bluuebunny/crossref_metadata_2025 huggingface dataset:
In-situ Recovery From the Athabasca Oil Sands - Past Experience and Future Potential
Authors: Redford D.A.
Published: March 2010

Despite 60 years of effort, the Athabasca oil sands deposit, the largest of the Canadian oil sand deposits, is the only deposit for which a promising in-situ recovery process has not been developed.

This paper reviews the many field pilots which have been attempted in this deposit, plus a number of pertinent pilots from related deposits. It then reviews the recovery processes put forward by a number of authors and sums up our current knowledge of this immense untapped Canadian resource and the state of our technology as related to its recovery, With this background in mind, the author gives his views on the state of the technology and indicates the most promising recovery processes for a number of different geological conditions found in the Athabasca deposit. The author concludes with a review of some of the key problem areas where progress must be made if commercial recovery is to occur.

Introduction

In 1930, Absher(1) wrote to his shareholders" I feel that we have overcome the technical difficulties and are able to produce (the Athabasca deposit) on a commercial basis". Absherwas the first to attempt to recover oil from the Athabasca bituminous sands by in-situ means. In the sixty years since his attempts and despite Absher's confidence to his shareholders and numerous subsequent attempts by others, the Athabasca deposit remains a formidable challenge. While commercial exploitation is occurring from the shallower parts of the deposit by surface mining, and promising in-situ methods have been developed for the Cold Lake and Peace River oil sands deposit and for the Grosmont carbonate deposits, the 90% of the thabasca deposit which is too deep for surface mining still remains a tempting motherlode just beyond our reach. This paper reviews the many field attempts which have been tried and some of the concepts which have been considered to unlock this immense resource. It also comments on our experience o date and indicates the author's views on some of the more promising technologies which warrant further testing.

Review of Athabasca Field Tests

The Bituminous Sand Extraction Co-Limited

During the period 1926 to 1931, Absher as the principal engineer for the Bituminous Sand Extraction Co-Limited, attempted in-situ recovery from the Athabasca deposit. His early work using steam and superheated steam was at very shallow depth (10 m to 15 m). but in 1926, he sank several wells to a depth of 100 m (overburden 55 m), and produced some bitumen using superheated steam. The following year, and for the next few years, more wells were completed in the area and a type of downhole steam generator or in-situ combustion was employed, however, no attempt was made to drive between wells, but rather to produce back to another part of the same well. Although some bitumen was produced and Absher was enthusiastic about the results, difficulties with overheating of the wells and loss of tubing and casings where never completely overcome. The advent of the great depression seems to have cut short this pioneering effort.
Effective Well Testing Is The Key To Planning Of Major New Developments Particularly In Remote Areas And Offshore Operations
Authors: Pearson R.M. , Adams D.M.
Published: March 2010

This paper discusses the merits of conducting production and injection tests in the context of frontier areas be they offshore, deep sour gas wells or discoveries in remote, hostile areas. A discussion is included of the data that needs to be collected and how the results affect development planning. To illustrate this, various field development case histories are referenced both in the North Sea and western Canada. Reservoir and production engineering well test design requirements are outlined and the methods for obtaining this data discussed. The case for multirate and extended tests are examined in the context of defining a cost-effective test program. The importance of obtaining adequate fluid samples is also discussed. Finally, an example of the mechanical equipment needed to achieve these requirements is presented for an offshore well test.

Introduction

As the oil and gas industry explores for future petroleum reserves in increasingly "frontier" areas, the need for adequately designed, conducted and analyzed well testing becomes even more important. Whether it is a sour gas plant in the Foothills or an offshore platform off the East Coast, a proper understanding of the reservoir and fluid properties is essential for cost-effective and efficient development planning. Having spent millions of dollars drilling a delineation well to prove-up the reserve, it is negligent to leave that well without establishing the basic data that will be required for planning the exploitation of the reserve. There are numerous cases where operators have had to re-enter or redrill a well or, worse still, have installed ill-designed facilities and proceeded with an uneconomic development as a result of inadequately planned, insufficiently long, poorly supervised or misinterpreted well tests.

At this stage it is important to note that one of the major differences, and perhaps the most important, between conventional and frontier hydrocarbon fields is that large capital investments have to be made for frontier field development based almost completely on exploration and delineation well data. This situation is also applicable albeit on a lesser scale to development of land fields in remote areas, such as western Canadian deep sour gas wells in the Foothills. While the conventional field development can be periodically updated in a staged manner using the latest drilling and production results, most frontier field developments require a commitment to spend the majority of funds long before any production history is available. Logically then, the data obtained from the exploration and delineation wells must be comprehensive and of the best quality possible.
Application Of Measurement While Drilling In A Shallow, Highly Deviated Drilling Program
Authors: Johancsik C.A. , Leraandd A.E. , Petovello B.G. , Gust D.A. , Smith B.W.
Published: March 2010

In choosing a survey system for a directional drilling project, consideration must be given to the production penalties associated with an off-target wellbore as well as to the simple comparison of survey costs. Wellbore position accuracy requirements for Esso Resources' Norman Wells Expansion Project Drilling Program have resulted in the choice of Measurement While Drilling (MWD) as the primary surveying system. The accuracy achieved at Norman Wells using an MWD system is the product of many factors. In addition to tool design and calibration, the operating and data check procedures are fundamental to achieving the required accuracy in the severe magnetic environment at Norman Wells.

Introduction

Scope of Norman Wells Drilling Program

Esso Resources Canada Limited is currently undertaking a major expansion project of the Norman Wells oil field. This field is located in the Northwest Territories on the Mackenzie River, 145 km south of the Arctic Circle (Fig. 1). The expansion project includes drilling approximately 162 wells between July 1982 and April 1985. The wells are drilled from mainland and natural island locations and from six artificial islands in the Mackenzie River (Fig. 2). Seventy-eight per cent of the project wells are directionally drilled to reach reservoir targets under the Mackenzie River. As of March 31, 1984, 100 of the wells have been drilled.

The unique circumstances at Norman Wells demand a sophisticated directional program. The wells are relatively shallow with true vertical depths to the top of the producing zone ranging from 335 m in the mainland area to 490 m at the downdip end of the reservoir. Horizontal displacements to targets extend up to 750 m from the surface locations. Small targets and the requirement for the wellbore to be as vertical as possible through the producing zone have required the use of S-curve well profiles with rapid build and drop rates.

Directional wells have been divided into three types (based on displacement) as illustrated in Figure 3. Type 1 wells have displacements less than 270 m, Type 2 wells range from 271 to 550 m and Type 3 wells reach targets up to 750 m from the surface locations. All directional wells are kicked off between 30 m and 50 m and angle is built at a programmed rate of 8 degrees/ 30 m. Maximum angles of 50 degrees, 60 degrees and 70 degrees to Well Types 1, 2 and 3 (respectively) are reached and held. The wells are then dropped into the targets at rates of 4 degrees/ 30 m. Figure 3 illustrates three wells that were drilled fromartificial island locations in early 1984.

Target Accuracy Requirements

The choice of a survey system to use for wells of this type is dictated largely by the requirement for accuracy. Accurate positioning of wellbores to hit the relatively small targets is important because of the particular nature of the Norman Wells reservoir. Hydrocarbons at Norman Wells are pooled in the Devonian limestone reef complex called the Kee Scarp.
Casing Running Considerations In Highly Deviated Wellbores
Authors: Jordan R.O.
Published: March 2010

This paper presents the results of a study that was carried out to improve production casing running times in highly deviated wellbores. Inadequate hole cleaning can be a major problem when drilling, casing and cementing high-angle wells. The mechanisms of hole cleaning are discussed, along with case histories from several wells. Recommended operating parameters are presented, as well as benefits that can be realized by following them.

Introduction

During the early phase of Esso Resources' Expansion Project at Norman Wells, unacceptably long production casing running times were experienced. On Type II, 60-degree, 810-metre wells, average casing running rates were 98.9 metres per hour with 12.7 metres per hour the minimum (Fig. 1). On Type III, 70-degree, 980 metre wells, the average running rate was 61.1 metres per hour with a minimum rate for one well of 10.6 metres per hour.

Initial attempts to reduce casing running times on similar wells included picking up drill collars to 'spud' the casing string. Another attempt involved a cathead-pulley-slip elevator arrangement to snub the casing into the wellbore. When these efforts produced no appreciable benefit, a thorough analysis was warranted. Because inadequate hole cleaning was suspected to be the problem, the study concentrated on this aspect. Case histories of 35-highangle wells and current research into cuttings transport in deviated wellbores were examined.

Casing Running Mechanism

With improper hole cleaning and cuttings carrying capacity, drill cuttings accumulate in a bed on the low side of the wellbore. When casing is run, it pushes the cuttings to the side or ahead as it goes (Fig. 2). This idea is supported in actual practice by the fact that upon reciprocation and working of the casing through tight spots, it would, almost without exception, return to at least its previous position. Although drag is considerable on a 60-degree well, a pure drag effect would not produce the same result, and hence was not considered the problem.

Cutting Transport in Directional Wells

The actual mechanism for cuttings transport in deviated wellbores has been the subject of several research projects(1, 2, 3). These studies have indicated that the most important factors affecting the carrying capacity of a drilling fluid include the hole angle, annular velocity, fluid viscosity, fluid density, cuttings feed rate or ROP, and annular geometry. Drillpipe eccentricity and rotation also have a minor impact. Under normal drilling and circulating conditions in a deviated well bore, a bed of cuttings forms on the low side of the hole (Fig. 3). The cuttings bed forms quite rapidly because the cuttings have such a short distance to fall, especially at higher angles. As the bed forms, the annular area is reduced and thus the velocity increases. The increased annular velocity improves cuttings transport. A steady state condition is achieved when the rate of cuttings dropped onto the bed equals the rate of cuttings picked up.
Simulation Of A Large Steam-CO Co-Injection Experiment
Authors: Stone T. , Malcolm J.D.
Published: March 2010

A high-pressure steam-CO2 co-injection experiment, carried out in a 1.5 m diameter physical simulator packed with Athabasca oil sand, is described. The experimental run lasted/or 113 hours and consisted of two injection-drawdown cycles. During the run, 1454 kg of steam and 75.3 kg of carbon dioxide were injected (equivalent to 2.1 mole % CO2 in the mixture). This resulted in the recovery of 12.5% o/the initial bitumen in the oil sand.

The experimental data obtained was compared to the results of a numerical modelling study. Good agreement was obtained. Differences between the numerical simulation and experiment are discussed.

Results from steam-only predictions are used to discuss the merits of the steam-CO2 injection process relative to steam injection alone.

Introduction

Many experiments have been carried out at Alberta Research Council (ARC) in the last five years to test the effectiveness of additives on recovery of Athabasca bitumen. An adequate numerical simulation capability is useful in analyzing these runs. This capability also serves as a design aid for further experiments as well as serving a need for idealized studies.

The experiment that was simulated for this report (hereafter denoted "Run 15006") was the first run in the 150 cm pressure vessel in which stearn and CO2 were simultaneously injected into an oil sand pack of this physical size. The primary objective was to study recovery benefits from addition of CO2 to the injection stream. Other objectives were to study the rate of advance of temperature profiles in the bed during the run and to provide data to test a numerical simulation of the steam-C02 process. A three component model developed at ARC was used to simulate the above process. The model is a fully implicit thermal numerical simulator with the capability of handling a single additive. Objectives of the numerical simulation were principally to test the numerical model, and hence all its property data for a CO2/water/bitumen system.

Description of Experiment

The 150cm diameter simulator system (Fig. 1) consists of a large pressure vessel (150 cm ID by 270 cm high) designed to allow steam and gas to be injected simultaneously into the test bed under controlled flow rates. Oil sand is packed into this vessel and maintained at field overburden conditions by introducing a nitrogen blanket at the top of the cell. Feed streams were injected to the centre of the test bed via an injection well.

The three main systems are schematically illustrated in Figure 1. These are the injection system, test cell and production system. The steam portion of the injection system consists of a high pressure steam generator followed by a superheater. Flow turbines measure flow rate after the superheater and are marked "F" in Figure 1. Thermocouples and pressure, gauges are also in place, marked "T" and "P" in Figure 1. The steam generator operates at a constant flow rate. Pressure to the system is regulated by a control valve upstream of the superheater.
A New Regime For The Frontier
Authors: Parsons Robert B.
Published: March 2010

It's a new ball game for the oil and gas industry in the frontier. On October 30, 1985, Energy Minister Pat Carney released a package of measures which will replace virtually all of the measures contained in the now defunct National Energy Program insofar as exploration, development and production in the frontier is concerned. No aspect of doing business in the frontier will escape untouched by the wide range oj proposals in the new regulatory framework.

Introduction

It has taken the present Federal government less than one year to demolish the former government's much loathed National Energy Program. As reported in the last edition of Tax Topics, the March 1985 Western Accord and subsequent Federal and Provincial budgets started the demolition process, virtually revamping all aspects of the NEP except for he rules applicable in the frontier. In ctober this year, Energy Minister Pat Carney drove the final nails into the NEP's coffin upon announcing a new set of incentives and tax and other regulatory provisions for operations in the frontier.

A 19-page paper entitled "Canada's Energy Frontier" describes the Federal government's aspirations, plans, and new rules and regulations for oil and gas in the frontier.

There seems to be unanimity in the oil patch that the complexion of such future operations will be notably different under the new regime.

Incentives

The proposed changes to the incentive system for exploration in the Canada Lands will probably have the most dramatic effect on the way of doing business in the frontier in the future.

Under the NEP's Petroleum Incentive Program (PIP), an enterprise with a minimum 75% Canadian ownership rating was entitled to cash grants equal to 80% of eligible exploration expenditures. A less than 50% Canadian owned entity could obtain cash PIP grants of 25% of exploration costs. This meant, for example, that the after-tax cost to a wholly Canadian owned corporation of exploring in the frontier was $.10 on the dollar, while the comparable after-tax cost to a non-Canadian corporation was $.37 1/2 on the dollar.

Two phenomena of the NEP era are clearly attributable to this cash grant system. First, the relatively cheap after tax cost of frontier exploration led to a remarkable shift in exploration spending rom the conventional provincial lands to the frontier. Second, the preferential treatment accorded Canadian ownership gave rise to some interesting bedmates, with non-Canadian owned multi-nationals entering into highly complex and convoluted arrangements with smaller Canadian owned concerns in order to optimize the utilization of PIP grants. Over-all, the result was considered by many to be a politically driven exploration business, as compared to a market driven one.

One of the evident goals of the proposed new incentive system is to restore the exploration decision-making process to the market. Under the new system, PIP grants will be replaced by a royalty and tax credit system.

The first $5 million of eligible exploration costs per well will be eligible for a 25% royalty credit.
Prospects Of Eor Techniques In Saskatchewan Oil Reservoirs
Authors: Ali S.M. Farouq
Published: March 2010

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

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

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

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

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

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

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

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.