bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery Of Crude Oil By Nitrogen Illljectionlaboratory Displacement Data
Authors: Sayegh S.G. , Wang S.T. , Fosti J.E. 
Published: March 2010

Abstract
Four series of slim tube displacement tests were carried out on a Nisku crude oil at 103 °C, wherein the injection gases were nitrogen and nitrogen enriched with propane and carbon dioxide. Ail the runs were immiscible at pressures up to 34.6 MPa. Twelve floods were performed in Berea cores using the same oil to examine the effects of miscibility, water saturation, mode of injection, and care orientation. The propane slug/nitrogen chase gas mode of injection was the most efficient way of utilizing these gases to produce oil, especially when gas injection was carried out as a secondary enhanced oil recovery process.

Introduction
This is the second paper written by the authors (Sayegh and Wang) on the recovery of crude oil by N2 injection. The first Paper(l) dealt with the screening of petroleum reservoirs to select candidates for N2 flooding; phase behaviour data of a Nisku crude oil with N2, N2 plus CO2, and N2 plus C3Hg; and the correlation of the phase behaviour data using the Peng-Robinson equation of state.
This paper deals with the displacement of Nisku crude oil from porous media by N2 injection, and includes slim tube displacement tests and their numerical simulation as well as Berea core floods. The oil-in-place (live Nisku crude), the injection gases (N2, CJHg and CO2 mixtures), and the temperature (l03 °C) are the same as those for the phase behaviour measurements. Table 1 lists some of the main properties of the live Nisku crude. The displacement pressures include those at which the phase behaviour measurements were carried out, as well as higher values. Hence, this paper, together with the work presented in Reference 1, provide complementary sets of data relating to the recovery of crude oil from petroleum reservoirs by N2 injection.

Slim tube Displacement Tests of Nisku Crude Oil by N2 Mixtures
The phase behaviour measurements presented in Reference 1 were designed to simulate the multiple contact process that occurs during oil displacement in porous media. A lot of information was gleaned from these measurements, but unfortunately only four "contacts" could be carried out because of equipment limitations. The slim tube displacement data presented in this section provide information on what occurs in such systems when a large number of contacts occur.

Experimental Apparatus and Procedure
The slim tube displacement apparatus is shown schematically in Figure 1, and a detailed description may be found in Reference 2. The tube itself was made from stainless steel, was 12.2 m long, had an internal diameter of 4.57 mm, and was coiled. It was packed with 100 µm diameter glass beads to a porosity of 0.37. Its pore volume was measured to be 73.7 ml. Live Nisku crude was the oil-in-place in all the displacements, 103 °C was the test temperature, and the gas injection rate was kept at 2.5 ml/hr for all of the runs.
Characterization Of Athabasca Bitumen For Gas Solubility Calculations
Authors: Mehrotra Anil K. , Svrcek William Y. 
Published: March 2010

Abstract
The solubility of five pure gases, namely N2 CO, CH4, CO2 and C2H2, in Athabasca (GCOS) bitumen is calculated using the Peng-Robinson EOS and with the use of the literature bitumen characterizations and a new ‘3PC’ characterization. The calculated gas solubilities are compared with the published data over a temperature range of 20 °C to 110 °C and pressures up to 10 MPa. The best over-all match of the gas-solubility data is obtained with the ‘3PC’ scheme which models the bitumen as a mixture of three pseudocompoments. Optimized values of the binary interaction parameter for use in the Peng-Robinson EOS are also provided.

Introduction
The objective of this paper is to evaluate bitumen characterizations for calculating the solubility of five gases, namely N2, CO, CH4, CO, and C2 H6, in Athabasca bitumen by use of the Peng-Rpbinson(l) equation of state (EOS). Bitumen is a highly complex mixture of light, medium and heavy organic compounds. Hence, it is not reasonable to model the bitumen as a single pseudocomponent even for use in simple calculations.
Three bitumen characterization schemes for Athabasca (GCOS) bitumen are considered in this paper. The first scheme of Mehrotra et al.(2), with the bitumen-split suggested originally by Bishnoi et al.(3), consisted of five pseudocomponents. The second scheme of Johnson et al.(4), consisting of four pseudocomponents, had been used for predicting the viscosity of gas-free and gas-saturated Athabasca bitumen by use of a corresponding states method. A third scheme consisting of three pseudocomponents (termed the ‘3PC’ scheme) was developed in the present study. For all pseudocomponents in each of the above mentioned schemes, the critical properties and acentric factor were estimated from the Kesler-Lee(5) correlations, which have been shown to produce satisfactory results for the solubility of CO2, in Athabasca and Peace River bitumens(2).
The literature on the measurement and prediction of thermodynamic properties of light hydrocarbons/gas systems is extensive. However, the literature specifically related to the properties of Alberta bitumen/gas systems is still very limited.
An Empirical Correlation for Oil FVF Prediction
Authors: Abdul-Majeed Ghassan H. , Salman Naeema H. 
Published: March 2010

Abstract
A new empirical correlation for predicting oil FVF at bubble point pressure is developed from 420 experimentally obtained oil FVF on 119 oil-gas mixtures collected from four different unpublished sources.
When applied to all data, the newly developed correlation clearly out-performs the existing oil FVF correlations, based on low values of average per cent difference, absolute average per cent difference, and standard deviation.
The present and the existing correlations are evaluated within pre-determined ranges of oil API gravity. Five main ranges of this parameter are selected for best correlations.

Introduction
The oil formation volume factor, Bo, is a factor used to estimate the change in volume of oil as it undergoes a change in pressure and temperature. The change in volume is a combination of thermal expansion, compressibility effects, and mass transfer, which is represented by gas evolving from or going into solution. Therefore oil FVF is the volume of oil at P and T occupied by one stock tank barrel (STB) of oil and the gas in solution. Several empirical correlations have been published that can be used to estimate Bo at and below bubble point pressure (Pb). The most widely used correlations are shown in Table 1.
The scope of the proposed research consisted of developing a new correlation for estimating Bo at and below Pb.

Data Acquisition and Preparation
The analysis of 119 bottom-hole fluid samples were made available for this study. The data bank used (consisting of a total of 425 PVT tests), is obtained from four different unpublished sources. In these sources, the flash separation data were used in conjunction with the values of the flash and differential process to calculate the combination formation volume factor. The calculations were performed assuming that the relationship between the flash and differential liberation processes is constant at any reservoir pressure (the procedure of calculations is described, in detail, in Ref. 2, p. 18).
Each of the PVT tests is examined for unreasonable values. If the observed FVF for a PVT test seemed unreasonable when compared to the FVFs estimated by all the existing FVF correlations (Le. the per cent errors of all the correlations are greater than 10%), the PVT test is eliminated from the data set. As a result, five data points are removed. The revised data bank now contains 420 data points (Table 2). A brief description of the revised data bank is given in Table 3.

Development of the Correlation
Using non-linear multiple regression analysis, the following relation is developed from 420 experimentally obtained oil FVF on 119 different oil-gas mixtures:
Equation (Available In Full Paper)
The same units apply for Rs, Gag, Gao, and T as in the equations shown in Table 1.
The developed correlation meets approximately the requirement for the formation volume factor of 1.0 at 60 °F and atmospheric pressure (R=O). Figure 1 is a plot of the observed Bo values vs the estimated Bo values for the data used.
Surface Tension Of Petroleum Mixtures
Authors: Pedersen Karen Schou , Lund Torgeir , Fredenslund Aage 
Published: March 2010

Abstract
A new correlation has been developed where the surface tension of a petroleum mixtures is related to the viscosity. The calculated results compare well with experimental observations atboth atmospheric and higher pressures. Accurate results are also obtained using a modification of the procedure of Lee and Chien.

Introduction
The surface tension is defined as the partial derivative of the surface free energy with respect to the dividing area between the gas and liquid phases.
Proper estimation of the surface tension of oil-gas systems is important in a number of reservoir engineering calculations. The surface tension is required to predict the capillary pressure of the oil in a porous solid. The surface tension also influences the relative gas/liquid phase permeabilities.
For pure components it has been experimentally observed(1) that there is an almost linear dependence between the reciprocal of the viscosity, η, and the logarithm of the surface tension, σ:
(1) In ( J = In A + B / ρ )
A and B may for pure components be determined by a least
TABLE 1. Results for the surface tension at atmospheric pressure of oils 1–7 and of gas condensate 1. Available in Full Paper.
squares fit to experimental data relating the viscosity to the surface tension. For mixtures it is less obvious how to determine A and B. On the other hand it is desirable to be able to determine the surface tension from the viscosity. Viscosity data are more frequently available than are surface tension data. Also more reliable correlations exist for predicting the viscosity(2, 3) than is the case for the surface tension.

1. Experimental Data
The surface tensions have been measured of eight North Sea reservoir fluids (7 oil mixtures and 1 gas condensate mixture) flashed to standard conditions (1 atm and 15 °C). The surface tensions were measured with an MOM Lauda Ring Tensiometer. The thermalization time was chosen long enough to allow surface equilibrium. For the temperatures reported, repeated measurements on the same sample showed no time effect. The viscosity measurements were performed with a Contraves Low Shear 30 Viscometer. The reported viscosities correspond to a shear rate of 100 S-I. The densities were measured with an Anton Paar-DMA 602H apparatus. The surface tension results for the 8 mentioned petroleum mixtures are presented in Table. 1. The corresponding results for viscosities are shown in Table 2. In Tables 3–10 molar compositions of the 8 petroleum mixtures are given. In addition to the data of Tables 1 and 2, pure component data for ethane, propane, n-butane, n-pentane, n-hexane, benzene, toluene(1) and cyclohexane(4) have been used to develop the procedure of the following section.
Experimental surface tension data for a reservoir fluid(5) has been used to test the predictive capabilities of the calculation procedures at higher pressures. The results are given in Table 11 and the molar composition of the reservoir fluid in Table 12.
The Directly Ploughed Concept For Small-Inch Pipelines - A Modern Approach To Reducing Installed Costs And Minimizing Environmental Impact
Authors: Maki D.R. 
Published: March 2010

Abstract
Coiled and straight length metallic pipeline systems, installed by the direct ploughing technique, are in a period of rapidevelopment. These systems (in 33.4 mm through 168.3 mm sizes) are now available in operating pressures of from 690 to 6900 kPa and provide an economic means of delivering large volumes of gas and liquids to processing facilities at low installed costs.
This paper will deal with developments in installation (ploughing) techniques for metallic pipeline systems, typical cost reductions available through the use of the technique (vs straight length welding and ditching), plus offer suggestions as to further cost reductions available to operators from the land use/easement purchase and environmental reclamation points of view.

Introduction
Oil and Gas Production Operations in Canada – Pipelines and Line Pipe Sizes
The majority of pipelines installed each year in western Canada for direct production purposes by oil and gas developers are in the 60.3 mm to 168.3 mm range; pipeline expansions in large inch pipe are limited, although some are presently being undertaken to deliver more crude, an increased variety of crude blends, heavy crudes and natural gas to specific end markets(1). Crude oil delivery levels to major pipelines have been kept up in western Canada over the last several years due in great part to high drilling rates (in the late 70s, early 80s and 1985) and increased production from the operating Tar Sands Plants. The large-inch pipelines now in place are being debottlenecked and can handle the steady and declining volumes of rudes being delivered to them. This situation will change in the 90s (when there will need to be more large-inch construction projects to deliver reserves from the frontiers), but until then, pipeline construction in western Canada will likely be concentrated in the "small-inch" area and for the following applications:Delivery of oil and gas to existing and new surface facilities.Transport of oil, gas and NGLs to major pipeline facilities for delivery to end markets.Transport of commodities to enhanced oil recovery schemes (gas, water, solvents).Injection pipelines as part of E.O.R. projects (water, solvents).Water disposal pipelines.
In parallel with declining reservoir deliveries and productivity is a natural lowering of operating pressures for the majority of systems. In grid form, the following types of lines can be subjectively classified by their characteristics (operating pressure, burial depth, and corrosivity) and approximate (proportional to the whole) percentages assigned to their sub-categories:

Lines by Type of Characteristics (Table 1)
Table 1 Available in Full Paper.

These Types of Lines do not Need to be Overbuilt!
This analysis is very subjective, but the figure as generated for the above lines is probably not far off the mark and these types of lines also have one other characteristic in common – they can be directly ploughed.
Panther River Well Stimulations - A Case History
Authors: Milligan M.R. 
Published: March 2010

Abstract
During 1986 two large volume stimulation treatments were carried out on two low-permeability (&lt;0.1 mD) Panther River wells. The formation treated was the Mississippian Turner Valley (Mt); a thrust-faulted dense dolomite containing sour gas (average 6% H2S) and found at about 4500 m (15 000 ft). Panther River No.2 was stimulated with a staged gelled pad, retarded-acid frac. Panther River No. 7 was stimulated with a massive propped frac using crosslinked HPG frac fluid and 40/60 sand. One of the objectives was to evaluate the response of low-permeability Panther River wells to these different stimulation techniques.
This paper reviews well and reservoir characteristics, selection of stimulation candidates treatment design and execution, and the stimulation results.

Introduction
The Panther River sour gas field is situated on the eastern slopes of the Rocky Mountains about 100 km northwest from Calgary and 12 km southwest from Shell's Burnt Timber sour gas field (Fig. 1). The Panther River field was discovered in 1958. Development has been gradual due to uncertainty in drilling he deep (up to 5100 m), expensive, low-deliverability wells, and the unavailability of suitable processing capacity and markets for the gas. Currently, Shell has ten wells drilled and cased in Panther River of which two are abandoned.
Total gas in place is estimated to be 58 E09 m3 (2 TCF); unfortunately, the reservoir exhibits low permeability (less than 0.1 mD) and low deliverability.
Two recent events sparked fresh interest in Panther River: 1. natural gas deregulation legislation in Canada provided new market opportunities for Panther River gas; and decline in deliverability from the Burnt Timber wells has created capacity at nearby Burnt Timber sour gas plant. As a result, Shell is proceeding with construction of facilities to connect five Panther River wells to the Burnt Timber gas plant with production to start in 1989.
Prior to construction of the gas gathering and compression facilities, two wells were selected as stimulation candidates to improve their deliverability and increase recoverable reserves. Massive hydraulic fracture (MHF) stimulations in similar tight gas reservoirs elsewhere had yielded promising resu1ts(1, 2).

Stimulation Candidate Selection
Hydrochloric (HCl) acid stimulations had been previously performed on all wens but one: Panther River No.2 was only drill-stern-tested (DST'd). Table 1 summarizes the acid jobs performed on Panther River wells prior to 1986 and some results calculated from post-frac pressure build-up test analyses.
These acid treatments were pumped at above formation fracture pressure, at the maximum pump rate possible and without leak-off control. It can be seen from Table 1 that the HCl acid stimulations were successful in removing near well bore damage and the creation of short conductive fractures (mostly less than 16 m). The short fracture lengths were believed to have been caused by: uncontrolled vertical fracture growth, small treatment volumes, and high leak-off due to acid wormholing and natural fractures.
A New Approach For Analysis Of The Nuclear Magnetic Log - Resistivity Log Combination
Authors: Aguilera Roberto 
Published: March 2010

Abstract
A new method is presented for analysis of the nuclear magnetic (NML)-resistivity log combination (NML is a Schlumberger Trade Mark). It is shown that a crossplot on logarithmic coordinates of effective porosity (Φe), as determined from neutron and density logs, minus free fluid porosity (Φft) as determined from the NML log vs true formation resistivity should result in a straight line with a negative slope equal to the water saturation exponent, n, for intervals which are at irreducible water saturation.
Extrapolation of the straight line to Φe- Φft = 1.0 yields the product aRw in the true resistivity scale. With these data, values of water saturation are readily calculated. Intervals with moveable water fall distinctly below the straight line, Gas-bearing zones plot above the straight line.
The method is illustrated with the use of a high-porosity sandshale sequence, Estimates of formation permeability and water cut are included in the analysis, A word of caution is raised with respect to the concept that the product ΦeSwi should remain constant for intervals of the same lithology at irreducible water saturation.
A major finding is that water resistivity can be calculated from the NML-Resistivity combination in reservoirs which (1) produce clean oil with no water, (2) have a poor SP development. (3) do not have a well established aquifer, and (4) do not have enough data so as to allow generation of water resistivity catalogues.

Introduction
The nuclear magnetic log (NML) has an approximate radius of investigation of one inch. It measures the earth's field proton free induction decay of formation fluids. As such the tool responds only to hydrogen protons associated with free or moveable fluids in the formation(l).
This characteristic allows the NML, when combined with other porosity logs, to calculate irreducible water saturation, Swi in turn can be used for estimating permeability based on empirical correlations.
A comparison of water saturation as determined from Archie's equation(2) and irreducible water saturation as determined from the NML permits a forecast of fractional water cut for an untested interval.
In carbonates, the NML tool reads close to total porosity due to the carbonates small surface activity(3). The tool is not affected by hydrogen protons in the matrix. This makes it valuable for determination of porosity in unusual lithologies containing extensive water of hydration (for example gypsum) where nuclear tools tend to give very large values of porosity(l).
In formations with light oil, the NML tool gives porosities that include this free oil. In formations with very heavy oil, the NML reads the free water filled porosity. Because the tool radius of investigation is only about 1 in, the NML reading might allow determination of hydrocarbon saturation in the flushed zone.
Neumann(4) has reported on the use of the NML for estimation of residual oil saturation. In this approach, the oil zone is invaded by mud filtrate containing paramagnetic ions.
Lanthanide Fingerprinting And Acidification Of A Glacial Till Soil
Authors: Thimm H.F. , Weleschuk I.T. 
Published: March 2010

Abstract
A glacial till soil from southwestern Alberta was examined in terms of its lanthanide, Th and Sc content in order to establish a lanthanide labelling technique or soil type. It is shown that this technique may also be applicable in acidic soils. The acidification of the soils tested showed that the soils were capable of at least partial, natural pH recovery. This behaviour was found to be due to the presence of two minerals, one of which war confirmed as monazite, a tertiary rare earth phosphate; calcite, dolomite or albite (feldspar) contributions to this pH control were not important. Some implications of this result with respect to environmental monitoring at sour gas plants are discussed.

Introduction
In a previous paper(1), we reported on the use of lanthanide (rare earth) element abundances as an investigative tool for estimating the degree of pollution of pond sediments at a sour gas plant. The original intent in that work was to use the lanthanides as markers for trace element migration in soils subject to the deposition of sulphuric acid precursors. Instead, the hypothetical migration could not be detected, and the lanthanide abundance data implied that even where there is a high acidification potential due to sulphur dusting, the elements may serve better as a fingerprint for the identification of soil strata.
The ability to label soils and sediments by lanthanide abundance might have numerous applications, apart from the utility in environmental assessment during decommissioning of gas plants which we have already reported(1).
The present work deals with the examination of soil data from the Pincher Creek area of southwest Alberta to confirm both the soil labelling ability and the implied lack of sensitivity to deposition of acids. Because it is known from the previous work that the metals in question are easily stripped off the soil with 2.5 M sulphuric acid, it is also necessary to know the soil pH range in which the lack of acid sensitivity can no longer be assumed. Finally, it is of interest to compare the ease of metal removal from glacial till soils with data from the acid precipitation work at Hubbard Brooks, New Hampsttire(2,3) and others(4,5). There have been reports of groundwater pollution by metals released from acidified soils(6). In Alberta, the occasional deficiency of copper in livestock feed has been speculatively linked to the deposition of acidic gases to soil(7).

Study Area
The area chosen for study (Fig. 1) is located in the extreme southwestern comer of Alberta. Two sour gas processing plants had been operating in this area for over 25 years at the time of soil sampling (1983). Emissions for both plants typically totalled 40 t/d SO2 with particulates at 200 kg/day. Prior to 1972, SO2 emissions were substantially higher, near 130 t/d.
The area shown in Figure 1 may be divided into two major soil Types(8). Soils developed from glacial lake bottom material extend to the southeast of Pincher Creek townsite, and then south to the Waterton Reservoir.