bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oin And Gas Prices-a Moving Target
Authors: Parsons Robert B. 
Published: March 2010

Abstract
For the fourth time in less than three years, Canada's oil and gas producers face new formulas for pricing their output. as the federal government continues refusal to let the market dictate domestic oil and gas prices.
The June 30, 1983 federal/Alberta price agreement offers some interesting and ominous surprises.

Introduction
There are many lessons to be learned from the National Energy Program, but the lesson which is becoming increasingly evident as time passes is that it is virtually impossible to administer static rules in a fluid international market place. The revised energy pricing agreement reached by the federal and Alberta governments on June 30, 1983 is one more striking example of the lesson that, in the absence of a fundamental policy change, interference in the market place is bound to require continuing ad hoc adjustments. (Apart from the pricing facet of the NEP, other examples of this lesson include the continuing tinkering with the COR and PIP rules, as well as the seemingly endless revisions of the royalty and income tax rules.)
Of course, the fundamental pricing policy change which is required to break out of the current dilemma of rulemaking would involve the federal government swallowing a seemingly bitter political pill and letting the market dictate oil and gas prices. Although the June 30, 1983 energy pricing revisions are, by and large, intended to apply for an eighteen-month period, there is a good chance that this period will not pass without further modifications to the agreed price structure.

New Price System
October 28, 1980 stands out as a black day in the modern economic history of Canada. On that day, the federal government announced the NEP, which established, among other things, a schedule of prices for domestic oil and gas production, plus a new system for blending the prices for different sources of oil into one weighted average price to consumers.
In response to the strong negative reaction by the producing provinces and most producers and other investors to the proposed price schedules, the federal government reconsidered the pricing of oil and gas. On September I, 1981, the federal and Alberta governments reached an accord which included revised schedules and formulae for the pricing of Canadian oil and gas production until 1986. Separate agreements were subsequently concluded with British Columbia and Saskatchewan in respect of pricing, as well as other matters relating to the NEP.
Further refinements to the price structure were announced on May 31,1982 to be effective July 1, 1982.
The September 1, 1981 pricing agreement, which was based on assumptions of dramatic increases in the international price of oil, was soon rendered nonsensical by the unexpected decline. These changed circumstances produced the main impetus for the federal and provincial negotiations of yet another set of negotiations which culminated on June 30, 1983 with the release of amendments to the September 1, 1981 federal/Alberta agreement.
The Rise And Fall of the Drilling Program
Authors: Murray Ivor 
Published: March 2010

Abstract
THE drilling program first appeared on the national scene in Canada- in 1976. During its heyday it attracted hundreds of millions of dollars a year which were channeled into Canadian oil exploration and development, with relatively minor amounts going to the U.S. Yet by the second half of 1981 it had virtually disappeared as a method of financing. What happened? This article will attempt to trace the events of that brief period and explain the demise of this innovative method.
Tax, and the avoidance of tax, are always of paramount importance. In Canada, "tax shelter" really means "tax deferral" although in some cases "(ax shelter" can mean "conversion of taxable income into capital gain". An important point must be made here. Tax shelters are not tax loopholes arising out of shortcomings in the Income Tax Act. They are tax concessions granted to encourage investment in endeavours which the government conceives to be in the national interest. This same method has been used time and again in Canada since the early thirties, and also elsewhere in the western world.
Is capital investment by industry lagging? Then let the government offer accelerated depreciation for new capital investment. Is there a shortage of high quality residential rental properties? Then let's have MURBs. Would it be desirable for Canada to become self-sufficient in oil and gas? Then let's encourage drilling programs.
The general principle for taxation of business enterprise in Canada allows a personal or corporate taxpayer in computing taxable income to deduct all expenses, including such non-cash expenses as depreciation and depletion, from gross income. The exception to that general rule is that the application of these allowances by private citizens in their personal investment activities is very severely limited. The exception to the exception is that in tax shelters the Income Tax Act allows the generated deductions to be applied by all taxpayers to income from any source. With that as general background it is illuminating to examine how governments (both the "feds" and provincial) stimulated investment by private citizens in oil and gas.
In 1976 the vehicles available for direct investment by persons and corporations were joint venture, direct ownership or participation in a limited partnership, with the last being by far the preferred vehicle for persons. The principal deductions available were:
Canadian Exploration Expense-The cost of exploratory wells including the land could be written off by the declining balance method at the rate of 300/0 annually. This meant that if a share of a well cost $10,000, $3,000 could be deducted from taxable income in the year the well was drilled, 30% of the remaining $7,000 or $2,100, in the following year, and so on. After May 26, 1976, however, the rate was increased to 100%, where it remains today, so that a $10,000 well generated a $10,000 deduction.
Canadian Development Expense-A well classified as development rather than exploration was and is eligible for 30% declining balance treatment.
Heavy Oil In Saskatchewan
Authors: Reid Bob 
Published: March 2010

Abstract
Although vast resources of heavy crude oil have been known to exist in west-central Saskatchewan for many years, until recently these resources have remained on the sidelines while the better quality crude oils of the southern part of the province were the focus of the oil industry. In recent years, however, the importance of these enormous reserves of low API gravity, high sulphur crude has been recognized, as the remaining reserves of high-quality crudes in Canada decline rapidly. In the next several decades, Saskatchewan's heavy oil will form a very significant part of the energy picture of this country as enhanced oil recovery (EOR) and heavy oil upgrading combine to unlock the potential that currently exists in this area.
Although heavy oil was discovered on the Saskatchewan side of the Lloydminster area in 1936 it was not until 1944 that a commercial discovery was made. Production commenced in 1945 and in 1947 Husky Oil Ltd. constructed a refinery at Lloydminster to make asphalt from heavy oil. The early 1950s saw a flurry of activity in the area and heavy oil production reached a level of about 1 600 cubic metres per day (10,000 barrels per day) during 1956. Production continued at levels between 800 and 1 600 cubic metres per day (5,000 and 10,000 barrels per day) until 1966 when renewed interest in heavy oil sparked a mini-boom in the area which has continued to the present day.
The province's recognized heavy oil deposits cover a broad area of west-central Saskatchewan known as the Lloydminster-Kindersley heavy oil belt. The present extent of heavy oil development is an area which stretches from Kindersley in the south to S1. Walburg in the north and as far east as North Battleford. The oil occurrences mostly consist of multiple zones of thin unconsolidated sandstones with high oil saturations at an average depth of 600 metres (2,000 feet). Most of the oil is found in the Mannville Formation of the Cretaceous Age. However, near Kindersley there are several Bakken Sand pools of Mississippian origin. The crude oil ranges in density from about 950 to 990 kilograms per cubic metre (11 to 17 degrees API) and is extremely viscous, resulting in very poor primary recovery (averaging less than five per cent of the oil-in-place).
In response to the "re-discovery" of Saskatchewan heavy oil in recent years, the number of producing heavy oil wells in the Lloydminster-Kindersley area has risen from 840 in 1968 to a present level in excess of 3,200 wells. In the same l5-year period heavy oil production has increased from an average of 3 300 cubic metres per day to 8 700 cubic metres per day (21,000 to 55,000 barrel per day).
The potential of the heavy oil belt is illustrated by Saskatchewan Energy and Mines' estimates of ultimate oil-in-place of four billion cubic metres (25 billion barrels) (nearly four times proven oil-inplace) and ultimate recovery of 600 million cubic metres (3,800 million barrels) with the implementation of EOR techniques in all suitable reservoirs.
Perspective On Canada Lands
Authors: Taschereau M.E. 
Published: March 2010

Abstract
Two and a half years have passed since the Canada Oil and Gas Lands Administration was formed to oversee oil and gas activities on Canada lands and I signed on as its Administrator. We are now at least half-way through the term of most of the new exploration agreements negotiated with companies. These have replaced their previous and existing exploratory permits and leases. Thus this is as good a time as any to take stock of how things are shaping up.
COGLA's mandate is to manage all oil and gas activities on Canada lands, an area of approximately 10.2 million square kilometres which includes the Yukon, Northwest Territories, Hudson Bay and east, west and north coast offshore regions. It is carried out under the legislative authority of the Canada Oil and Gas Act and the Oil and Gas Production and Conservation Act. Objectives under federal energy policies include aggressive frontier exploration based on the goal of self-sufficiency in oil by the 1990s, plus the "need to know" the extent of hydrocarbon resources on the Canada lands. A fair opportunity for Canadians to participate in and realize the greatest possible benefits from petroleum activity including employment is another objective. Equally important are the needs to preserve traditional ways of life in communities near oil and gas projects, the serious consideration of northern concerns in the approval of projects, and human and environmental safety. The Government of Canada has also resolved that petroleum activity will not interfere with negotiations involving native land claims.
Just what has been achieved so far? Firstly, virtually all existing rights covering some 125 million hectares have been converted to new exploration agreements in accordance with the provisions of the Canada Oil and Gas Act. These agreements. 164 in total, have been approved by Ministers while another 31 remain to be concluded, including 25 in areas of world moratoriums. (87 are in the east coast offshore. 20 in the Arctic Islands; 34 in the Mainland Territories; and. 23 in the Beaufort Sea/Mackenzie Delta region).
These agreements have an average term of four years and require the drilling of at least one wildcat well in that time. The 164 exploration agreements announced to date include commitments to drill over 200 wells at a cost of about $8 billion.
A number of factors-the Petroleum Incentives Program, work requirements under exploration agreements, and the fact that 50 per cent of the lands must be relinquished during the terms of the agreements, has stimulated an unprecedented level of frontier oil and gas activity which is just now building to a peak.

Exploration
Over 300 000 km of seismic has been carried out over the past 3 1/2 years. A total of 103 exploratory wells have been drilled, including 22 in 1981, 23 in 1982,33 in 1983 and 25 in the first five months of 1984.
Retlaw Upper Mannville 'V' Pool Unit Experimental Carbon Dioxide Flood
Authors: Kerr W.E. 
Published: March 2010

Introduction
In November 1983, Westgrowth Petroleums Ltd. and partners initiated Canada's first carbon dioxide flood in the Retlaw Upper Mannville ‘V’ Pool, 80 miles southeast of Calgary. The flood is classified as an experimental project and is designed to test immiscible CO2 flooding of a 23 º API crude in a Glauconite sand. The CO2 project is the culmination of over two years of effort which included technical studies and research work, obtaining regulatory approvals, unitization of the project area and construction of the CO2 injection facilities. Westgrowth is operator and major owner. There are 11 co-owners.

Discussion
The Retlaw Upper Mannville ‘V’ Pool was discovered in 1976 by the drilling of the well 8-28-12-18 W4M and has since been developed to the south and east. Thirty-three wells have been completed on 32 ha (80 acres) spacing.
The reservoir is a lower Cretaceous Glauconite sand, which is thought to be a reworked splay sand that developed from nearby fluvial channels. The pool is a stratigraphic trap that is bound by shale or sand sequences of reduced quality. There is neither free water nor oil-water contact associated with the pool, which is at an average depth of 1067 m (3,500 ft). The reservoir temperature is 35.5 ºC (96 ºF) and the original pressure was 11,373 Kpa (1,650 psi). Several small gas caps exist in the southern part of the pool.
The pool has an average pay thickness of 8 feet, porosity of 18% and 50 md permeability. The original solution gas-oil ratio is 62 m3/m3 (350 SCF/bbl) and the 22 to 24 degree API gravity oil has a reservoir viscosity of 8 to 10 cp. The initial production rates for the wells varied from 2.4 to over 32.0 m3/d (15 to 200 BOPD).
The concept of a CO2 flood developed from the idea of pressure maintaining the reservoir with the CO2 rich tail gas from the nearby Turin Gas Plant, 3 miles from the pool. Most of the gas wells producing into that gas plant have a higher than normal natural content of CO2.
The need for a pressure maintenance scheme was apparent from quickly rising gas-oil ratios (and penalties) soon after the wells were placed on production. Waterflood was rejected because it was determined in lab studies that the hydrophillic clays in the glauconite sand swell on contact with fresh water. There wasn't enough saline water produced from other pools nearby that would be cheaply available. The inherent difficulties in waterflooding a viscous oil which had a developed free gas saturation along with the potential upside benefits of CO, flooding clinched the final decision.
A number of technical studies and core floods were conducted to establish the incremental benefits of CO2, flooding. Applications were made to the ERCB and AENR to seek approval. The CO2, is expected to work well because it has a high density at the low reservoir temperature. In addition to providing pressure maintenance, the CO2 increases the recovery by swelling the oil, reducing the viscosity and by extraction.
Helium-What About It?
Authors: Welch R.V. 
Published: March 2010

TO THE MAN in the street the word "helium" conjures up toy balloons on a midway or a picture of the Goodyear blimp hovering over a televised football game or professional golf match, and there, unfortunately, for most of us the interest ceases.
This lack of interest stems not from lack of curiosity but rather a breakdown in communication. The fact that the earth's atmosphere contains a constant five parts per million of a monatomic, colourless, non-toxic, inert gas does not now arouse much, if any, public comment but will be of considerable importance to our descendants two or three generations down the road when all of the world's natural gas has been consumed along with the entrapped helium.
The commercial source of helium is natural gas contaminated with helium resulting from radioactive disintegration processes occurring in the earth's crust over billions of years. The helium so formed diffuses through the porous crust into gas fields and into the atmosphere from which it is continuously lost to outer space(1).
Canadian efforts in regard to the harnessing and marketing of helium really began in 1917 when, under the need to obtain helium in quantity to fill airships and balloons during World War I, Professor J.E. McLennan of the University of Toronto surveyed most of the Canadian producing gas fields. There were only two places where an extraction plant might be established: at Hamilton, Ontario and Calgary. Alberta. In 1918 a small experimental plant was set up near Hamilton. Although quite pure helium could be obtained, the gas supply was insufficient for continuous operation. A short while later the plant was therefore brought to Calgary to process gas from the Bow Island field. From December 1, 1919 to April 17, 1920 a series of trial runs produced a total of about sixty thousand cubic feet of helium of 60% to 90% purity. The plant was closed when further financial support was not forthcoming(2).
Nothing further occurred until the discovery of a natural gas field in Saskatchewan containing 1.9% helium. 1.5% carbon dioxide and 96% nitrogen by the British American Oil Company (later Gulf Canada). This company joined with the bottled gas distributors British Oxygen Limited of England and L' Air Liquide of France to build an extraction plant.
The plant was built in 1964 under the name of Canadian Helium Limited some nine miles north of Swift Current, Saskatchewan, with an original capacity of twelve million cubic feet of grade A (99.995% pure) helium per year which was soon to be expanded to thirty-six million cubic feet per year. The production exceeded Canadian needs and most of it was exported to western Europe.
Reserves estimates, thought to be sufficient to last into the 1990s proved fallible and the plant closed down in mid-1977, leaving Canada without an indigenous supply of helium, a condition which still exists.
Productivity Potential Indicator In A Heavy Oil Reservoir
Authors: Nickel B.I. , Edgson J.J. , Howes E.J. 
Published: March 2010

Abstract
This paper presents a technique for relating wireline log data to production in the Morgan Lloydminster A Pool. It will be shown that information derived from this study of log data can be used to determine a particular heavy oil well's producing potential. Should the well not be producing to this estimated potential, the technique derived will indicate if a stimulation is necessary or warranted.
Recommendations will be given for evaluation of other similar heavy oil reservoirs. It should be noted that the process discussed is a simplification made necessary because of the limited log data available on the majority of the wells.

Introduction
Murphy Oil Company Ltd. operates approximately 70 wells in the Morgan Field, located 40 km northwest of Lloydminster, Alberta (Fig. 1). At first glance the primary producing horizon, the Lloydminster sand, appears fairly uniform throughout the field, yet production can vary from less than 1 m3 of oil per day to in excess of 6 m3 of oil per day.
This paper discusses a technique to determine if a Morgan Lloydminster A Pool well is producing to expected standards. The technique will be shown useful in determining if further work is warranted to bring the well up to these standards.

Geology
The oil sands of Lloydminster are sedimentary deposits of the Cretaceous Age. The Mannville sands of interest commonly include the Colony, McLaren, Waseca, Sparky, G.P., Rex, Lloydminster, Cummings and Dina (Fig. 2). This group of sands was deposited in the high-energy environment of the receding waters of the Boreal Ocean. Hence, they are a mixture of marine and continental shales, sandstones, siltstones and thin limestone stringers. They are relatively clean and unconsolidated with average porosities in the 30% range.
The Lloydminster sand is of primary interest in this paper. It is relatively clean unconsolidated sand with an average clay volume of 10% and porosities in the 30% range. The sand is generally 8 m to 16 m thick, and is found at an average depth of 550 m. The oil is 12 degrees API gravity and a viscosity of 18 000 m Pa.S at 20 °C.

Well Evaluation and Production Results
Most of the Morgan Lloydminster A Pool wells have been logged in the past with resistivity-spontaneous potential and neutron-density porosity logs. When it became obvious that production from well to well varied more than these logs would appear to indicate, the logging suite was modified to include an indicator of the amount of oil moved. Wellsite computer generated processes utilizing these logs were also used to aid in the interpretation of the reservoir (Fig. 3).
Figure 4 shows wellsite computed products from two wells, 12A-10-52-4W4 and 11D-10-52-4W4. Both have average porosities between 25% to 30% and water saturations of 10% to 25%. If anything, the wellsite computed product in 12A-10 would indicate slightly higher porosity and a slightly cleaner zone. Yet 12A had a stabilized initial production of 3 m3 of oil per day, while 11D-10 had a stabilized initial production of 6 m3 of oil per day.