bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simultaneous Nonsteady Flow of Oil And Water Through Linear Porous Media
Authors: Pascal H. , Kirkpatrick John W. 
Published: March 2010

Abstract
This paper is concerned with the behaviour of a linear oil reservoir which is produced at constant terminal pressure and is fed b:r a finite aquifer with a sealed outer boundary. The study is confined to the case where the water saturation in the oil reservoir exceeds the so-called irreducible minimum.
Specifically, this work presents a mathematical formulation of the system. The resulting partial differential equations express the pressure distribution in both zones, the wat.er saturation in the reservoir the oil and water flow rates, and the cumulative productions as functions of time. Although it appears that this set of equations can be solved only by numerical means, an approximate analytical solution, valid for large values of time is presented.

Introduction
SINCE AN OIL RESERVOIR call be exploited but once, and the possible exploitation schemes are many, it is necessary to predict the behaviour of the reservoir for each scheme, compare results and choose the scheme which is most suitable according to selected criteria. In order that this be done, mathematical formulation is required for each reservoir and scheme combination.
The object of this study is to examine H linear oil reservoir which is fed by a finite aquifer with a sealed outer boundary. Given the situation in which the water saturation in the reservoir exceeds the critical and the reservoir is operated at some constant pressure at the producing face, the question is can the following be expressed as function of time?water saturation in the reservoirpressure distribution in the reservoirpressure distribution in the aquiferoil production ratewater prodLlction ratecumulative oil productioncumulative water production.
If such functions can be formulated and the resulting equations solved, the information obtained may be used to predict the behaviour of such linear systems either in the field or laboratory.

Problem Formulation
If the cross-sectional area of the reservoir and aquifer are constant and equal, the system may he described pictorially by means of a plan view as shown in Figure 1, where zone I represents the reservoir, zone II represents the aquifer and I and L represent their respective lengths.
For the case where the water saturation in the reservoir is greater than the critical, the pressure in both zones is initially equal and constant al some value, say p, and production is initiated and continued by dropping the pressure at the out flow face to some
(Equation Available In Full Paper)
fixed value, say p one may describe the situation mathematically by means of the following initial and boundary conditions.
(Equation Available In Full Paper)
In addition, zones I and II are coupled by virtue of the fact that the water flux must be continuous across the reservoir-aquifer boundary.
Oil Reserves In Alberta
Authors: van de Panne C. , Kirkpatrick John W. 
Published: March 2010

Abstract

Introduction
IT IS OF CONSIDERABLE INTEREST TO KNOW the total amount of conventional crude oil which can be recovered in Alberta. The Energy Resources Conservation Board has estimatedl J1 this quantity at 20 billion barrels; it also estimated the annual increase of proved reserves at 450 million barrels.
These estimates were obtained by considering the curve of proved reserves of the province over the past 25 years and extrapolating linearly. This is similar to the methods applied to the crude oil reserves of the U.S. by Hubbert(1) and Moore (see Lovejoy and Homan(2)) though the curves fitted by Hubbert and Moore were somewhat more complicated.
Such curve-fittings have their disadvantages. There may be many reasons why a trend which has been present for many years suddenly changes. It is much better to formulate a relationship between the reserves and some other variables which explains the development of these reserves, To estimate such a relationship and to use it for projections is the main purpose of this article.
The increase of the initial recoverable proved reserves (that is all oil known to be recoverable plus all oil produced so far) in any year consists of reserves (that is all oil known to be recoverable plus exploratory wells and additions to and revisions of reserves of oil pools found previously; these additions and revisions are called the appreciation of reserves.
Let us indicate the total proved reserves of the province in year t by Pt and proved reserves in year t of an oil pool discovered in year τ by P (τ) it is obvious that P (τ)t = 0 for t &lt; τ. We have then
(Equation Available In Full Paper)
P(t), are the proved reserves of pools discovered in year t and P(t0)?.P(t-1), are the proved reserves of pools discovered in previous years to, ..., t-l, where to is the year in which the first reserves were discovered.
The appreciation of oil reserves over the years is quite erratic. Nevertheless, it is possible to estimatethe average appreciation of reserves as a function of the years since discovery. The Energy Resources Conservation Board has used(3) the formula
(Equation Available In Full Paper)
where r(t) is the average multiple of the proved reserve in the year of discovery after t years, and a and b are estimated from curve 1 in Figure 1, which gives the averages resulting from the data available. Curve 2 gives the curve fitted in to curve 1, taking into account some other information which* results in the values a = 8.495, b*= 4.4505 or b = 0.7988.
Because the fit of curve 2 is not very good, the author of this article used a nonlinear least-squares procedure to fit (1,2) to curve 1, which resulted in a = 8.7711 and b = 0.88381.
A Three-Dimensional Model For Predicting Natural Gas Reserves And Availability
Authors: Richards Ross 
Published: March 2010

Abstract
A model is presented which analyzes the discovery and subsequent appreciation of natural gas in Alberta using data compiled by the Alberta Oil and Gas (now Energy Resources) Conservation Board. This model is then used for the prediction of new discoveries and subsequent appreciation of existing discoveries. This means that the volumes of gas discovered are analyzed and predicted both as a function of discovery year and year since discovery.

Introduction
PREVIOUS ATTEMPTS at statistically estimating natural gas reserves have dealt with the problem as a process which analyzed and subsequently predicted reserves as a cumulative quantity. No attempt was made at separating the appreciation of present reserves and the prediction of new reserves. Noteworthy of the studies that have been performed are two approaches. The first approach, presented by Hubbert(1) and Moore(2), uses cumulative gas reserves tabulated by calendar year and involves the fitting and extrapolation of S-shaped curves of either logistic or Gompertz form, respectively, with the latter curve giving a slightly better fit to the data presented here. The second approach, presented by the Alberta Oil and Gas Conservation Board(3,4) uses cumulative gas reserves tabulated by years since discovery and analyzes the growth pattern of the appreciation of existing gas reserves. This method does not predict an ultimate initial established marketable gas reserves, but does provide a very good fit on a cumulative basis of the appreciation of existing reserves.
This paper is aimed at statistically analyzing the way estimates of natural gas reserves grow. The model used for the analysis is referred to as a three-dimensional model because it is a function of three factors - the calendar year, the year since discovery and the amount of reserves known at these times. Alberta Oil and Gas Conservation Report data(3) used in this study are shown in Table 1. The Table shows) by year since discovery and by calendar year, the recognized reserves of some 400 natural gas pools discovered subsequent to 1950 which have initial reserves greater than 10 billion cubic feet. In total, it is estimated that these pools represent 72 per cent of the total reserves that have been recognized as being discovered prior to December 30, I970.

GENERAL STRUCTURE OF THE MODEL

Appreciation of Existing Reserves
Once given the amount of gas discovery in any one particular year (t), the appreciation of this gas is a very regular process which slows down exponentially with time and hence the cumulative growth has the form of a limited exponential of the following form.
(Equation Available In Full Paper)
Applying this model to the data presented in Table 1 for the years of discovery 1951 to 1960, the following results were obtained by non-linear least-squares techniques.
(Equation Available In Full Paper)
As can be seen from the above results, each individual model as well as the cumulative model provides a good description of the data.
A Laboratory Investigation of the Enriched Gas Displacement Process In Vertical Models
Authors: Alonso M. , Morineau Y. , Simandoux P. , Bradshaw A.D. , Bennion D.W. 
Published: March 2010

Abstract
The object of this study was to understand the enriched gas displacement process that is being applied in several kigh-relief carbonate reservoirs in Alberta. There is not yet sufficient field production history to determine the mechanisms affecting their performance. Therefore it is necessary to use laboratory data to show how the process works and the manner in which the various mixing zones develop and grow. Two programs were developed to study this phenomenon. The first was to define the behaviour of a simple three-component fluid system. The other was to use a multicomponent system in actual reservoir carbonate rocks performing the displacements at field pressure, temperature and rates.
These experiments indicate that the solvent is not directly miscible with the oil but rather acts to change the composition of the oil. This change iscaused by the solvent contacting the oil and coming into thermodynamic equilibrium with it, forming two phases (liquid and gas). The velocity of the gas phase is greater than the liquid phase; hence, it moves ahead contacting new oil and coming into equilibrium with it. This exchange takes place until the gas at the front is in equilibrium with the original oil.
These experiments showed that three zones develop. First there will be a zone having the composition of the original reservoir oil. The secondwill be a two-phase zone. This will be followed by a zone in which only a gaseous phase is flowing.
The utility of these experiments is only to explain the displacement mechanism. The sizing of the solvent bank and recovery prediction must be made by numerical simulation.

INTRODUCTION
MISCIBLE FLOODING of a petroleum reservoir is defined as a displacement process which- has zero interfacial tension between the displaced and displacing fluids. There are two types of miscibility.Direct miscibility, where the two fluids form a single phase on first contact with each other.Conditional miscibility, where the fluids are not miscible on first contact but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchange of components, the system becomesmiscible.
In summary, there are three general types of miscible displacements in active field use:
LPG solvent, which is directly miscible with the reservoir oil; high-pressure gas, which is conditionally miscible with the reservoir oil; and enriched gas, which is conditionally miscible with the reservoir oil.
Figure 1 is a constant pressure temperature pseudo-ternary diagram which is not thermodynamically rigorous but can be used to represent these three processes. The ternary representation is composed of four regions. The size and shape of these areas are determined by the dewpoint and bubble-point curves of the particular fluids being studied. Region A is a single-phase gas area, B contains two phases, C is a single-phase liquid area and region D is a single-phase fluid area.
Stability of Crude Oil-in-Water Enlulsions
Authors: Chen E.C. 
Published: March 2010

Abstract
A coulter counter was used to measure the droplet-size distribution of crude oil-in-water emulsion. The stability of the emulsion was determines by the decrease in oil concentration and the change in specific surface with time. All experiments core carried out at room temperature with initial oil to water volume ratios of 0.005 and 0.01. Six different types of crude oil were investigated. All of them behave similarly. Creaming was found to be pre-dominantly responsible for the instability of the emulsions. However, all the emulsion finally attained stability with an oil concentration or between 10−2 and 10−3 % volume, a specific surface of around 3 × 10 cm2/g and a droplet size belong 4 μm.

Introduction
WHEN CRUDE OIL SPILLS onto the surface of water, it spreads out into a layer the thickness of which depends on material properties and environmental conditions. Unless the spillage has been close to shore or the water is exceptionally calm, two types of emulsions will likely be formed(1) The oil-in-water emulsion, having droplets of oil dispersed in the water phase, is caused by the action of currents, wind, tides and waves and may be rendered stable by such hydrophilic groups a. - COO-, - OH, - CHO, - OSO3 and SO H which occur naturally in the crude. The water-in-oil emulsion consisting of droplets of water enclosed in sheaths of oil, is stabilized by the presence of various resinous and asphaltic materials which also occur naturally in crudes. The latter type of emulsion now generally referred to as "chocolate mousse", is known to be extremely stable(2,3). However, knowledge of the stability of the former, which is a useful input in assessing the effects of an oil spill has not yet been reported. The present work investigates the stability of crude oil-in-water emulsions by making use of a Coulter counter.

Experimental
Materials: Six different types of crude oil were used in this investigation. Their origin and physical properties are given in Table 1. The water was deionized, distilled and filtered twice using a Gel man membrane filter with a pore size of 0.2 μm. A 3% sodium chloride solution also filtered twice with the Gelman filte, was used as the diluent for the Emulsion and, at the same time served as the electrolyte solution for the Coulter counter. All the glassware employed was thoroughly washed and rinsed with filtered water. Traces of oil remaining in the glassware due to a previous experiment were removed by benzene and hot water.
Preparation of Emulsions: The crude (oil-in-water Emulsions were prepared using a Virtis 45 homogenizer as follows. The homogenizer falsely was first filled with 200 ml of water the crude oil was then pipetted in and the mixture was homogenized for 10 minutes at the medium speed (approximately 10,000 rpm). The emulsion as immediately transferred into a cylindrical separatory funnel and samples were withdrawn from the bottom at selected time intervals.
Computer Control of High-Pressure Sour Gas Wells, Kaybob South BHL Gas Unit No: 3
Authors: Kernaghan F.K. 
Published: March 2010

Abstract
This paper describes the computer- controlled supervisory and control system which was installed to measure and control production tram and injection into the gas wells of the Kaybob South Beaverhill Lake Gas Unit No. 3. Items to be covered include: reasons for installation of an automation, scheme in this field, initial configuration of the system, field installation and start-up, changes that have been made and an assessment of the systems performance after one year of operation.

Introduction
THE KAYBOB SOUTH BEAVERHILL LAKE GAS UNIT No. 3 is located approximately 130 miles west of Edmonton. The plant, which is one of the largest gas plants in North America, is located centrally in the 12- by 6-mile field. The terrain in this area is heavily wooded and has high relief, with ground elevations ranging from 2600 to 4150 feet above sea level.
Temperatures at the Kaybob plant range from -50 °F in the inter to +80 °F in the summer. Precipitation averages 75 inches of snow in the winter and 30 inches of rain in the summer.
The plant was designed for an inlet rate of 445 MMcf/D of very rich, sour gas, yielding a daily output of 3,065 long tons of elemental sulphur, 32,720 barrels of pentanes plus, 17,950 barrels of LPG's and 284 MMcf of dry residue gas. Of the residue gas, 54 MMcf is sold and the remaining 230 MMcf is re-injected into the formation in a recycling scheme designed to enhance the recovery of pentanes plus and sulphur.
Prior to plant start-up, the well count was 37 producing wells, 11 injection wells and one well that could be used as either an injector or a producer. The effluent from the producing wells is carried as two-phase flow through lateralpipelines to one of the three-trunk lines feeding the plant. These gathering lines operate at pressures of 1200 to 1500 psig and temperatures of 90 °F to 150 °F. At these conditions, the liquid hydrocarbon ratio is as high as 150 barrels per MMcf of gas.
The residue gas from the plant to the reinjection wells is carried in a three-trunk line to lateral sy.3terns operating- at a maximum discharge pressure of 4700 psig at the plant.

Reasons for Automation At Kaybob South
Operating problems within the gas plant make frequent cuts in plant inlet rate necessary. This could be accomplished by reducing the producing flow rates or diverting part of the inlet gas to flare. If consideration is given to pollution of the environment and conservation of energy resources, it is obvious that flaring of inlet gas is not acceptable.
A method of reducing well flow rates that is used by many gas plants is to increase the, back pressure that the plant exerts on the gathering system. Two-phase flow in pipelines installed in hilly terrain produces liquid heads wherever the flow is uphill. The amount of liquid build-up increases as the flow rate is reduced, up to the point at which the liquid starts to move as a slug.
The Influence of Freezing-Thawing On the Stability of Crude Oil-in-Water Emulsions
Authors: Chen E.C. 
Published: March 2010

Abstract
The effect of freezing-thawing on the stability of crude oil-in-water emulsions was studied. Four different types of crude at three freezing temperatures were investigated. The experimental methods were the same as those used in a previous investigation. It has been found that freezing-thawing causes an increase in the droplet size and lowers the oil-drop concentration in the emulsion.

INTRODUCTION
THE STABILITY of crude oil-in-water emulsions was the subject of a previous investigation(J). It has been found that crude oil and water form fairly stable oil-in- water emulsions if sufficient mixing energy is available. This means that when crude oil spills on water, a persistent oil-in-water emulsion may form due to the actions of currents, tides and waves. If the spillage occurs on an arctic water, where the temperature is above freezing point in daytime and below freezing during the night, the emulsion will then be subjected to freezing and thawing cycles. What is the fate of this emulsion? Will it behave differently from the emulsions not subjected to freezing and thawing? The present work attempts to obtain some answers to these questions.

Experimental
The experimental methods employed were the same as those used in the previous investigation(l), except that a Model T Coulter counter was used instead of the Model Z. The ''Model T is capable of counting simultaneously the number of droplets at 15 selected size ranges and thus completing an analysis within a few seconds. A 50-pm aperture tube was used and droplets down to 1 pm in size were counted.
Four different crudes, two from the Northwest Territories and two from Alberta, were investigated. The physical properties of the crudes are given in Table 1. The properties of Crude No, 3 are said to be close to those of the Prudhoe Bay crude.
Identical crude oil-in-water emulsions were prepared with an initial volume ratio (oil to water) of 0.05 and stored in wide-mouth, 16-ounce glass bottles. One sample was kept at room temperature throughout the period of the experiments, Other samples were allowed to stand at room temperature for one day and then were subjected to one or two freezing-thawing cycles. Freezing was carried out by placing the emulsions in a Revco Freezer for one day at −5, −15 find −40°C, respectively. Temperatures of the emulsion during freezing was recorded continuously by means of a probe which was placed centrally in the bottle.
(Figure in full paper)
The freezing took place as follows; the emulsion was first supercooled to a temperature T5 (T5 was about – 12, −8, −11 and −4ºC for Crude No. I, 2, 3 and 4, respectively) and began to solidify (at this point, the temperature rose suddenly to 0º C). The frozen emulsion remained at its freezing point, 0ºC, for several hours before it cooled down gradually to the temperature of the surroundings. It should be noted that at −5ºC, only the Crude No. 4 emulsion was frozen. Thawing was allowed to proceed at room temperature.
Design of Pipelines For Multiphase (Gas-Condensate) Flow
Authors: Gregory G.A. , Aziz K. 
Published: March 2010

Abstract
Problems peculiar to the design of multiphase (gas-liquid) pipelines are discussed using a multiphase-flow pipeline design program- A number of design methods currently used by the petroleum industry are compared in detail, with partieu1u"r reference to pipelines transporting natural gas – condensate mixtures. It is demonstrated that large differences in "predicted pressure drop may be obtained with different methods.

INTRODUCTION
IN SPITE OF THE FACT that many principles of single phase pipe flow also govern the pipe flow of gas liquid mixtures, in general, the design problem for the latter is unique. Because of complex interactions between the fluid phases, neither a rigorous analytical approach nor conventional single-phase flow correlations can usually be applied with much success. In this paper, some of the problems peculiar to two-phase flow are identified and pressure-drop predictions by a number of design methods currently used in the petroleum industry are compared for a typical gas-condensate pipeline.

Design Considerations For Two-Phase Flow
A number of characteristics of two-phase flow pose special problems for the pipeline designer that are not encountered with single-phase flow. These are discussed in detail in the book by Govier and Aziz(1) and will only be dealt with briefly here.

FLOW PATTERN
Depending on the relative gas and liquid flow rates, two-phase flow may exist as anything from a continuous gas phase with finely dispersed liquid droplets to a continuous liquid phase with finely dispersed gas bubbles. A number of well-defined flow patterns exist which result, in some cases, from the domination of buoyancy forces and, in others, from the domination of shear forces. It has been demonstrated by Mandhane et al.(4) and Gregory et al.(2) that the accuracy of most of the available friction-pressure-drop or in-situ-liquid- volume-fraction correlations can depend on the flow regime. It is thus important that the designer be able to predict the expected flow pattern from readily available information before performing his pressure-drop calculations. A number of correlations for doing this are available in the literature, including one recently proposed by Mandhane et al(J)

LIQUID HOLDUP
Almost invariably, the gas and liquid phases travel through a pipe at different velocities. This gives rise to a liquid holdup effect, because the fraction of the pipe volume occupied by the liquid phase under flowing conditions will be significantly different from the volume fraction of the liquid in the two-phase mixture entering the pipe. The total pressure losses for a two- phase mixture generally include a hydrostatic-bead contribution, which is calculated using a mixture density. Thus, the designer must be able to predict the in-situ liquid volume fraction under flowing conditions, as this is directly related to the mixture density. Numerous correlations are available in the literature for this purpose and, as noted above, these correlations may be more accurate for some flow regimes than others.