bluuebunny/crossref_metadata_2025 huggingface dataset:
The Wizard Lake D-3A Pool Miscible Flood
Authors: Young Marshall N. , Martin W. Earl
Published: March 2010

A hydrocarbon miscible flood was initiated in the Wizard Lake D-3A pool in late 1969. The scheme involved placing a slug of LPG at the gas-oil interface, and displacing it vertically downward with dry gas while injecting water to stabilize the oil-water contact. Ultimate recovery is expected to be 323 million stock tank barrels, 84per cent of the original oil-in-place and 69 million stock tank barrels higher than under primary depletion.

The Wizard Lake D-3A pool, located in central Alberta, is one of nine Devonian reef pools connected to the Cooking Lake aquifer. It is a dolomitized bioherm reef with a maximum original oil zone of 648 feet. The pool was considered an ideal candidate for a miscible displacement process because of its vertical relief, small areal extent and the absence of any barriers that would be detrimental to displacement of the slug.

This paper reviews the implementation, monitoring techniques and performance of the miscible flood scheme.

Introduction

The Wizard Lake D-3A pool, located 55 kilometres (35 miles) southwest of Edmonton, as shown in Figure 1, was discovered in April 1951 with the drilling of Texaco Wizard Lake Crown 'B-I in 12-22-48-27-W4M. The pool, drilled on 4D-acre spacing, was fully delineated by the late nineteen fifties.

The reservoir is a dolomitized bioherm reef of Devonian age which is part of a prolific chain of Leduc member reefs appropriately known as the Golden Trend. The productive horizon attained a maximum recorded height of 197.5 metres (648 feet) above the Cooking Lake aquifer in which reef growth was initiated. The Cooking Lake aquifer pinches out to the west, but is extensive in the other three directions. This aquifer is very active and is common to other oil and gas accumulations which give rise to interference between pools (Figures 2 and 3).

The oil column covered an area of 1,507 hectares (3,725 acres) at the original oil-water contact of 1,230 metres subsea (4,034 feet subsea). Figure 4 presents a structure contour map of the top of the pool based on the gross reef section. The initial oil-in-place is estimated to be 61,200,000 m3 (385 MMSTB), with some 6.5 × 109 m3 (231 bcf) of solution gas dissolved in it.

The primary recovery mechanism, identified as a combination of gas expansion, water drive and gravity segregation, was allowed to continue until 1969, when a slug-type hydrocarbon miscible scheme was initiated (Fig. 5). In 1965, a secondary gas cap began to form and by the end of 1969 there existed a 24-metre (78-foot) gas column containing approximately 152 × 106 m3 (5.4 Bcf). Also, by 1969 the oil-water contact had risen by 15 metres (50 feet); leaving an relatively small quantity of available core and thus a method had to be developed to Overcome this shortcoming and also handle the edge effect on porosity that is characteristic of reef pools(1).
A Radial Model For Estimating Heat Distribution In Selective Electric Reservoir Heating
Authors: Harvey A. Herbert , Arnold M.D.
Published: March 2010

The Selective Electric Reservoir Heating process is designed to increase oil recovery by employing an alternating electric current to heat portions of the reservoir that are normally bypassed by injected fluid. A radial model is proposed for estimating the distribution of heating under somewhat idealized conditions, and a technique is suggested for estimating the percentage of current that is flowing in strata adjacent to the oil zone.

Introduction

We have been investigating the possibility of using an alternating electric current to heat portions of an oil reservoir that are normally bypassed by injected fluids(1,2). Canadian and U.S. patent applications are pending on the process.

Electric heating is accompanied by water injection, and the process is expected to increase oil recovery in a waterflood. In a pattern flood, the application of heat to parts of the pattern that are normally bypassed by injected fluids will usually improve the mobility ratio at the displacement front, because the viscosities of most crude oils are more temperature-sensitive than the viscosity of water.
Depletion Studies of Two Contrasting D-2 Reefs
Authors: Gillund G.N. , Patel C.
Published: March 2010

Introduction

The Nisku Band G pools are two West Pembina D-2 poolswith contrasting reservoir properties. Average porosity, permeability and maximum thickness are 5%, 130 mD and 95 metres, and 16.4%, 7100 mD and 19 metres respectively. Theresults of the depletion model studies of waterflooding andmiscible flooding and some of the problems that occured duringthese studies will be reviewed.

Introduction

The West Pembina play has resulted in the discovery in the past three years, of a series of reservoirs located some 120 km west-southwest of the city of Edmonton. A recent tally shows that some 40 pinnacle reef pools have been discovered with oil-in-place varying from 100,000 m3 to 5.75 × 106 m3. Many of the pools have shown very prolific production rates, with potentials of up to several hundred cubic metres per day. Amoco Canada has participated in a number of these discoveries. The two pools that will be described in this paper are of interest in that they illustrate the wide range of reservoir properties that have been encountered in these pools and the different approaches required in developing depletion methods suitable for them.

The two pools are the Bigoray Nisku Band G pools, located as shown in Figure 1.

Reservoir and Fluid Properties

Some data on the two pools are summarized in Table 1. As shown, the oil-in-place is 1.5 × 106 m3 and 0.75 × 106 m3 for the B and G pools, respectively. However, they exhibit a very wide range in reservoir properties. The thickness for the B pool is 95 m and that for the G pool is 19 m. The permeability shows an even greater contrast. The average permeability of the G pool is 7,100 mD, with some individual values in the 20- to 40-Darcy range. The average permeability of the B pool is 130 mD, but this does not reflect the streakiness of the pay. The rock is generally in the 1-10-mD range, with vugular sections that raise the average. In addition, the 13–9 well to the north is limestone, whereas the 8-8 well to the south has been dolomitized.

Figures 2 and 3 show core samples from the two pools. The fluid properties of the two pools are given in Figures 4 and 5. The bubble points are 9,067 kPa and 14,451 kPa and the solution gas-oil ratios are 51.4 m3/m3at 58°C and 104.4 m3/m3at 74°C for the Band G pools respectively.

Selection of Modes of Depletion

The thick section present in the B pool invited investigations of a vertical miscible flood, although the poor quality of the pay was of concern and prompted a bottom water-flood study as well. There was no known water underlying this pool.

Although the G pool is of high quality, the low thickness and oil-in-place were insufficient to warrant anything except water-flooding. A preliminary solvent slug sizing calculation using linear diffusion indicated that a 90070 P. V. slug would be necessary assuming a 20-year life.
Evolution of Alberta''s Petroleum And Natural Gas Land Regulations
Authors: Jordan Dale
Published: March 2010

Introduction

Mineral Owership

Section 109 of the British North America Act gives jurisdiction over natural resources to the provinces, and consequently we have as many sets of regulations providing for administration of the mineral resources as we have provinces. In addition to provincial regulations, there are regulations for minerals owned and controlled by the federal government in the northern territories and offshore areas and the minerals owned by the Treaty Indians under lands south of 60° parallel N.

Freehold Minerals

Not all minerals in Canada are owned by governments, and a summary of the rights generally referred to as freehold minerals follows.

Hudson"s Bay Lands

In 1670, Charles II granted to the Hudson"s Bay Company all the lands draining into Hudson"s Bay. This grant amounted to some one and a half million square miles westerly from Hudson"s Bay in much of what is now Manitoba, Saskatchewan, Alberta and the Northwest Territories to the Rocky Mountains.

Following federation in 1867, the new government of Canada undertook to acquire the territory granted to the Hudson"s Bay Company. In 1869, an agreement was signed pursuant to which the Hudson"s Bay Company surrendered all of its lands to Canada in consideration of:A payment of 300 thousand pounds sterling;The company retaining both surface and mineral rights at the company"s different trading posts and settlements, totaling about 45,000 acres;A grant of one-twentieth of the land (both surface and minerals) in what was referred to as the "Fertile Belt", an area described in the agreement as being bounded on the south by the United States, on the west by the Rocky Mountains, on the east by Lake Winnipeg, Lake of the Woods and the waters connecting them, and on the north by the North Saskatchewan River. These Hudson"s Bay lands are generally section 8 and 3/4 of section 26 in each township.

As a result of this agreement, the people of Canada in 1869 owned 95 per cent of the surface and minerals in the "Fertile Belt" and the surface and minerals in the balance of the area.

Railroad Lands

To effect settlement of the West as quickly as possible and to provide a land link to the colony of British Columbia, land and minerals were granted to the railroad building companies. The Canadian Pacific Railway Company received a large area (including surface and minerals) along the right-of-way of its railway. Similar grants were made to smaller railways, some of which were subsequently taken over by the Canadian Pacific Railway Company. In the four western provinces, approximately 3,500 miles of railway were constructed and some thirty million acres of both surface and minerals transferred to the different companies as subsidies.

Homestead Lands

Settlers acquiring homesteads obtained the minerals with the surface until October 31, 1887. After that date, the federal government excepted minerals when making land grants. All mines and minerals thereafter were reserved to the government when land was disposed of for some surface-related purpose.
The Sulphur Industry In Alberta
Authors: McDonald M.D. , Moeller E.P.
Published: March 2010

Introduction

Recent increases in worldwide demand for sulphur have resulted in a rapid escalation of prices. This price increase has greatly improved the Canadian sulphur export picture. The Alberta net-back price now makes remelting of stockpiles profitable. For the first time since 1966, inventories are declining and sulphur can no longer be labelled an undesirable by product.

As a result of these changes, more effort and sophistication is being applied to sulphur production and marketing. These improvements are likely to continue as a result of an increasing awareness and appreciation of the limitations on the economically· available stock of the resource in Alberta, and the rising cost of Frasch production elsewhere. This paper seeks to provide the reader with a brief description of the industry, its history and future, as well as related issues.

History of the Industry

In 1924, Royalite Oil Company Limited constructed the first commercial-scale gas processing plant in Alberta. This plant recovered natural gasoline and residue gas from the wet solution gas being flared. The first gas scrubbing plants utilized the Seaboard Process (later replaced by the Gerbitol Process) to remove hydrogen SUlphide gas; however, no sulphur was recovered. In 1934, Gas & Oil Products Limited, later Anglo American Exploration Ltd., constructed a plant near Hartell and in 1936 The British American Oil Company Limited built a plant near Longview. These three plants comprised the total natural gas processing industry in Western Canada until after the Leduc oil discovery in 1947. Since then, the plants at Longview and Hartell have ceased operations, but throughout the province numerous other plants had to be built to strip liquids and remove sulphur in order to render the gas marketable.

The first plant to commercially extract sulphur from sour natural gas was the Shell Jumping Pound Plant. It was placed on stream in 1951 and was initially designed to process 990 thousand cubic metres per day of raw gas and recover about 30 tonnes per day of elemental sulphur.

Regulatory Development

Royalite No.4, which made the major natural gas discovery in 1924, ushered in an era of waste at Turner Valley. The only way to get a saleable product was to strip the condensate and flare the gas. Even before oil was discovered in 1931, it had been realized that gas flaring had robbed the reservoir of much of its virgin pressure. The oil and gas that would have otherwise been recovered had become locked into the pool forever. The Alberta government, concerned since 1930 about this loss of production and royalty, created the Petroleum and Natural Gas Conservation Board in 1938 to enforce the Oil and Gas Conservation Act. In 1970, it became evident that Alberta needed to review its requirements for all forms of energy resources and provide a means of government-coordinated development of the petroleum in the province. The result was the passage in 1971 of the Energy Resources Conservation Act.
Federal Sales Tax Reform Aggravates Industry''s Indigestion
Authors: Parsons Robert B.
Published: March 2010

The incredible scalpels and bedpans of Ottawa's undaunted fiscal medics know no rest! As if the far-reaching measures of the NEP were not enough for Canada's petroleum industry to absorb with that program's prescription of new rules for income taxes, royalties, excise taxes, prices, incentives, ownership, etc.-the industry is now confronted with a total reform of this country's federal sales tax system.

It is now intended that the government's proposed reform of the system, which was announced in the federal budget on November 12, 1981, would be Implemented with effect from January 1, 1983. (Of course, the oil and gas sector had an early dose of the reform in 1981, when the federal sales tax on gasoline, diesel and aviation fuel was shifted from the producer stage /0 the distributor stage). Although the proposed new rules will affect the integrated producers and distributors more than others in the industry, the effects of the changes will be felt by all enterprises in varying degrees.

This month, Tax Topics describes very briefly the thrust of the new system and its possible effects on doing business in Canada.*

Price Waterhouse has published a comprehensive, fully illustrated booklet on the federal sales tax reform. Complimentary copies of the booklet may be obtained from any Price Waterhouse office.

Introduction

The long-awaited changes to the federal sales tax system, as well as some changes in excise taxes, were announced by Finance Minister MacEachen in the federal budget of November 12, 1981, when it was proposed to shift the incidence of these taxes from the manufacturer to the wholesaler level. This announcement was followed up with the release of a Federal Sales Tax Reform Discussion Paper and related draft legislation on April 30, 1982, thereby giving taxpayers some insight into how the new system may affect them. However draft legislation dealing with administrative matters such as refunds, assessments and appeals has yet to be released.

This article introduces very briefly the main features of the new tax system in order to provide some guidance to readers for obtaining an understanding of the implications of the new provisions and some insight into the potential impact on their businesses. It is, of course, not intended to provide an all-inclusive and definitive commentary on all facets of the new federal sales tax system.

The information in this article is based on the draft legislation, the discussion paper and other government information available at the date of publication. However, there will undoubtedly be numerous changes made to the draft legislation as submissions from taxpayers and others are considered. The main features of the proposals are summarized in Table 1.

Background

The federal sales tax is a tax on the provision or consumption of finished goods in Canada. The tax is one of general application, imposed under the Excise Tax Act on all domestic manufactured goods or imported goods, other than those exempted by specific legislative provision.
Building Semi-submersible Rigs In Canada- is It Feasible?
Authors: Gurel Douglas O.
Published: March 2010

Introduction

What are the special considerations involved in building a semi-submersible rig in Canada today? Husky Oil and Bow Valley Resource Services are currently involved in the construction of two semi-submersible drilling rigs. One is being built in Sandefjord, Norway by Framaes, the other in Saint John, New Brunswick by Saint John Shipbuilding and Dry-dock.

The former is an enhanced Pacesetter design with the Standard six-column and two-pontoon arrangement. This is probably the most popular type of rig currently being built.

The latter is an 8-column design and is very similar in ail essential features to the enhanced Pacesetter. It differs only in such areas as equipment and accommodation layouts. From a rig owner's standpoint the rigs are essentially identical, as can be seen in Table 1.

Both rigs are built to conform to the so-called 35-degree* rule which allows them to float with the loss of buoyancy in one column.

As semi-submersibles go, both are medium size and very similar to those currently operating on the East Coast. Both rigs will be drilling initially for the Husky/Bow Valley joint venture off the coast of Nova Scotia. Simultaneous construction provides a unique opportunity to compare construction from every angle.

History of Rigs Built in Canada

A review of rig building in this country reveals that over the

*The actual angle that the rig will float with one column completely flooded is not necessarily 35 degrees. Rather it is determined by the size of the columns and the configuration of the rigs. Calculations for the ACKER 3.2 rig show that it would float at a 26-degree list with one column flooded. The object of this rule is to provide an additional margin of safety and time to evacuate the rig even though it may be listing dangerously past 15 years, a substantial number of offshore rigs, both semi-submersibles and jack-ups, have been built. There is an established construction capability for jack-up rigs.

Witness to this is the fact that over the past three years, nine units have been completed and three are under construction. All of these have been built in the Davie Shipbuilding yards at Lauzon, Quebec. Table 2 tabulates the Davie jack-up rigs. The principal owner of these units is Global Marine Drilling. These rigs are currently at work in a variety of places around the world-Brazil, Tunisia, Gulf of Suez, and the Gulf of Mexico. Global Marine states that their Canadians-built rigs are very satisfactory and cost-competitive with any of the other rigs in their fleet.

Semi-Submersible Rigs

There have been no rigs of this type built in Canada since 1978.

Table 3 lists those floating rigs built in Canada. The first four were of the three-legged design and the next three were moored semis using the long pontoon-column arrangements.

(Figure in full paper)

The 709 was a dynamically position semi and the 471 was a ship-shaped rig.

SEDCO and several other users report satisfactory performance. They compare favorably with any other units in their fleet.
The Western LNG Project
Authors: Van Der Linden J.R.
Published: March 2010

Introduction

The Western LNG Project is one of the last "megaprojects" which is still being actively pursued in Canada because the oil sands plants, the Arctic Pilot Plant and the Foothills Pipeline are all in various stages of shelving or mothballing. Canada needs the Western LNG Project, and Dame Petroleum Limited is working very hard to bring it into being.

This paper will provide a little history, will briefly outline the project, and will indicate our progress to date.

In 1978 Dome, a key player in Alberta ethane supply identified a surplus of ethane developing in Alberta and saw potential in British Columbia. At the time the surplus was in excess of requirements for Alberta and other traditional markets, consequently an approach was made for sales to Japan.

To make a long story short, the ethane surplus disappeared due to expansion plans for petrochemical developments in Alberta and, as a substitute energy export into Japan, the Western LNG Project came into being.

The years 1980 and 1981 were the "years of the market "where the principal project activity was centered around obtaining the sales agreement which was signed in its final form March 20, 1982. The year 1982 was, and is, the "year of the regulatory approvals ", governments permitting, 1983 will be the "year of the engineer" when we can complete our design and proceed with the construction.

Project Description

Dome Petroleum Limited and NIC Resources Inc. (a Canadian subsidiary of Nissho Iwai Corporation of Japan), signed the agreement for the sale of liquefied natural gas to five major Japanese utility companies. Nissho Iwai is a major Japanese trading company, the largest in Japan in the area of LNG. Contingent upon obtaining the necessary Canadian government approvals and assuming our plans are in place, deliveries will begin in 1986. Under a 20-year 100 per cent take-or-pay purchase agreement, annual deliveries will total 2.9 million tonnes (154 billion cubic feet) by 1989. Other Canadian participants could include NOVA, An Alberta Corporation, TransCanada Pipeline Limited and British Columbia Resources Investment Corporation.

The natural gas will be converted to liquid at the Grassy Point site, 30 kilometres north of Prince Rupert, British Columbia. The LNG will then be transported to Japan in five conventional marine carriers each having a capacity of 125 thousand cubic metres (2.7 billion cubic feet) of liquefied natural gas. Upon reaching Japan, the LNG will be sold to the five major Japanese utility companies.

Figure 1 presents a schematic representation of the project. A joint Alberta, British Columbia natural gas supply is proposed. Of the total peak requirements of 451 MMcf/d, Alberta will provide 338 MMcfl/d (peak day) in the first phase of the project. The remainder of the natural gas, approximately 113 MMcf /d (peak day), will be supplied by British Columbia. The province recently conducted hearings to determine the amount of surplus gas available in B.C. and analyze the projects. The Western LNG Project was selected.
Use Of Magnetic Ranging Logging Tool To Direct Amoco . Steep A7-28-66-07 W6M Drilling
Authors: Duguid A.T.
Published: March 2010

Amoco et al. Steep A7–28–66–7W6M was drilled as a directional well to 2395 m M.D. to intersect Amoco et al. Steep 7–28–66–7W6M which had blown out. The replacement well was to be used to perform a bottomhole-kill operation and then subsequently converted to a producing well. As the precise bottom hole location of Steep 7–28 was unknown, a method for estimating the proximity of this wellbore to the Steep A 7–28 wellbore, while drilling, was required.

A "Magrange II" logging tool, used to detect the presence of magnetized steel in remote bore holes, provided both direction and distance from the logging tool to the abandoned drill string in the Steep 7–28 wellbore. This information was used to direct the drilling progress of Steep A7–28 toward the blowout well.

A separation of approximately two metres between the wellbores, at 2331m. T.V.D. was achieved. The kill operation was subsequently conducted through a completed wellbore.

Introduction

The Amoco et al. Steep 7–28–66–7W6 well blew out upon penetration of the Spirit River " F" conglomerate at a depth of 2338 m M.D. (7669 ft). Located approximately 60 km (40 mi.) south of Grande Prairie, Alberta in the heart of the Elmworth Deep Basin, the well was drilled as part of Amoco Canada's program to test the massive Lower Cretaceous sands, principally for their tight gas potential. Assessment of the kick data from Steep 7–28 and of data from two other wells which had encountered this conglomerate in Township 66–8W6 revealed the Fahler " F" to have an over pressured gradient of approximately 12.5 kPa/m (0.55 psi/ft) with a deliverability of sweet dry gas, in the range of 425–1000 × 10m3/d (15–35 mmcfd), typical of high permeability conglomerates.

After controlling the blowout, a fishing job was undertaken to recover the stuck drill string and save the well The Steep 7–28 well was left with the bottom 1100 m (3600 ft) of drill string in the hole and a fishing string hanging from the wellhead. A small amount of gas continued to flare at surface as the 7–28 well could not be shut-in due to a lack of casing in the Wellbore. With 1890 m (6200 ft) of open hole exposed and at least partially collapsed around the drill string, the possibility of underground blowout, or uphole charging of permeable formations, necessitated the drilling of a relief well, Steep A7–28–66–7W6 to effect a bottomhole kill at Steep 7–28.

Steep A7–28 was designed with the following factors in mind:overpressured gas-the well was designed as a producer for high pressure, high deliverability gas.deliverability-in order to complete a bottom hole dynamic kill of 7–28, a fluid pump rate capability down the well of 20–25 m3/min. (125–160 bpm) had to be accommodated.breakthrough gas-any overcharged uphole formation could cause premature connection between A7–28 and the Fahler " F" of 7–28.hole problems-Blackstone and Shaftsbury shales are known problem zones in this area.directional drilling-the well was to be drilled to intercept 7–28.
Energy Pricing Scenarios
Authors: Angevine G.E.
Published: March 2010

Current intense interest in the subject of prices is in part related to recent developments in the world oil market and their jarring impact on Canada's energy sector. Where is the world oil price headed? What are the implications of the world oil market situation as at the beginning of January 1983 for the Alberta/Canada oil pricing agreement of September 1981, and domestic natural gas prices (closely tied by regulation to oil prices)?

Because the oil price is the key to energy pricing patterns in today's environment, this paper will focus on likely oil pricing developments-with some reference to gas. One must, however, not forget that the prices of energy commodities which compete with oil and gas —especially electric power rates —are not insensitive to movements in the oil price. While not directly linked to the oil price, regulated electric power rates can, in general, be expected to rise more or less rapidly as the rate of domestic oil price increase accelerates or slows. The linkages are embedded in the economic system. As oil and gas prices rise relative to electric power rates, the demand for electricity can be expected to rise. In turn, this will increase electric power generation capacity requirements, the construction of which will put additional pressure on power rates.

The world oil price

Figure 1 shows that the official price of Saudi Arabian light marker crude has risen about threefold since 1978. Most of the price increase occurred through 1979 and 1980. Increased crude oil demand among the industrialized countries and a decline to deliveries from Iran because of the revolution, caused the spot price to take a sharp jump. OPEC responded by raising its official marker crude price.

It was assumed by many that increases in the OPEC price would continue through the 1980s with annual gains at least equal, on average, to the inflation rate in the major industrialized countries. It is, however, doubtful that this will occur. In fact, if OPEC, led by Saudi Arabia, had not moved to reduce its total production rate drastically (from 10.0 MMB/D to 5.5 MMB/D) beginning in the second half of 1981, (Fig. 1A) the glut in the world oil market would have been even greater and the average spot price might have fallen back to 1978 levels or even further. As it happened, the production cutbacks kept the price from rumbling.

Assuming that world economic recovery will be slow, it is unlikely that OPEC will opt for, or be able to achieve, price increases in excess of inflation rates over the next two years. A more rapid increase in the oil price would damage prospects for economic recovery and prolong the need for continued severe production quotas on OPEC members. It would also increase the incentive for OPEC customers to develop their oil sands, heavy oil, relatively costly frontier petroleum resources, and even alternative energy sources such as solar, wind hydrogen and compressed natural gas.
Some Observations On North Sea Developments Relative To Canada''s East Coast*
Authors: DeWolf A.G.
Published: March 2010

Introduction

This paper originally was in the form of an address to the Mining Society of Nova Scotia, 19th Annual Fall Meeting, Sydney, Nova Scotia, November 20, 1982. In this presentation, the paper was entitled " Some North Sea Experiences With Offshore Hydrocarbon Developments ".

History

The experience of North Sea countries with oil and gas is, of course, very recent. Since at least the period of the Roman invasion of Britain, the North Sea has been a centre of trade and its principal natural resource has been fish. To the Anglo-Saxons in Britain, the North Sea brought the feared Norse hordes who were less than welcome guests in their country (actually kingdoms). During the thirteenth and fourteenth centuries, the North Sea was the centre of trade in Northern Europe under the Hanseatic League. Cities such as Hamburg and Lubeck in Germany. Bruges (present day Brussels) in what was then France, London, and Bergen in Norway became important centres of trade. After the decline of the Hanseatic League, London continued to thrive but was rivaled in the seventeenth and eighteenth centuries by Amsterdam, which became a major trading and commercial centre. Much of this history is irrelevant to the present day experience of North Sea countries with offshore development but it is included to give some perspective to the very short experience North Sea countries have had with oil and gas compared to their long experience with trade, commerce and fishing.

Turning to the recent North Sea experience, it has been slated that as late as 1958, a staff geologist with the Norwegian Geological Survey said he would drink all the oil that would be found on the Norwegian Continental Shelf (Stenstadvold, 1981, p.l). Such was the attitude to the prospects of finding offshore hydrocarbons until the mid-1960s.

The first significant discovery of hydrocarbons by a North Sea country was not made offshore, but rather onshore, in the Netherlands, in 1959. In that year, the massive Slochteren gas field in Groningen Province, with estimated recoverable reserves of 63 trillion cubic feet, was discovered. Apparently, this discovery was not taken as an indication of the potential for oil and gas discoveries offshore as offshore drilling did not begin until several years later.

In 1963 and 1964, Norway and the United Kingdom, respectively, declared sovereignty over their continental shelves. Offshore drilling licenses were issued very soon after sovereignty was declared but it was not until 1965 that the boundary between the United Kingdom and Norway was agreed to. The 1958 Geneva Continental Shelf Convention provided for the sovereign right of states to explore and exploit natural resources of the sea bed on the continental shelf to a depth of 200 metres, to the limits which exploitation of natural resources was feasible or, failing agreement between two littoral countries, to a line equidistant between them.
International Experiences: a Personal Perspective
Authors: Benediktson S.V.
Published: March 2010

I have been asked to share my views on working as a Canadian expatriate engineer in the international oil and gas arena. I confess at the outset to a biased view. I would not trade a moment of my time since leaving the farm near Markerville, Alberta in 1953 to go to work in the oil fields. Over the ensuing thirty years I have lived in drilling camps in Northern B.C. and Alberta, at Norman Wells, Redwater, Edmonton and Calgary. Houston, Texas, Melbourne and Sydney. Australia, Jakarta, Indonesia. Dhahran, Saudi Arabia, Abu Dhabi in the United Arab Emirates and Ottawa, Ontario, and I have enjoyed each place and each assignment. Some more than others, but always secure in the knowledge that the oil and gas industry is the greatest business in the world.The following are a number of generalizations that I consider unique to an overseas job and/or to the successful expatriate employee:An An overseas job is generally characterized by more responsibility than an equivalent domestic job.A professional in an overseas job must provide a standard of excellence in his j ob performance that merits the trust and support of his management and host governmentThe expatriate employee needs to have a social sensitivity and a concern for local customs and practices.An overseas job usually requires a commitment to train a local national, often the expatriate's replacement, in technical and/or operational detail.A special measure of patience and job commitment are required by the expatriate to overcome situations that may occur, such as reporting to a local national who may be obviously less qualified than the expatriate.It is important for the expatriate to make an effort to learn at least a minimal vocabulary in the language of the country.It is important for expatriates to become familiar with the legal and social values that guide the conduct of those residing and working in the country. The consequences of ignoring this guideline range from embarrassment for the individual to cancellation of the company's operating contract.It is advisable for expatriates to be informed of and sensitive to local political issues but to avoid involvement and outspoken comments on local politics.Almost every expatriate employee is deemed to be a spokesman for his employer.In some overseas locations there is a complete absence of government regulations or standards or‘’ design. The expatriate may have to relate to regulations and standards from another locale or possibly assist the local government in developing appropriate regulations and standards.An expatriate may not be able to obtain equipment and materials from traditional suppliers to the domestic industry and needs to be resourceful with the ability to adapt.Expatriate survivors are the ones who look on new experiences and customs as enriching experiences to be enjoyed. The expatriates or thier families who react to changes as though they were a burden tobe borne or worse yetto be changed, do not last inthe international arena.
A Libyan Experience
Authors: McCaskill A.J.
Published: March 2010

Introduction

Libya! When the job offer arrived, I knew very little about this country other than echoes of World War II battles won and lost-and finally won again: Benghazi, Tobruk ... and across the border in Egypt: El Alamein.

Our children were grown. My wife and I were living in Calgary and I had a job where I could comfortably have stayed put until that magical sixty-fifth birthday. But adventure beckoned. I replied to an ad in the Calgary Herald for a production engineer for Oasis Oil Co. of Libya.

Oasis has a personnel office in New York and a recruiting team from there travels around Canada and the U.S. The interview in Calgary was pleasant and low key. The company representatives explained financial arrangements and indicated that the company would ship our household effects to Tripoli. We would have a rented furnished villa until our furniture arrived and by then we would have found our own accommodation.

There was not a fixed-term contract. Instead there was an employee savings plan which was enhanced by company contributions if one stayed for three years or longer. A month's leave, plus travelling time, each year, with the company paying the return fare to one's point of origin, provided an excellent opportunity for seeing the world, as the fare could be applied to any trip one wished to take.

The company also paid for our two younger children, who were at university at the time, to fly to Tripoli once a year for three years (i.e. up to obtaining a first degree). For families with younger children, there is an excellent school in Tripoli which goes up to Grade IX and after that the oil companies subsidize secondary schooling wherever the children may be attending. (This may be in North America or Europe-many go to Switzerland). I accepted the terms offered, but made one demand: I would not resign from my Calgary position until the company had obtained a work permit for me. They had wanted me to go immediately on a visitor's visa, but I wanted my status to be assured.

In November of 1974, the permit came through and I was off, leaving my wife to rent our house, dispose of cars, and arrange for shipment of our "Lares and Penates", then join me a month later. This also involved purchasing a propane-powered stove, as electric power is somewhat uncertain in Libya. We also shipped an air conditioner, but later sold it as our apartment was just a block from the Mediterranean and we could usually keep very comfortable just by opening windows and the French doors to the balconies.

My arrival in Tripoli was not auspicious- but symbolic of what my new life style was to be. My plane arrived eight hours late-well after midnight. At that time the Tripoli airport was a former R.A.F. W.W. II hangar; there were shell-holes still evident in the roof.
Financing Major Energy Projects
Authors: Bain Donald
Published: March 2010

The first oil and gas department in a bank was created in 1928 and the first oil and gas production loan was made in the 1930s by a Dallas-based bank. Its technical staff was brave enough to lend against established cash flows. Thus, an important principle had been established: lending against a security buried under the ground. Technical personnel were able La predict reserves and production rates because many of the Texas fields had been on stream for relatively lengthy periods and reliable production histories had been established. In addition, increasing government regulation controlled production making for more reliable loan collateral.

As a result of Leduc in 1947, the then Canadian Bank of Commerce actively pursued the concept of forming its own oil and gas department. Senior officials toured Texas and Oklahoma and talked to industry personnel and banks and the first oil and gas department in a Canadian bank was formed by the Canadian Bank of Commerce.

Right from the beginning, it was decided that banks would not lend for exploralion unless the loan could be secured by established production or some other form of collateral and this is still the case. After all, exploration is an extremely risky exercise. Traditionally, banks have only been interested in low-risk ventures, confining themselves to projects where it is possible to recover payment of the loan plus interest. Even if a field provesto be as big as Pembina, the banks will not share in the sudden wealth, but on the other hand if, the venture fails, it is possible to lose the entire loan. Oil and gas loans historically have had extremely low failure rates. This may sound too conservative, but remember that in an oil company an explorationist who achieves a 1 in 8 success ratio is treated as a genius, while in a bank a loans officer who makes one bad deal in one hundred may be regarded as a disaster. So it just depends which way one looks at things.

Four main areas have evolved: equity financing balance sheet loans, conventional production loam and project loans.

Equity Financing

Generally speaking, the major banks have not taken an actual share in oil because they are normally prevented by legal constraints from doing so. Canadian and American banks have very strict regulations controlling their investments but banks can purchase shares it is to prevent a company from going into receivership.

The major exception is in the U.K. North Sea where British chartered banks actively participated in the seventh round of licence awards in 1980. The UK government had let it be known that it wan Led British companies to become involved and as a result some of the most unlikely "oil finders" appeared in the list of successful bidders. Personally, I am not sure that it is a good idea for banks to enter into the industry as participants. even if they have not yet actually acted as Operators.
Alberta Securities Act
Authors: Budd Thomas , Goss Doug
Published: March 2010

AN OIL and gas company wishing to issue securities to the public cannot do 50 without complying with the SecuritiesACTofAlberta. The Act is administered by the Athena Securities Commission and although dealings with natural resource companies are commonplace at present, strangely enough the evolution of the securities regulatory process in the province of Alberta, had little to do with the growth of the oil and gas industry.

The first securities legislation, administered by the Board of Public Utility Commissioners, was passed in Alberta in 1916 with its main purpose to prevent stock fraud and to assist in the detection and prosecution of persons not normally liable for offences under the Criminal Code.

In 1955, a new Securities Act was passed by the Alberta legislature as it became apparent that an agency which could only deal with the regulation -of securities on a part-time basis was no longer adequate. The first appointed Chairman of the Commission was G. Harry Rose who was a former member of the Board of Public Utility Commissioners and who, in fact, was responsible for establishing the machinery for the proclamation of the Act. The 1955 Act was expected to provide protection to the investing public from several "boiler shop" operations and "suitcase" brokers who had been forced out of other provinces where effective securities legislation had been enacted. This effectively curtailed these undesirable business operations.

Although the 1955 Act helped eliminate telephone solicitations from other provinces and relieved the province of stockaleers, it did not totally prevent fraudulent trades in securities. Shady promoters simply became smarter and were able to circumvent the intent of the securities legislation.

In 1967, the Securities Act of Alberta underwent a substantial revision in an attempt to improve laws which would better protect the public and improve the integrity of the capital markets. This new legislation was based mainly on recommendations prepared by the Kimber Committee which undertook a special study of securities legislation in Canada, the United States, England and Australia. The committee's mandate was:

"To review and report upon, in the light of modern business conditions and practices, the provisions and working of securities legislation in Ontario and in particular to consider the problems of take-over bids and of insider trading, the degree of disclosure of information to shareholders, the requirement as to proxy solicitation, procedures as to primary distribution of securities to the public and like matters and generally to recommend what, if any, changes in the law are desirable."

The revised Act introduced a "new concept of disclosure", new rules relating to take-over bids and insider trading and proxy notices. From the public's viewpoint, the financial disclosure provisions represented the most important changes as they were primarily designed to provide investors with more information on corporate and financial affairs of companies whose shares were trading" on the public market.
Current Status of Tidal Power
Authors: Clark R.H. , Karas A.N.
Published: March 2010

Introduction

It goes without saying that tidal power is an environmentally clean, renewableenergy source. Although tidal energy is available in abundance, there arerelatively few locations in the world where the tidal range makes this form ofenergy economically exploitable under existing conditions. Relatively largetidal ranges had been used on a micro-scale for driving mills and pumpsfor many hundreds of years but such small direct drive applicationsbecame obsolete with the onset of the Industrial Revolution.

Technologically, this source is well within reach to exploit. It is renewable, pollution-free, relatively inflation-free, and completely predictable. It couldcontribute to energy self-sufficiency and reduce the environmental problemsassociated with the conversion of fossil fuels to electricalenergy.

The obvious question is: Why has this resource not been exploited to itsfullest extent? There is no easy answer. Canadian government energy policiespreoccupied with non-renewable sources and an apparent reluctance to undertakea project which, although technically feasible, has combined with marginaleconomics and high financial risks to slow progress. There are no precedents inthe field of successful tidal megaprojects such as might be built in the Bay of Fundy. Moreover, there are only a few locations where the topography wouldproduce tidal amplitudes large enough to justify installation.

Tidal Characteristics and Tides as a Power Source

Tides require a unique approach to the development and utilization of theirenergy. Along the Atlantic coasts of both Europe and America the tides rise andfall twice each 24 hours and 50 minutes, phased with the apparent period ofrotation of the moon. The excess of 50 minutes over the solar day results inmaximum and minimum water levels occurring at progressively different times ondifferent days, i.e. the tidal cycle moves into and out of phase with man"sactivities. The range also varies from day-to-day, reaching a maximum every twoweeks when the sun and moon are in alignment creating spring tides. Eight dayslater, the sun and moon form a right angle with Earth and partially neutralizeone another's gravitational influence to produce "neap" tides. At the vernaland autumnal equinoxes, the range is extremely large. These latter occurrenceshave an important bearing on the design of a tidal power plant. There are, ofcourse exceptions. For example at a number of places the maximum water leveloccurs every day at the same time; at others, there is only one tidalfluctuation a day; at still others, the single maximum may be replaced by two.The cardinal feature of tides is that, regardless of their local variation, they, occur in a most orderly, predictable fashion.

Large tidal ranges in the Bay Fundy and at other locations around the world aredue to a combination of two natural phenomena: the motion of the sea initiatedby forces of the sun and moon and the configuration of the coast line overwhich this motion occurs.