefore the gas-oil capillary pressure being low near the bottom when gas is flowing through the core. A detrimental consequence of the end effects is that, everything else being equal, the percentage of recovery of residual oil increases with the length of the core. Indeed, as the length of the core increases, so does the thickness of the oil bank, compared with the vertical distance over which capillary retention takes place (approximately 40 cm in Berea).
The most obvious solution to producing the remaining oil is to eliminate the capillary end effects, and this can only be achieved by preventing the breakthrough of gas_ A semi-permeable membrane, which is put in contact with the producing face of the core, was developed for this purpose. This membrane must be mixed-wet, that is, permeable to oil and brine, but impermeable to gas. With the membrane in place, it is possible to establish a sufficiently high oil-gas capillary pressure in the bottom part of the core to eliminate the capillary retention of oil.
In order to prepare the mixed-wet paste from which the semi-permeable membrane is made, very fine powders of calcium carbonate (water-wet) and active carbon (oil-wet) need to be obtained.