bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prospects Of Eor Techniques In Saskatchewan Oil Reservoirs
Authors: Ali S.M. Farouq 
Published: March 2010

Abstract
The heavy oil deposits of the Lloydminster area of Alberta and Saskatchewan represent a vast resource (3.5 billion m3 or 20 billion barrels) of great importance to Canada. Unlike the oil sands of Alberta, these oils are mobile at reservoir conditions, and thus more easily recoverable. However, these pose problems of their own: the reservoir quality is inferior the oil recovery technology is yet to be proven for the great majority of the fields, and as yet facilities for upgrading of the produced oil are non-existent. It is believed that variations of steam injection and wet in-situ combustion and immiscible carbon dioxide flooding will help produce a sizable fraction of heavy oil in Saskatchewan. However, a great deal of laboratory research and field-testing will be needed in order to double the present heavy oil production over the next ten years, which was the goal set in 1980. Development of enhanced oil recovery is a slow process, which cannot be speeded up simply by infusion of capital. It is clear that the present pace of EOR activity in Saskatchewan, while encouraging, is too slow to meet Saskatchewan Energy and Mines' (SEM) 1982 projections.

Introduction
The heavy oil deposits of the Lloydminster area have an everincreasing importance in Canada's energy picture. The inplace oil is estimated at about 3.5 million m3 (20 million barrels) – possibly three times as much. Unlike the oil sands of Alberta, the oil in these reservoirs is mobile at the prevailing conditions. The primary recovery is 5% to 10% of the in-place oil, with an additional few per cent by waterflooding. As a result, unlike the oil sands of Alberta, fluid injectivity and productivity and inter-well communication are not problems in the Lloydminster reservoirs. In recent years, both the success in the Lloydminster pilots and the limited success in the oil sands projects have served to underscore the importance of the Lloydminster deposits. It is certain that with increased field activity and laboratory research, very large volumes of oil can be produced from these reservoirs. Canada's conventional oil reserves are about 1.2 million m3 (8 billion barrels); the current oil production is about 200 000 m3/day, while the consumption is 260 000 m3/day. The impact on the Canadian economy is about $12 billion per year – some three times the actual cost of the imported oil. The Lloydminster heavy oil is playing a vital role in reducing this deficit.

General Features of the Lloydminster Reservoirs
Numerous fine papers by Vigrass(1) and others have discussed the geology and the basic characteristics of the Lloydminster area reservoirs. These reservoirs are usually small in size, and have been described as "islands of sand in a sea of shale". The oil gravity varies from a high of 22 – 23 API (Wainwright, Taber W) to 14 – 16 API (Bonnyville) to 9 API (Onion Lake). The in-place oil viscosity varies from 150 to 4000 mPa.s, with 2000 average. The oil saturation is usually very high about 80% and the porosity is 35%.
Skin Factor And Flow Efficiency In Wells Producing Under Solution Gas Drive
Authors: Nind T.E.W. 
Published: March 2010

Abstract
It is argued that the skin factor is an inappropriate measure of damage around the well bore for wells producing from solution gas drive reservoirs in which the pressure has fallen below the bubble point. This is because the value of the skin factor is influenced by the high gas saturations close to the well which lead to reduced effective permeabilities to oil.
The curvature exhibited by the inflow performance relationships of Vogel and Fetkovich is a reflection of the increased gas saturations in the vicinity of a producing well so that a value of flow efficiency, based on a comparison of actual performance with the "type-curve" IPR, should give a truer measure of skin damage than that given by the skin factor.
Formulas are presented which enable the value of the flow efficiency to be determined from a two-point rate/ flowing RHP test together with knowledge of the static pressure at the well in question. An estimate of the production rate increase, resulting from remedial work to improve the flow efficiency of a particular well, is readily obtainable.

Introduction
In many producing wells the value of the formation's permeability close to the well bore is different from its value further back in the reservoir. There are several possible reasons for this: well completion techniques, for example, may result in formation damage due to the mechanical disturbance of the sand grains, or to the invasion of the pores by mud filtrate, or to resistance to flow created by a gravel pack or by inadequate casing perforation techniques. On the other hand, bullet perforation of the casing and cement may create channels around the well bore that improve the effective permeability, while acidization or fracturing jobs are designed to improve that permeability.
When production takes place at a flowing BHP that is below the bubble point, the presence of free gas in the pressure sink centred on the well reduces the ease with which oil flows in this region, that is, alters the effective permeabilities.
It is useful in the field to have a method for determining the extent to which the average permeability around the well bore differs from that of the formation in order to assess and improve completion practices and to judge the necessity for and the profitability of possible remedial work at some stage in a well's life-perhaps an acid wash, an oil backflush, or a reperforation.

Skin Factor
The most commonly used measure of the degree of damage around the well is the skin factor, the value of which is routinely determined as part of a pressure build-up survey. Referring to Figures 1 and 2, and using standard symbols, a dimensionless number S is defined by
Equations (available in full paper)
Of the various factors appearing in Eq. 4 some uncertainty surrounds the value of (k/ µ), although this may be determined with reasonable accuracy from m (Eq. 3) provided that the formation thickness, h, can be adequately defined;
Miscible Flood - Field Facility Design
Authors: Verma K. , Giesbrecht Peter 
Published: March 2010

ABSTRACT
This paper summarizes the design, selection, installation and operationalaspects of hydrocarbon miscible flood field facilities. Field facilitiesdiscussed include solvent and gas, fresh and produced water injectionpipelines, double block and bleed system, and injection wellhead. The pipingdesign for high-pressure injection system is described to explain the economicsof selection of high-grade pipe.
In a cyclic miscible injection system, hydrate formation is the mainoperational problem. This paper presents the rationale for selection of theunique design of double block and bleed system. The simplicity of this designhas reduced operating costs. The techniques involved in switching the cyclesfrom solvent injection to water and vice versa are described.
Field facilities pressure testing has always been an outstanding question, especially for miscible injection lines. Water, gas and methanol as test mediaare evaluated.

Introduction
With the increase in the number of enhanced recovery projects, it is helpfulfor all operators to have benefit of the experience obtained to date in orderthat future projects may proceed as smoothly as possible. The design, installation and operational techniques mainly focus on South Swan Hills Unit(SSHU) and Nipisi Gilwood Unit No.1 (NGU) hydrocarbon miscible flood fieldfacilities.
The South Swan Hills Unit as shown in Figure 1 is located approximately 225km (140 mi) northwest of Edmonton. There are currently 188 producing wells, 16produced water injectors and 48 miscible injectors. During 1984, the averagedaily oil production was 3 620 m3 (22 770 BBL), Nipisi Gilwood Unit No.1 is approximately 273 km (170 mi) northwest of Edmonton (Fig. 1). There are120 producing wells, 32 produced water injectors and 6 solvent injectors. Theaverage daily oil production for 1984 was 6 000 m3 (37 740 BBL).
The major design areas of miscible flood field facilities are:
Other field systems such as fluid gathering, automation and injection welldownhole equipment are equally important, but are not addressed in thispaper.
Production Loans: One Bank's Approach
Authors: Tomilson G.A. 
Published: March 2010

Introduction
Once upon a lime lending to the oil and gas business was straightforward. Prices for oil and gas were low and expectations were that they would remain that way. Producers were told how much oil each well could produce through the provincial allowable system and there were a limited number of purchasers. The gas marketing situation was stable and there were only a handful of gas purchasers. Loans to oil companies were usually made based on proven producing assets which were often secured by Section 82 assignments.
The financial and regulatory environment has changed significantly since that time. So has the way loans are made. The way of taking security is catching up. We have moved from a straightforward lending environment where there were a handful of larger oil companies to one which is qui[e different where there are a multitude of oil companies, many with unique financing needs.
The taking of security must parallel the style of loan analysis. Loan analysis can either be on a total corporate basis or on an individual project basis. Security can either be taken on the company as a whole or on a group of individual properties. In the former case, the underlying assumption is that the company will continue operations (i.e. it will continue to own and operate existing assets and that it will continue to develop new assets). In the latter case, the underlying assumption is that the bank could realize on its security, should the need arise, and sell these assets to a third party to effect payout.

Lending Environment
Let us take a trip down memory lane and see how the lending environment has changed over the past 10 to 15 years.
Prior to the early 1970s, major oil companies controlledproduction and held large inventories which were used primarily to stabilize international oil markets and prices. During the past 10 to 15 years, governments in many producing countries took control of production. Today, major integrated companies hold inventories primarily for their day to day operations and are not in a position to materially influence markets and prices. Low inventories at the consuming end have led to price instability and volatility. The price for oil has declined significantly since December 1985 and it is difficult today to project the future price of oil with any degree of certainty, a complexity which was not previously thought to be here.
Within Canada, many rules under which oil companies operate have been changed over the past 10 to 15 years. In the mid-1970s:Crown royalties were increased from a flat rate in Alberta to a sliding scale rate with a maximum Crown royalty being almost 45%;Crown royalties were made non-deductible for calculation of income tax, thus moving forward the tax horizon for nontaxable companies; andthe Resource Allowance was introduced to partially compensate for the disallowance of Crown royalties for income tax purposes.
The industry adjustment to these changes were made easier by the ever increasing price of oil in the mid-to-late 1970s.
Discussion Of Analytical Miscible Relative Permeability Curves And Their Usage With Compositional And Pseudo-Miscible Simulators
Authors: Mungan N. 
Published: March 2010

Abstract
M. S. Jankovic (July-August 1986, JCPT, pages 55–65) is to be complimented for providing us with simple, analytical expressions for the solvent and oil miscible relative permeabilities and the relative permeability ratio. It should be emphasized that these equations are applicable to two-phase miscible flow only. There are times and situations when even in a miscible flood this condition may not prevail and hence these equations may not apply well. Consider the multiple contact miscible, enriched gas injection process: Around injection wells, miscibility often does not exist for a certain distance because there has not yet been sufficient contact and mass transfer between the injected solvent and the reservoir oil to have developed the miscibility. Within some distance around production wells on the other hand, miscibility may be lost depending on the pressure drawdown. The relative permeabilities of these immiscible, multiphase flow regions often control such things as injectivity, gas / oil and solvent / oil production rates, albeit the flood may be miscible in the bulk of the reservoir.
I note that the solvent-oil relative permeability ratios given in Figure 8 by the author to describe the multiple contact rich gas drive process of Metcalfe et al.(1) are slightly different from those given in the original paper. There are differences between the two sets around a solvent saturation of 10 per cent for cases 2 and 3. Were the data from the original curves inadvertently truncated or purposely dropped because they did not fit the straight line MRPR relationship proposed by the author? I rather think the latter is the case since in very low solvent saturation zones miscibility may not have existed.
Finally, the author states that in Equation (5) the oil saturation So can be replaced by the liquid saturation SL. This is correct if and only if other fluids present, be it gas or liquid, are immobile. In a number of Alberta reservoirs the solvent flood will be allowed to displace previously water flooded zones where water mobility, along with that of the oil and solvent, will occur. Also, in the alternating water / gas process, simultaneous gas/water/solvent mobility may exist. In such situations the use of MRPR may not be all that rigorous.
An Analysis Of Two-Phase Flow In Inclined Pipes With Zero Net Liquid Production
Authors: Kokal S. , Stanislav J.F. 
Published: March 2010

Abstract
A two-phase gas-liquid flow in upward inclined pipes with zero net liquid production is considered. The models of slug and stratified flow regimes are proposed for predicting the pressure drop. Estimated values of pressure loss compare well with the experimental results obtained with 26 mm and 51 mm pipes at angles of inclination of + 1 degree, + 5 degrees and + 9.2 degrees.

Introduction
Transportation of hydrocarbon mixtures by pipelines has been recently gaining in importance as Canada begins an era of increasing dependence on production from offshore fields. Although the commercial pipelines follow the terrain variations, most of the research endeavor has been focused on horizontal and vertical flow.
The subject of this study is to investigate a special case of the gas-liquid flow in upward inclined pipes: a case of zero net liquid production.
Such a situation may occur under any of the following conditions:pipeline is shutdown and a hydrocarbon mixture is cooled below its bubble point;liquid to gas ratio is very low; andliquid slug is introduced into the pipeline as a "kick " from a gas well.
In all these cases fluid accumulates at the low sections of a pipeline. After the start-up some of the liquid is sheared off by the flowing gas and the remaining liquid circulates in the uphill pipeline section resulting in a zero net liquid flow rate. The liquid presence significantly affects the pressure drop in a pipeline initially designed for gas flow only.
The main goal of this investigation is to describe the physics of the problem to the extent [hat the pressure drop could be correctly determined in design calculation.

Model Development
Gregory et al. (1981) conducted an experimental study on systems featured with zero net liquid production. The intermittent flow pattern was observed at superficial gas velocities up to 2 m/s. At higher rates fluid stratification occurred. Due to the zero liquid flow rate no comparison with existing flow maps is possible. Any step increase in gas velocity was accompanied by a corresponding decrease in liquid holdup.

Intermittent Flow
Over the past two decades a considerable amount of research has been done on intermittent flow in horizontal pipes. A major contribution was made by Dukler and Hubbard (1975) who proposed a semi-empirical model for slug flow. A major drawback of the model is the fact that quantities such as slug frequency and gas holdup in liquid slugs cannot be predicted from the first principles. Later on, Nicholson et al. (1978) modified this model. Recently attempts have been made to close the model: Barnea et al. (1983) suggested a method of predicting the slug holdup, and Maron et al. (1982) described the slug characteristics in terms of the boundary layer theory.
Difficulties of the gas liquid slug flow modelling may be appreciated by inspecting Figure 1 which show the schematics of this flow pattern together with the symbols used in the mathematical description.
Rise Of Interfering Steam Chambers
Authors: Butler R.M. 
Published: March 2010

Abstract
An approximate expression has been developed which predicts the rate at which asteam chamber will rise in a reservoir. It is assumed that the steam chamberrises at a constant rate which is determined by the ability of steam to flowinto the advancing steam fingers and for the oil to drain down from aroundthem.
The predicted velocities are proportional to the reservoir permeability and arestrongly dependent upon the steam temperature and oil viscosity.
Calculated curves predict steam chamber rise rates which varyfrom 0.004 m/dayfor Athabasca bitumen heated by steam at 100 °C, to 0.19 m/day for Lloydminstercrude with steam at 300 °C.
An interesting feature of the theory is that fingers of different sizes rise ata rate which is independent of their size, i.e. small fingers rise at the samerate as large ones. The size of the fingers is inversely proportional to thepermeability.
Using reasonable assumed relative permeabilities, the theory predictsvelocities which are in line with those reported by Closmann and Smith for afield experiment in Athabasca.

Introduction
In the thermal recovery of bitumen and heavy oils using steam, it frequentlyhappens that a steam saturated zone, the steam chamber, rises through thereservoir with oil draining counter currently. The rate at which this upwarddisplacement can occur is of considerable interest because it affects theperformance of many steam recovery projects.
This paper contains a theoretical analysis of the process which predicts therate at which displacement occurs.

Mechanism
The nature of the flows occurring during steam chamber rise is depicted in Figure 1. The rectangular boundary in this figure is assumed to rise at aconstant velocity through the reservoir.
Flowing downward through the top of the boundary is the cold-saturatedreservoir material together with its fluid contents; the velocity is the risevelocity of the chamber. Steam flows upward through the lower boundary. Thisprovides the heat to raise the reservoir and its contents to steamtemperature.
Heated materials leave through the lower boundary as a number of identifiablestreams. The reservoir rock and residual oil leave at the velocity of rise ofthe chamber, The flowing hot oil and condensate leave at higher velocitiesbecause they have a downward velocity relative to the hot rock and residualoil. Also, the entering steam moves at a higher velocity than the chamber inorder to pass through the lower boundary.
At the very top of the chamber steam fingers move into the relatively coldreservoir. Heat is transferred from these fingers to the reservoir material byconduction and the oil drains downward around and between the fingers as itbecomes mobile. At this point, substantial temperature gradients exist in themobile oil and the average oil temperature is below that of the steam. This isimportant as the rate at which the process can proceed is determined by therelative mobility of the oil to that of the steam.
Gravity is moving the oil downward and allowing the steam to rise.
Energy In Nova Scotia - The Next 100 Years
Authors: Laffin J.J. 
Published: March 2010

Introduction
It is often said that forecasting the future is fraught with danger and when the period is 100 years hence the waters are indeed treacherous. Nevertheless the exercise can be interesting in that it forces one to identify and understand the various factors that act upon the dependent variable. In the case of forecasting future energy supply and demand patterns the factors are usually large and act as precursors to change in these patterns. Therefore, it is useful to do some investigation of the past in order to determine what these forces have been and the impact they have had on energy markets. Because Nova Scotia has, by and large, shared the energy-related developments of Western society, a brief history of those developments is in order.

Historical Summary
Let us begin with the industrial revolution of the late 1700s and the technological revolution which followed it, 100 years later. For it was the magnificent advances of these two ages which have led to the wholesale reorganization of Western society into the cities and commercial networks of today and in turn the energy use patterns during the waning years of the 20th century.
The transition in our society from a largely rural, agrarian existence of the Middle Ages to the cosmopolitan lifestyles of today would have been impossible without the advances made in new applications of energy. Inventions, such as the steam engine, the internal combustion motor and the electric light bulb, facilitated the new processes and the movement of goods and services that were to drive the industrial and technological eras.
Developments on the energy supply side were able to keep pace with these new applications and thus hastened their adoption. The extraction, refining and transportation of petroleum opened up phenominal growth in the use of that resource worldwide. Breakthroughs in the generation and distribution of hydro electricity led to its integration by all segments of our society. The ease of application and convenience made these two fuels leading forms of energy, beginning in the early 1900s, replacing such fuels as wood and coal.
Although our social and economic development was interrupted somewhat by the depression and Second World War, the early 1950s heralded the resurgence of progress in Western society. Economic expansion on a broad front, heightened expectations of a growing middle class, and changing tastes led to the era of the consumer society which affected the consumption pattern of not only energy but many other products as well. Affordable prices, ample supplies and convenience led to a growth in energy demand that doubled almost every ten years.
The rapid changes that occurred in so many aspects of our lives during the 50s and 60s were not without their costs. Pollution from industrial processes, depletion of resources and social discontent were all symptoms of the expansion that had gone on before. For the first time, beginning in the late sixties, the very foundations of our technological I industrial society were being brought into question.