bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract

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

Abstract
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.