bluuebunny/crossref_metadata_2025 huggingface dataset:
Texaco''s Expanded Bonnie Glen Solution Gas Processing And NGL Fractionation Facilities
Authors: Eastlick B.K.
Published: March 2010

Introduction

When Texaco Canada Resources Ltd. opened the $40 million addition to its Bonnie Glen gas processing facHities in June 1982, the three-plant complex located 80 km southwest of Edmonton, became one of Canada's largest natural gas liquids producers. The new Bonnie Glen Solution Plant No.2 can handle 1.4 million cubic metres of gas a day, including a 2780 cubic metre a day fractionation train. The new solution gas processing plant was completed on time and on budget under an engineering, procurement and construction turnkey contract.

The Oilfields

Texaco's Bonnie Glen complex serves two of Canada's most prolific oilfields, Wizard Lake and Bonnie Glen, discovered within a year of each other in the early 1950s.

The Wizard Lake oilfield, about 11 km north of the Bonnie Glen Gas Plant, has an original oil-in-place of 61.2 million cubic metres and has been under pressure maintenance since 1969. The Wizard Lake Miscible Flood is one of the largest and most successful enhanced recovery projects of its type in the world. The project increased the field's recoverable oil by 11 million cubic metres to an estimated 84% of the original oil-in-place. Over the years, some 4.4 million cubic metres of LPG solvent has been injected into its miscible slug. The field, 100% owned by Texaco, can produce up to 8700 cubic metres of oil per day.

The Bonnie Glen find differed from Wizard Lake because it had an original primary gas cap overlying the 119 million cubic metres of oil-in-place. This pool, 74% Texaco owned, is not under pressure maintenance. However, ultimate recovery is still expected to be 71% of the original oil-in-place with a production capability of 1300 cubic metres a day. In 1975, the gas cap was unitized and a cycling scheme was brought on-line which has successfully minimized retrograde losses and improved ultimate pool recovery by 4.3 million cubic metres.

The Processing Complex

The Bonnie Glen gas processing complex today includes three facilities: two solution gas plants, Nos. 1 and 2, each with a 1.4 million cubic-metre-a-day capacity and a cycle plant which has a 3.9 million cubic-metre-a-day capacity to extract natural gas liquids as part of the gas cap cycling project (Fig. 1).

The original Bonnie Glen Solution Plant No. 1 came into operation in 1954 with the capacity to handle 790 000 cubic metres of gas a day. It was one of the first gas plants built in Alberta, installed at that time for conservation purposes. Plant No.1 had five integral compressors, a mine sweetening and ambient temperature lean oil absorption systems and a fractionation facility.

By 1969, the plant's rated capacity was increased to 1.4 million cubic metres a day through a series of improvements which included the addition of compression, a propane refrigerated gas fractionator downstream of the lean oil absorber and a second depropanizer. Then as now, Plant No.1 extracted more NGL than it could fractionate. The excess raw NGL formed one of the solvent streams injected in the Wizard Lake Miscible Flood.
The Development Of CNG As A Vehicular Fuel
Authors: Buchanan J.J.
Published: March 2010

Introduction

The development of compressed natural gas (CNG) as a vehicular fuel is leading toward new markets for natural gas.

It takes two things to develop a new market successfully. One is product suitability —your product must be able to do the thing you are claiming it can do. The second is market acceptability —people have to be convinced that they want, and can obtain, that product. The development of CNG as a vehicular fuel will depend on the successful combination of these two elements.

Product Suitability

Let me start with the suitability of the product itself for this intended use. We are now in a time when, because of the rising price of gasoline, a number of other fuels are being proposed as alternatives for vehicular use. Each has its place in the over-all search for ways to reduce Canada's dependence on oil. However, the only fuel suitable for any mass conversion away from gasoline is natural gas.

Four factors combine to make it very suitable —supply; cost to the end-user; the inherent properties of the fuel; and the technology for its application.

Supply

First, supply. Canada has an overwhelmingly abundant supply of natural gas. For the last several years, we have been adding over 5 TCF per year to our proven reserves of natural gas. In 1980, we used 1.6 TCF domestically and exported an additional 1.8 TCF to the U.S., leaving us with a net addition to surplus of about 2.7 TCF. Given markets and reasonable returns to the producer, we can continue to add another 5 TCF a year to our proven reserves-indeed, by 1990, with contributions from the frontier areas, a more realistic figure would be 8 to 9 TCF. Yet by that same date, according to National Energy Board estimates, our domestic market will need less than 3 TCF-even taking into account increased demand following completion of the proposed pipeline to the Maritimes. It is estimated that 0.1 TCF would provide enough natural gas to fuel 500,000 vehicles for a year.

There is a second point to be made about supply. It is one thing to have a reserve of a given natural resource-it is another thing to be able to distribute it economically to the customer. In other words, supply is a matter of both availability and deliverability. CNG also passes the deliverability lest very handsomely.

Natural gas rises up out of the ground. passes through a gas processing plant (usually located right at the field), goes via transmission lines to major distribution networks and is piped directly into homes and commercial enterprises. As most service stations throughout this land already have natural gas lines into the premises, the addition of CNG to their product range requires only one further step: compression. The delivery system is already in place.

Cost

The second of the four factors under the heading of suitability is the cost to the end-user. The cost of CNG to fuel a vehicle for a given distance is only about one half that of gasoline.
Corporate Barter —The Business Of The Eighties
Authors: Sanderson A.
Published: March 2010

OLD FASHIONED and impractical as it may seem, in a world said to be profoundly technological and endlessly complex, barter sounds less efficient than the use of cash and it is. However, barter or counter trade has returned from a state of near non-existence in the early 1970s to a revitalized concept amounting to several billion dollars annually.

All modern economics are based on the ideas that the direct exchange of goods and services is too cumbersome and restrictive. Hence the use of money.

At first, money worked well. Its value was the direct consequence of productive effort and with it the artisan could make his products and would not have to wait until someone came along with some food stuffs to ply his trade. Throughout history, governments have controlled money and have tried to use it to make an unearned value. At first rulers would shave the edges off coins to make up the unearned value. Governments more recently have tried to print more currency to solve their economic problems, and have met with disastrous results.

Governments, whether they be communist or capitalist, control the supply of money rather than have money produced as a consequence of productive effort. Currencies therefore have become deflated and are not precisely redeemable for anything concrete.

Countries and companies still use cash as the major medium of exchange, but more and more commodities: from oil to land, wheat to gold are becoming the real "hard" currencies, everywhere rising in value while the value of paper monies steadily decreases.

With the deflation of currencies, and the scarcity of international liquidity, barter has become one of the fastest growing segments of today's business community. The Wall Street Journal reports that 65% of the manufacturing companies listed on the New York Stock Exchange barter as standard business practice. In fact, barter has shown an astonishing growth from approximately 2% of world trade in 1978 to an estimated 20% in 1982.

As banks continue to cut back on their lending to eastern European and developing countries, many countries have turned to barter to conserve cash reserves. Romania, for example, brought barter back dramatically in 1980 with a law saying all trade must be on a barter basis. Poland is using its own barter system to survive a collapsing currency and Mexico is now trading oil to the United States in exchange for products and technology.

Finland has the top growth rate of western countries of the Organization for Economic Co-operation and Development. Counter trade with the Soviet Union is cited as one of the keys to their success. Finns exchange high quality manufactured goods and services for much needed oil. The trade agreement has kept Finnish factories productive while the rest of Europe has slowed.

Major corporations, that at one time would not even consider barter, are now finding it an essential part of their business and are forming counter trade divisions to handle this growing market.

General Electric, the United States" largest exporter, set up its counter trade department in 1979.
Will Reversion Of Deep Rights Lead To A Resurgence In Exploration In Alberta?
Authors: Holubowich F.J.
Published: March 2010

THE CROWN in right of the Province of Alberta, owns the minerals in approximately 80% of the lands in the province. Up to July 1, 1976, when the governing legislation was changed, the holder of a Crown petroleum lease was entitled to rights from the surface to the centre of the earth. Most of the producing fields in the province had been discovered over the 23-year period since the discovery of Leduc on February 13, 1947. Thus the deeper rights were sheltered by relatively shallow productive geologic zones held by relatively few oil and gas companies under leases granted to them for terms of ten or 21 years. Because the legislation then in effect did not compel a lessee to explore all potential geologic formations underlying his lease, the deeper formations tended to remain dormant. The lessee was usually content to produce the shallower zones rather than accepting joint-venture or farm-in proposals from other companies wishing to explore the deeper zones. Under the rules in effect until July 1, 1976, the lessee knew that the shallow producing zones would ensure retention of all rights.

In the large producing fields with deeper zone potential, Pembina for example, the major oil companies, as lessees, diverted their exploration in the late 1960's away from Alberta to the frontier areas, particularly the Arctic. Alberta activities tended to be restricted to development of oil and gas from proven fields. Their departure from Alberta led to an explosion in the formation of many new, but small, Canadian companies who were eager to carry out exploration for oil and gas in the province but could not always get a piece of the action.

The need for amending the Act to provide for a more open land tenure system became increasingly apparent as Alberta entered the 1970s. Departmental officials were besieged with verbal complaints from the smaller companies seeking drastic changes in the legislation to provide for a more rapid turnover of unexplored Crown petroleum and natural gas rights. And these complaints grew in number with the growth of the number of companies.

In the summer of 1973, shortly after assuming his position as Deputy Minister of the Department of Mines and Minerals, as it was then called, Dr. G. B. Mellon commissioned Seaton-Jordan and Associates to study the existing land tenure system. The resulting report triggered a complete review of Part 5 of the Mines and Minerals Act dealing with Crown petroleum and natural gas rights. Initially, only the senior officials in the Department were involved in developing new concepts, but ultimately the Land Committees of both the Canadian Petroleum Association (CPA) and the Independent Petroleum Association of Canada (IPAC) were invited to provide input.

The initial reaction from the CPA, representing the major oil and gas companies, was negative. CPA favoured retention of the existing tenure system as it would continue to preserve the preeminence of the majors in the Alberta scheme of things.
Long March II
Authors: Wong James F.
Published: March 2010

Introduction

In October, 1934, Mao Tse-Tung led his armies on a 6,000-mile march across China. This gruelling one-year trek known as "The Long March" crossed 18mountain ranges and 24 rivers and was one of the heroic events in China'smodern history that culminated in her liberation on October 1, 1949.

Another trek is now taking place in China - Long March II - the arduousjourney to industrial growth and economic prosperity. And, leadinginternational corporations and businessmen are joining in on Long March II.

China is surviving the current world recession well. Where other countriesare foundering under enormous debt loads, China remains virtually debt free.Intensely competitive foreign suppliers of goods and services are beating apath to her doors thus ensuring a huge storehouse of products at bargainprices.

"China is a tough market" say both experienced and novice China watchers andtraders. And yet, the hotels of Beijing (Peking) are crammed with businessmen, year round, all hoping to close deals with this stirring giant. Think of onebillion people in an area slightly smaller than Canada, all eager for theimplementation of policies to improve their standard of living. The growingawareness and demands of one-quarter of the world's population for food, shelter and consumer goods is staggering.

Directly related to the desire for an improved standard of living is thedemand for energy and China's ability to develop her energy resources in stepwith this growing demand. Over the next 20 years, a World Bank study estimates China will spend $420 to $480 billion to develop its energy infrastructureincluding offshore petroleum exploration and production, onshore enhancedrecovery, oil and gas pipelines, coal mining facilities and hydro-electric andnuclear power stations.
The Esso Caisson-Retained Island Data Acquisition System
Authors: Der C.Y.
Published: March 2010

In the fall of 1983, Esso Resources Canada Limited will construct a Caisson-Retained Isiand (CRI) at Kadluk 0–07 in the Beaufort Sea. Upon completion of this new island, a $2 million instrumentation system developed by the Esso Research Department will be put into operation to gather environmental and performance data.

Approximately 300 sensors will monitor the island's structural and geotechnical responses to the environmental forces. These sensors will be connected to a network of data acquisition subsystems controlled by three distributed computers. The data collected will be used to add to the safety of operations on the island. It will also allow Esso to optimize the design of future Beaufort Sea offshore structures, and will extend our insight into the environmental conditions in this area.

Background

Esso Resources Canada Limited has been very active in Beaufort Sea exploration for more than a decade4 During this time, Esso has pioneered the design and construction of sacrificial-beach, artificial islands (eighteen to date). Recently the lack of local (Western Beaufort) sources of fill materials having good soil propeties, and the poor economics of long haul distances have directed Esso's ongoing research toward alternative artificial·island technologies. This led to the development of Esso's first Caisson-Retained Island (CRI).

Figure I shows the complete ring of linked, steel caissons which will form the outer perimeter of the island. The ring is made up of eight caissons each weighing approximately 50,000 kN (5000 tons) when fully ballasted. The caisson ring is set down on a prepared subsea foundation (berm) and the interior of the ring is filled with dredged sand. This type of island has the advantage of requiring significantly less sand fill as compared to sacrificial-beach islands. In addition, the caisson ring can be disconnected and moved to other locations for re-use.

Simultaneously with the design and construction effort of the CRI, the Esso Research Department designed an extensive $2 million instrumentation system for the island. This system is currently in its final development stage and will be operational by the fall of 1983 when the CRI is installed at its first location. The entire instrumentation program for the CRI is expected to require a commitment of eight to ten man-years over the next three years.

The requirement for an instrumentation system was identified early in the CRI project to accomplish the following:ADD to the safety of island operations;OPTIMIZE the design of future caissons, or other Arctic structures; andSUPPORT Arctic research studies using the caisson island as an observation platform:

To achieve these objectives, the system was designed to collect data on key environmental and CRI performance parameters, such as:local and, global ice forces;ice sheet and rubble movements;geotechnical forces and" movements;caisson stress and movement;wind and current velocities; andwave heights.
Financing Oil, Gas And Coal Projects
Authors: Peterson R.B.
Published: March 2010

THE GOOD NEWS is that recovery, albert slow, is underway in the Canadian petroleum industry.

Earnings at last are starting to recover. Indeed, the percentage increases from the disastrous levels of the last few years are impressive. They are going to look big in the headlines-and that could be the bad news.

It's a fact of life that Canadians are distrustful of profits-especially those made by oil companies. So our industry should be prepared. It won"t be easy to gel attention (at least until those headlines on profits appear) because Canadians are no longer interested in energy issues. They want attention focused on matters they consider far more critical-the worst unemployment levels since the Depression.

When I make these statements about public attitudes, I am Quoting research reports by some of the best people in the survey business. They tell us Canadians now have little or no worry of Canada suffering future energy shortages. They tell us Canadians still see multi-national companies taking huge profits out of the country, with little or no benefit to Canadians in terms of investment and jobs.

So we have our work cut out for us. We must show skeptical Canadians that they have a false sense of energy security. Despite the current glut at the gasoline pumps, the fact of the matter is that our country is running short or conventional reserves of oil: the present reserve life is about 12 years. Industry is only able La replace 15 per cent of the oil that's being withdrawn from conventional reserves each year.

So where can we turn? Either we continue to increase imports of oil from unstable sources-whose own reserves are also depleting. Or else we turn to the Arctic and the Atlantic, those Canadian Frontiers which have been very stubborn about releasing their secrets, and to the Alberta oil sands.

That's the energy side of its current sources of oil are depleting; we have to develop new ones. And that brings me to the profits.

One encouraging aspect of the research on Canadian attitudes is finding that the people recognize the petroleum industry as a potential major contributor to national economic recovery. They also want Industry to be permitted to "get on with the job."

What's needed to "get on with the job"? The answer is in just three words: restore investor confidence. Investors must see acceptable" returns on prior investment before they"ll seriously consider future investments.

In recent years, earnings in our industry have provided a return as low as one per cent on capital assets. So much for those huge profits! You could do at least 15 Limes better by pulling money in Canada Savings Bonds. To finance the minimal expansion which it was undertaken, the industry has had to borrow heavily.

But at last, things are improving. Governments have begun to realize that they had tried to share in too much, too fast, and they are easing off. Industry is also working very hard to increase efficiency and productivity.
A Mechanism For Initiation of Bitumen Displacement From Oil Sand
Authors: Takamura Koichi , Chow Ross S.
Published: March 2010

According to an oil sand structure recently proposed in this laboratory, connate water in high-grade oil sand appears in at least two types of configurations: as pendular rings at grain-to- grain contact paints, and as a roughly 10 nm thick film which covers the sand surface.

The aqueous film exists due to the double layer repulsive forces between the bitumen and sand surfaces. The study has now been extended to include a theoretical model regarding the separation of bitumen from oil sand aggregates immersed ill aqueous solutions. The model describes the displacement mechanism in terms of the capillary forces at the bitumen/aqueous interface, the viscous drag of the bitumen and the stability of the aqueous film on the sand surfaces. The model successfully explains the observed results of the crumble test;a high rate of crumbling on an oil sand pellet was observed in a NaOH solution, but the presence of Ca++ caused a dramatic decrease in the effect of NaOH. The theory was further confirmed by a microscopic disintegration experiment. Here the bitumen displacement from individual sand grains was observed and video-recorded under a high resolution optical microscope.

Introduction

The previous paper(l) dealt with an accurate description of the microscopic structure of in-situ Athabasca oil Sand; especially the manner In which connate water and bitumen are distributed in the void space between the sand grains.

In-situ, the sand grains occupy roughly 65% of the total volume. In the case of high-grade oil sand, the pore space is filled with bitumen and water. The water occupies between 10 and 15% of the pore volume and forms pendular rings at the contact points between the sand grains. These pendular rings (bulk aqueous phase) cover roughly 30% of the sand surface and the remaining 70% of the surface is covered by a thin film of water (film aqueous phase), which connects the bulk aqueous phase. The thickness of this aqueous film is of the order of 10 nm. In lower-grade oil sand, clusters of fine particles exist within the framework formed by the coarse sand grains. These clusters of fine particles are saturated with water. Thus the amount of connate water in oil sand increases linearly with increasing fines content. The main features of the structural model of the Athabasca oil sand described above are schematically shown in Figure 1.

Theoretical considerations demonstrated that the aqueous film has been held in place throughout geological times due to the double layer repulsive forces between the negatively charged sand and bitumen surfaces. Recently, similar analysis was also reported by A.C. Hall et al(2,3). It has long been recognized that the presence of the aqueous film is the single most characteristic and fortunate feature of the Athabasca oil sands(4,7). Without this aqueous film or the hydrophilic nature of the sand, the hot water extraction process of bitumen would not work. The above model provides good grounds for the existence of this aqueous film.
Development Status Of The Taciuk Oil Sands Processor
Authors: Taciuk W.
Published: March 2010

The Taciuk Direct Thermal Processor has been under research and development since late 1974 in Calgary, Alberta, Canada. This work has been carried out by the UMATAC Industrial Processes Division of Underwood McLellan Limited, Consulting Engineers, under funding agreements with the Alberta Oil Sands Technology and Research Authority (AOSTRA).

Original research work and small-scale testing was completed by 1977 when a financing agreement for pilot plant construction and testing was signed with AOSTRA. Under this agreement a pilot plant was constructed in 1977-78, and has been operating for a period of 6 years using the following feed stocks:Athabasca Oil Sandslow grade - 6% oil contentmedium low grade - 9% oil contentaverage grade - 11–13% oil contenthigh grade - + 13% oil contentU.S. Semi Consolidated Sand-Shale low grade - 6–8% oil contentHeavy Oil from Lloydminster FieldHeavy Oil Atmospheric Tower Bottoms from Local Refineries.

During 1981 and 1982 the pilot plant was operated on heavy oil and oil sands to provide confirmation data, and oil product samples for detailed oil analysis which resulted in hydrotreating requirement projections.

During 1983 UMATAC has completed the design and cost estimates for a 100 ton/ hour demonstration plant to be located in the Fort McMurray area. UMATAC has also completed the conceptual design and cost estimates associated with use of the process in a commercial oil sandplant with an output of approximately 115,000 barrels of synthetic crude per calendar day.

Processor Description

The Taciuk Processor consists of a horizontal rotating vessel containing compartments which house individual process steps. Figure 1 schematically shows the arrangement and process flows. As-mined oil sand feed is introduced into the preheating section of the processor where connate water is evaporated as steam, frozen material is ablated, oversize is removed and the oil sand is heated by heat exchange with the hot outgoing tailings sand. The heated oil sand is then transported into the reactionzone where it is mixed with hot combusted sand from the combustion zone. The resulting temperature is adequate to thermally crack the hydrocarbons yielding a vapour stream containing the cracking reaction gases and liquids (in vapour form), and a coke residue coating on the sand. The vapour stream is passed through cyclones to remove fine solids and then enters a fractionating tower where various liquid fractions are separated for further processing. The off-gases are then passed to a central gas processing plant for light end recovery and desulphurization.

The coke-coated sand dicharges into the combustion zone where preheated air is injected to burn most of the coke. Auxiliary burners provide heat for startup and trim control. The hot sand from the combustion zone passes through arecycling arrangement that ensures an adequate supply of heat to the reaction zone while allowing net sand to move Into the cooling zone. In this zone the sand and combustion gases are cooled by heat exchange with the incoming oil sand.
Leduc, A New Life At 38
Authors: Barfoot G.L. , Rodgers R.J. , Scarth B.R.
Published: March 2010

Discovery of oil in well Imperial Leduc No.2 on May 10, 1947, marked not only a long-awaited success for Imperial Oil Limited in western Canada, but also provided a major impetus for the subsequent explosive growth of the Alberta petroleum industry.

Unique among its Devonian neighbours on the active Cooking Lake Aquifer, the Leduc D-3A Pool had a thin, areally-extensive oil leg, and a large gas cap. Balancing the thinning oil zone between the gas cap and aquifer has been an unrelenting challenge of reservoir management. Reducing the oil zone from its original 11.6 metres to 1.5 metres has been a 37-year success story. However, the operator is about to lose the upper hand.

Two years of appraisal and planning have focussed on the future of the remaining hydrocarbon reserve. This paper summarizes the past and present of the Leduc pool, and looks futuristically toward the day of final depletion.

Introduction

The Leduc D-3A Pool is located 20 kilometres southwest of Edmonton (Fig. 1). Discovered in May 1947, It is one of a series of reef structures located on the Rimbey-Meadowbrook geologic trend which extends some 480 kilometres in a southwest-northeast direction across central Alberta. Leduc is located on the southern portion of the trend, which also includes the major hydrocarbon-bearing pools of Homeglen Rimbey. Westerose South, Westerose, Bonnie Glen, Wizard Lake, Glen Park, Acheson, Big Lake and St. Albert (Fig. 2). All pools receive strong pressure support from the Cooking Lake Aquifer.

Based on geological data, the Leduc D-3A Pool is divided into three distinct areas (Fig. 3):the Main Pool, the focus of this paper;the Saddle Area; andthe Southeast Extension

The three areas of the Leduc D-3A Pool originally contained die hydrocarbon accumulations shown in Table 1. Since discovery, 63 per cent of the 50.4 × 106m3 of original oil-in-place, or 98 per cent of estimated reserves have been recovered from the Main Pool. At present, it is estimated that a thin 1.5 metre oil leg remains.

While the challenge of managing oil production from a thin oil sandwich has been successful, the continually diminishing oil zone and near-depletion of reserves necessitates planning and executing the next phase of Main Pool depletion-a rapid gas cap production, commonly referred to as a blowdown.

This paper familiarizes the reader with the past and present of the Leduc D-3A Pool, and provides forward-looking insight into the reservoir at times referred to as the genesis of the Canadian oil industry.

Reservoir Geology

General

The Leduc D-3A Pool is one of the many Devonian reefs (Fig.2) enclosed in basinal shales of the Ireton and Duvernay Formations that grew upon the extensive Cooking Lake carbonate platform (Fig. 4). Fluids derived from compaction of the adjacent basinal sediments are thought to be the source of the dolomitization of all the bioherms or pools along the chain, as well as the western margin of the Cooking Lake platform.
Geology, Geophysics And El1Lgineering: A Case For Synergism
Authors: Gretener Peter E.
Published: March 2010

Introduction

My prediction (Table 1) has been previously published in "The Wavelet", the newsletter of the geophysics group at The Department of Geology and Geophysics of The University of Calgary.

To make predictions that range ten or more years ahead is quite obviously risky. This article is an expression of my personal bias, so the readership is cautioned to treat the content as a base for further debate. Most recently, to the consternation of many, crystal balls have proved murky. Economic and political experts, much like weather forecasters, cannot be trusted with predictions that extend beyond a year. There is no reason to believe that long-range technical or scientific predictions are less fragile. As one famous scientist (his name escapes me) once stated: "One cannot predict the future but one can explore its possibilities". It is hoped that this will prove to be a reasonable exploration.

With this caveat firmly in mind, let us establish that all three professional groups are dealing with rocks and their fluid contents. Initially, these three operated independently with a competitive spirit that often bordered on hostility. Today geology and geophysics have been united. Any geological or geophysical meeting bears testimony to that fact. To deny it, only proves that one has acquired the status of a fossil before physical death.

It is my view that geologists and geophysicists must close ranks with the engineers and abolish the current state of separation which is being perpetuated by both sides. Geology and geophysics schools gear their curricula toward the exploration for natural resources, whereas engineers consider exploitation as their exclusive domain. There is no doubt that resource exploitation requires solid engineering knowledge yet one must remember that this phase also involves rocks and for their fluid contents, and this is where geologists and geophysicists can and should fit in. Now that the term "Ultimate Recovery" equally applicable to oil production and hard rock mining-assumes a new importance, particularly in North America; all three can only benefit from cooperation. The intent is, of course, not to make an engineer out of a geologist or vice versa, but rather to upgrade each other's knowledge in the respective fields to the point where a meaningful dialogue becomes possible.

One is now tempted to carry this paper further with an arm-waving campaign in favour of the interdisciplinary dialogue-another buzzword of our days-but I prefer to illustrate my point with a specific example. I choose artificial well fracturing to demonstrate how both geologists and engineers can benefit from such studies, with a direct applicability to both pure and applied science.

Some readers may think I have chosen a very special subject and might be hard pressed to find another example. To set such suspicions at rest, an equally good case could be made for the concept of effective stress. Terzaghi introduced this idea into soil mechanics in 1923 (see Skempton, 1960).
Shacks, People And Petroleum
Authors: Finch David A.
Published: March 2010

Tents, shacks and small houses served as the first living quarters in Turner Valley Heat, water, sanitarian, business, leisure, entertainment and crime were to develop in due course. But at first it was a lot like an extended campout.

Dingman No. 1 made the Valley famous in 1914. The closest town was Black Diamond, a farming community centre. Even by 1924 when the spectacular Royalite NO.4 well blew in, only a few buildings existed at the present site of the town of Turner Valley.

A panorama photograph, one of those mind-bending photos that looks south at one end and north at the other, shows only a few buildings near those famous wells in 1925.

Seventeen derricks or well heads dot the panorama view. Sam Coultis lived on the hill which became known as Snob Hill across the river and southeast from the plant. Just below the riverbank sat the houses of his workmen. Each day they walked across a foot bridge to the small plant.

A school, some company offices and warehouses, a few homes near the wells where the men were employed and the famous flare in the coulee called Hell's Half Acre complete the picture. This was the beginning of the boomtime for Turner Valley.

Housing at first consisted of tents. As the permanence of the oilfield became obvious, some people built houses but many just lived in tar paper shacks. That is, tar paper was the only covering on the small frame buildings, built on skids, that were hauled from one work site to the next.

Some shacks eventually got a protective coat of siding but still, they were small. One lady commented that the cars were bigger than the houses so that the cars could pull the houses around.

Full sized houses were built for the plant management at the top of Snob Hill. Other people rented or bought land but many just squatted, with no thought or care for a title, until they moved to the next worksite. The only settlement to survive the years since the 1920s was Black Diamond. Even there many of the houses had come from many other communities before settling down for good.

Heat was an important commodity when you lived in a tar paper shack, years before insulation or central heating. Most buildings were heated with waste gas from anyone of the numerous nearby wells.

Seldom did the gas cost much, if anything, but the unscrubbed fuel exacted other payments. First it just plain stank. A high sulphur content made the valley smell like rotten eggs when the gas was burned. Next the pressure was highly unpredictable. One lady boasted she could cook a turkey in 20 minutes when the pressure was up to 220 pounds per square inch. Another lady died when her house blew up after a gas leak filled her house with gas.

Not only did the gas smell. One story says that when the vicar was coming for tea the silver tea service was highly polished and then covered carefully to keep it bright.
New Technology For Cold Lake
Authors: Whelan W.J.
Published: March 2010

Carlyle Energy Ltd. became involved in 1981 when the U.S. owners of the technology were attempting to raise funds in Canada for a heavy oil pilot project.

Cold Lake Heavy Oil Ltd. (CLHO) was formed: 45% by Carlyle (55% of the voting control) and 55% by three parties in the U.S. who own and developed the technology. Carlyle commissioned studies by A.J. Gruy & Associates, Inc. of Dallas and McCallum, Stewart and Associates in Calgary to study and review the material available relative to the application of the process to Cold Lake type reservoirs. A pilot project was beyond their financial resources so time was spent interesting others in CLHO.

In late 1982 and early in 1983, AOSTRA financed a laboratory study of the technology by the Alberta Research Council. Their recommendation was that a field pilot project be undertaken.

CLHO was able to negotiate a staged farm-in of the Gulf lease and Bow Valley Industries Ltd. agreed to participate and operate Phase A of the pilot project. The technology, if successful, will greatly enhance the recovery of these heavy oils.

Project

Bow Valley Industries Ltd. and CLHO (a 45% subsidiary of Carlyle Energy Ltd.) has initiated Phase A of an in-situ oil sands bitumen recovery project located approximately 30 km north of Grand Centre, Alberta. The project known as the "ABC Cold Lake Pilot" involves three participants, AOSTRA (Alberta Oil Sands Technology and Research Authority), BVI (Bow Valley Industries Ltd.), and CLHO.

The pilot project is located on a BVI / CLHO farm-in from Gulf Canada Resources (Heavy Oil Lease 84) and covers approximately 5,000 hectares (12,500 acres) bordering on the north-west shore of Cold Lake. The location is 16 km east of Esso's Marie Lake project.

Total expenditures in Phase A will be approximately $15,000,000 over the next two years. Capital costs for 1984 will be $7,000,000, with the remaining funds being operating expenses for the next one and a half years. All costs will be shared 75 per cent by AOSTRA and 25 per cent by BVI.

To date, seven directional wells have been drilled in a hexagonal configuration from a central pad. Steam injection and well satellite facilities were installed during late August and September. Steam and carbon dioxide injection was scheduled to commence in late September.

Over 85 per cent of capital costs represent Canadian material and tabor, the majority of which will be expended in Alberta. Drilling, equipment, fabrication and installation have been awarded to local contractors in the Cold Lake area.

A field office at the pilot site has been opened and will employ 12 full time staff and contract personnel to conduct the project, the majority of whom are presently area residents. Bitumen produced by the project will be trucked to L1oydminister. Phase A of the project will evaluate a new technology, which relies upon the use of superheated steam, carbon dioxide and other additives to recover bitumen from the Clearwater formation at a depth of about 1,400 feet (430 m).
Canadian Natural Gas Export Policies And Prospects
Authors: Angevine G.E.
Published: March 2010

Introduction

Over the past 15 years Canada has exported over 13 Tcf [13.6 EJ (exajoules)] of natural gas to the United States but gas exports have been running considerably below authorized levels since 1979. If U.S. gas demand increases, with little change in the gas reserves-to-production ratio (Fig. 1), exports of Canadian gas will probably regain and surpass their earlier levels. The compatibility of gas export pricing rules with those for gas consumed domestically will continue to challenge Canadian government policy.

Canadian Gas Reserves

Remaining non-frontier established Canadian gas reserves at the end of 1982 were about 84 EJ. National Energy Board procedure limits "remaining reserves" to those with demonstrated viable delivery systems.

Very significant quantities of "tight" gas (in place) (as high as 400 EJ) are known to exist in the "Deep Basin" of western Canada. They are also excluded even though a portion may be contiguous to conventional, producible, gas reserves.

An improved market situation, in terms of both price and volume as U.S. requirements for Canadian gas accelerate, should elicit 44 to 50 EJ of conventional gas in the next 15years with an expected concentration in the late 19805 and early 1990s.

Table 1 breaks out total reserves of gas. Frontier resources are expected to be drawn on as the more accessible non-frontier reserves are depleted. Canada's combined ultimate potential may be as much as 6 times greater than currently established non-frontier reserves of 84 EJ.

Domestic Natural Gas Consumption

Figure 2 projects trends in Canadian oil, natural gas and electricity shares of secondary energy demand (i.e. energy commodities sought by energy users for consumption as energy by them) to the year 2000. Total annual energy demand growth is expected to continue slower than growth of Real Domestic Product over the balance of this decade as conservation measures contribute to further decline in the energy-output ratio. By the 19905, the effects of the price shocks of the early 19805 should have been absorbed. Barring further major price disruptions, energy demand will begin to track output growth more closely.

Both natural gas and electricity shares of the Canadian energy market will almost certainly increase. Most of the increase in the gas portion will come from the penetration of new markets-in Quebec, if the Trans Quebec and Maritimes Pipeline makes natural gas available to regions east of Montreal; in Saskatchewan, due to expansion of the distribution system in rural areas; in the Maritime Provinces, as Sable Island gas comes on stream; and in British Columbia, through possible extension of the natural gas pipeline system to Vancouver Island.

By the year 2000, natural gas is anticipated to supply about one-third of the needs of the Canadian energy market compared with 27.5 per cent in 1983 and 20 per cent in 1970. Domestic gas requirements will then be about 2.8 EJ, compared with the current level of about 1.8 EJ.
Enhanced Oil Recovery Design For The Pembina Cardium Field
Authors: O'keefe J.J. , Boutette M.J. , Howes B.J.
Published: March 2010

The design of a hydrocarbon miscible flood is presented for areas of file Pembina Cardium field where there is little or noonglomerate present. A procedure for describing the reservoir for use in simulation is also discussed.

The indicated optimum miscible flood design is to infill drill to 8-hectare well spacing and to inject at a solvent-water ratio of 2.5. A solvent slug size in the range of 10% HCPV, followed by about 20% HCPV of chase gas, is recommended.

Introduction

The Pembina Cardium oilfield is located 120 kilometres southwest of Edmonton, as shown in Figure I, and is the largest oilfield in Canada, covering an area of 1900 square kilometres. It has an original oil-in-place (OOIP) of 1.2 billion cubic metres and approximately 70% of the reservoir is being water flooded. The average water flood recovery is about 23%(1). This low recovery and high OOIP combine to make the Pembina Cardium reservoir a significant target for enhanced oil recovery.

A study was undertaken to identify areas favourable for miscible flood implementation, to analyze their potential and the parameters which control miscible flood performance, to determine the most favourable conditions, and to evaluate the resulting economics.

This paper describes the design of an enhanced recovery scheme suitable for the parts of the Pembina Cardium field that have little or no conglomerate present. It includes the description or the reservoir for use in simulation and the evaluation of various factors in the operation of the proposed EOR scheme.

Nature of the Reservoir

The Cardium formation in the Pembina area has been divided into four zones(2), as shown in Figure 2. Zone 1, at the top of the section, is a conglomerate which varies in thickness and reservoir quality. Its permeability can vary from 1 mD in thin deposits to more than 1 Darcy in thick, well-developed areas. Zone 2, a sandstone, is one of the two main producing zones. It is present in the central and eastern parts of the field. The third zone is a bioturbated sand-shale which is usually not productive. It isolates Zone 2 from Zone 4, which is the other main producing zone. Zone 4 is also a sandstone and ispresent in the west-central portion of the field. Figure 3 shows the areal extent of Zones 2 and 4.

Kerr(3) has correlated fluid properties with geology and has established the presence of two distinct fluid, a low bubble point oil in Zones 1 and 2 and a higher bubble point oil in Zone 4. The properties or these two oils, as used in this study, are shown in Table 1.

A directional flow trend, oriented southwest to northeast, has been described by McLeod(4) and Hassan(5). This trend may be the result of directional permeability within the reservoir rock or, more probably, may be the result of induced fractures oriented southwest to northeast. Virtually all of the Pembina Cardium wells are hydraulically fractured upon completion and fractures may also be induced as the result of injecting above formation parting pressure.
Carbon Dioxide For Enhanced Oil Recovery In Canada
Authors: McDonald S. , Mandybura F. , Sparks N.
Published: March 2010

major miscible so/vent in Canada and describes Shell Canada's carbon dioxide exploration efforts over the last few years. Enhanced oil recovery, specifically miscible flooding, has been recognized as a technically and economically feasible method for adding reserves and productive capacity to Canada's light and medium oil. The fiscal regime has been altered by both the federal and provincial governments to encourage miscible flooding development. As a result many projects have been initiated with others being evaluated and designed. This paper analyzes the history and the direction of miscible flooding in the United States, where carbon dioxide is becoming the predominant miscible solvent. The potential for future use of carbon dioxide in Canada is specifically addressed:potential oil recoverysolvent supply, andeconomics.

Shell's carbon dioxide exploration play currently underway is also discussed.

Introduction

Since the 1973 Arab oil embargo and subsequent rapid rise in oil price, oil self-sufficiency in Canada has been expressed as a national desire. Yet, since that time, yearly conventional oil production has not been replaced.

Figure 1 shows that domestic crude oil supply and demand are temporarily in approximate net balance, primarily due to the recent substantial reduction in the latter(1). Canadian demand is forecast to exceed production from established reserves and new discoveries by approximately 100,000 m3 per day (630,000 bbls/day) by the early 1990s. Canada must therefore turn to the non-conventional sources to achieve self-sufficiency.

This paper examines the contributions enhanced oil recovery (by miscible flooding) may be able to make in achieving oil self-sufficiency. An analysis of the history and future direction of miscible flooding in the United States, where the petroleum industry has changed from using light hydrocarbons to using carbon dioxide as the predominant solvent, is given. From these analyses carbon dioxide could emerge as the dominant solvent in Canada in the future.

Light and Medium Enhanced Oil Recovery Potential in Canada

Two-thirds of the original oil-in-place is usually left in the ground after conventional (water flood) recovery techniques have been applied. Miscible enhanced recovery processes involve the injection of a solvent such as carbon dioxide nitrogen or light hydrocarbons (ethane, propane and butane) to mobilize some of this remaining oil.

Miscible flooding has the potential to add 300 to 400 E6M3 (1.9 to 2.5 109 bbls) to Canada's remaining recoverable oil reserves. As shown in Figure 2 this reserve could increase Canada's remaining recoverable reserves by approximately 50% (2, 3, 4). This addition alone will not solve Canada's future oil shortage but can make a significant contribution toward the goal of eliminating reliance on imported crude oil. Miscible flooding in the United States has matured to a greater degree than in Canada. The United States experience and direction may give a strong indication of how the future will unfold in Canada.