bluuebunny/crossref_metadata_2025_split huggingface dataset:
Administration Ofthe Bituminous Oil Sands Of Alberta
Authors: Warne G.A. 
Published: March 2010

Abstract
The exposed bituminous oil sands at Athabasca appear to have first received the attention of white settlers in 1719 when Henry Kelsey, one of Hudson's Bay Company's early Governors, observed a sample of bituminous sand brought to him at Fort York(1)). One of his Cree employees had travelled to the Athabasca valley and brought back a sample of "gum or pitch" taken from the river bank. Although the bituminous sands sample did not impress Kelsey in 1719, the resource was recognized as having enormous potential by others who followed close behind him. Extensive efforts have been made since then, by provincial, federal and industry interests to improve the understanding of the resource, establish its economic potential and ensure that it is developed in the best interests of Alberta and Canada.

Early Disposition of Rights
The first disposition of rights to develop the oil sands was made in 1901 by the Privy Council of Canada(2). Seven tracts comprising 12,725 acres along the Athabasca River at and north of Fort McMurray were patented for surface, asphalt and petroleum and natural gas. Regulations for the "Disposal of Tarsands, the property of the Crown", in that portion of Alberta lying north of Township 80 between the 4th and 5th Meridians were approved by Order of the Governor in Council in 1910. Tar sands were interpreted in the regulations as:
" ...the sands and other material impregnated with tar, bitumen, petroleum, oil and other like substances found in deposits in the northerly portion of the Province of Alberta".
Soon after this in 1912 the regulations were suspended and each application was considered on its own merits.
In total some 21 leases were issued by the federal government. However, only four were in existence at the time of the transfer of the administration of the resources to the province in 1930. It appearsonly the leases held by Mr. Draper resulted in the construction of a plant and other significant operations prior to the transfer. However, in the late 1920s International Bitumen Company had commenced work at Bitumount leading to the major pilot extraction operations there in the 1930 to 1950 period.
The first regulations issued by Alberta for the disposal of bituminous sands deposits, the property of the Crown in the Province of Alberta, were issued by order in 1930.
Between 1930 and 1951 provincial agreements for development of the sands were entered into with companies and individuals including: Max Waite Ball, International Bitumen Company Limited, Abasand Oils Limited, and Lloyd Rogers Champion.
Of this group of dispositions only that of Max Waite Ball of Denver, who also formed Abasand Oil, was continued. His work led later to the Great Canadian Oil Sands (now Suncor) development.
A major bituminous sands conference was arranged by the Alberta government in September 1951 to study factors affecting bituminous sands development. In conjunction with the conference, Honourable N.E. Tanner, then Minister of Mines and Minerals, gave a: policy statement regarding prospecting permits and leases.
Incorporation Of Vertical Permeability Test Results In Vertical Miscible Flood Design And Operation
Authors: Gillund G.N. , Kamal M. 
Published: March 2010

Abstract
The original analysis of the Bigoray Nisku B miscible flood indicated potential coning problems related to the level of vertical permeability. This paper presents the results of a vertical permeability lest which were incorporated into a coning study. Additional reservoir data, along with the rate information from the coning study, will be used to revise the original reservoir simulation prediction and depletion Strategy.

Introduction
The miscible flood in the Bigoray Nisku B pool was initiated in February 1980. It was recognized at the time that the pool was subject to coning and that controlled production rates would be required to control solvent breakthrough. Since that time, additional work and studies have been carried out to refine and optimize production strategy.

History and Description
The Bigoray Nisku B pool (Fig. 2), part of the West Pembina play shown in Figure I, was discovered in April 1978 with the drilling of Well 13–9. Well 8–8 was drilled about one year later, in June 1979. Soon after that time, the possibilities of a miscible flood were investigated(1) and solvent injection was started into Well 13–9 in February 1980. The same studies showed that an additional well would increase recovery and allow higher producing rates since coning prevented the wells from reaching their full potential As a result, Well 9–8 was drilled in July 1980 and Well 16–8 in October 1982.
The historical production rates are shown in Figure 3. Note that prior to drilling Well 16–8 the allowable of 266 m3 /d was not being met. The full allowable is now being produced as a result of drilling this well.
The Nisku B pool is a pinnacle reef with a maximum thickness of 95 m and an oil in place of 1500 × 103m3. The measured core permeability averages 130 md; however, the indicated effective permeability value is much lower. Pay is streaky and vugular. Well 13–9 is limestone, 9–8 and 8–8 have been do1omitized and 16–8 partially so.

Vertical Permeability Test
The original model study demonstrared that coning was going to be a potential problem and some preliminary coning studies confirmed this tendency. Prior to conducting a proper coning study, it was felt that it was necessary to compare core and in-place values of permeability and Well 9–8 was chosen for this purpose.

Well Location and Test Intervals
The location of the test (9-8-52-8W5M) is shown in Figure 2. The well bore configuration during the test is shown in Figure 4. Due to the relatively large thickness of the formation it was recognized that testing more than one interval would be preferable and, therefore, two tests were run over two different intervals. However, only the first test, which is discussed in this paper, was successful. In this test, oil was injected in the upper perforations, centred at 2357.0 m. and the pressure were measured at the lower perforations centred at 2374.1 m. After the conclusion of the first test, a third set of perforation (not shown in Fig. 4) were shot at 2322.9 m.
Ice Management In The Labrador Sea
Authors: Miller J.D. , Greenhorn M.J. 
Published: March 2010

Introduction
The Labrador Sea is known as a hostile environment to all forms of marine activities. The region is buffetted by numerous storms every year which bring high winds, severe seastates and superstructure icing. For vessels attempting to navigate through the region the presence of icebergs present a year round hazard and sea ice, present during the winter and spring months, restricts the trafficability of vessels.
It is in this environment that the Labrador Group of Companies has undertaken an extensive program of exploratory drilling over the last decade. To date, some 23 wells have been drilled by this consortium, primarily on the offshore banks and the saddles between these banks. To ensure a safe and successful drilling operation, special attention has been given to the environmental constraints and programs have been developed to minimize their effect. In this paper we will present some of the aspects of the iceberg problem and the ice management techniques in place to deal with them.

Setting
Icebergs are found throughout the region encompassed by the permit acreage within the Labrador Sea. It is difficult to generalize on the presence of icebergs over the entire Labrador Sea region as their presence is variable in time and space. There exists an annual variation which sees the largest numbers of icebergs present in the May and June period, decreasing throughout the summer to a local minimum in October and November and then increasing to a late spring peak. The variability between years, in terms of the total numbers of icebergs recorded, is largely unknown in this region although there are large differences between a light and a heavy iceberg season. Farther south, at the boundary of the Grand Banks, the variation is from a minimum of zero icebergs to a maximum of about four times the mean annual value. The distribution of icebergs within the Labrador Sea shows a decrease in the number of icebergs present with increasing distance from the coastline. Also, at a given point in lime more icebergs will be present in northerly regions than in those farther south. The reduced fluxes with distance offshore and southward along the coast indicate both the deterioration of icebergs and the divergence of icebergs from the surveyed region. A variety of mechanisms, both mechanical and thermal, influence the decay of icebergs in this corridor and their interrelationships are only qualitatively understood.

The Equipment
On the Labrador Shelf drillships have been used predominantly. Their deck load and cargo capacity permits operation in remote areas with minimum resupply. Dynamically positioned drillships have been preferred due to their ability to move off and back onto a well quickly when threatened by Ice or icebergs. This capability maximizes vessel safety and minimizes costs due to downtime.
The dynamic positioning system enables such a drilling unit to maintain position over the wellhead using ship's power alone.
CESAR
Authors: Hobson George D. 
Published: March 2010

Abstract
CESAR (Canadian Expedition to Study the Alpha Ridge), a program of the Department of Energy, Mines and Resources, was conducted from an ice station on the Arctic Ocean between March 30 and May 23, 1983. The base camp was established near 85 °52' north and 112 °34' west, 420 km north and west of Ellesmere Island and drifted in an irregular manner for the duration of the project. Preliminary disclosures were made at a one-day symposium (May 31, 1984) at the CMOS/COU meeting in Halifax. A digest of the geological and geophysical interpretations follows.
In cooperation with the Canadian Hydrographic Service some 1300 individual depth soundings and gravity measurements were established over the Ellesmere Island Continental Shelf and Alpha Ridge to the 116 degrees west Meridian. In addition, about 120 kilometres of echo sounding and gravity recordings were established along the drift track of the CESAR station. A 100-m contour bathymetric map and a 10-m Gal contour free-air gravity anomaly map have been compiled and include data collected from Ice Island T-3 between 1969 and 1974 just before grounding for several months off the northern coast of Ellesmere Island. Unlike the Lomonosov Ridge, investigated in 1979 during Project LOREX, the topography of the Alpha Ridge is complex and rugged, showing ridges, grabens, seamounts, etc. in profusion. The minimum depth recorded over the Alpha Ridge is 1087 m. The Alpha Ridge joins the Continental Shelf at a depth of between 1800 and 2000 m. In general, the gravity free-air anomalies mirror the ridge topography and, over this portion of the Continental Shelf, the gravity map reveals similar positive elliptical free-air anomalies that have been mapped all along the Canadian Arctic and the Alaskan Continential Shelf; these are considered to be indicative of the transition between continental and oceanic crust. Based on gravity data alone, the Alpha Ridge might be interpreted as continental crust.
During CESAR, sixteen Benthos piston cores and twelve gravity cores recovered as much as 6 m of sediment from the southeastern Alpha Ridge. In total to date, approximately 600 cores have been recovered and studied from the various ice stations in the Arctic Ocean. The cores provide the first information on the lithology and age of sediments covering the Alpha Ridge crest and adjacent grabens. Initial studies indicate a correlatable sequence of litho-facies that range in age from ate Cretaceous to Recent. The graben and basins on the flanks of the northern Alpha Ridge are filled with about 250 m of unconsolidated sediment of which the top 6 m is a continuous section of Lower Pliocene to Recent mud. Most facies of this mud can be correlated with U.S.G.S. cores from the Southern Ridge, western Alpha Ridge and Chukchi Rise. Planktonic and benthic foramanifera appear at intervals in the cores with coarse detrital material interspersed. Pollen has also been observed in the cores but is not as yet identified.
"Safety Offshore Eastern Canada"
Authors: Charchuk Noel 
Published: March 2010

Abstract
The Royal Commission Goint Federall Provincial) on the Ocean Ranger Marine Disaster that occurred on the Continental Shelf off Newfoundland and Labrador on February 15, 1982, was established to investigate the sinking of the Ocean Ranger. The first section of its report was made public in mid-August.
The conclusions reached by the Commission were similar to those of the U.S. Coast Guard and the National Transportation Safety Board. The disaster was caused by a chain of events, starting with a severe storm breaking the glass in the porthole of the control room, allowing seawater to contact the ballast control panel, causing short circuits. This event, in turn, caused the ballast control valves to open and close. The lack of knowledgeable crew intervention caused the list of the rig to worsen, until the chain lockers began to take on water, leading to the capsizing of the rig.
Several weaknesses in design were pointed out in the report. The location of the control room and the strength of the glass in the porthole were not satisfactory. The ballast control panel had many sensitive electronic controls which were not suitable for use in an area where seawater could conceivably enter. The openings to the chain lockers were not water tight and could not be pumped out so that when water began to enter, the severe list was worsened.
Also condemned in the report was the delay in starting search and rescue proceedings as well as the lack of adequate search and rescue capability stationed in St. John's. The second phase of the Commission's task began the, next week when a three day conference was held in St. John's.
The conference, Safety Offshore Eastern Canada, took place August 21 to 23 and featured an international cross section of experts. The reports and Submissions will be used by the Commission in preparation of the final report.
Representatives of various companies involved in the offshore regulatory bodies from other countries having offshore activities and consultants presented papers and discussions on environmental and design criteria, safety considerations and on excape and survival in cold ocean environments.
A further session of public hearings will be held in the fan prior to the final report of the Royal Commission.
Enhanced Oil Recovery: Retrospect And Prospect
Authors: Watkins G.C. , Sharp K. Chant 
Published: March 2010

Introduction
Outside of the ‘oil patch’, few people are aware that an oil reservoir normally will yield only a fraction of the oil held underground. However, much time and effort has been devoted to projects designed to recover a higher proportion of oil-in-place, to what in industry jargon is called enhanced recovery techniques.
At present, enhanced recovery schemes1 account for about one-third of Alberta's conventional recoverable crude oil reserves. And as in the fullness of timeexploration prospects suffer from depletion, the ability to obtain more from what has already been found becomes of progressively greater importance as a source of additional oil supply.
This paper looks at various aspects of enhanced recovery over the last decade or so, focussing on experience in Alberta where some 85 per cent of Canada's current conventional oil reserves is located. Trends in the nature and volume of reserves, costs, pricing provisions and economic incentives are examined. Finally, comments are made on the future outlook.

Enhanced Recovery Reserve Trends
Table 1 shows data for selected years on key features of Alberta oil reserves over the past decade. Over the 1973 to 1983 period, the
TABLE 1. Recent trends in Alberta oil reserves. Available in Full Paper.
average recovery factor for Alberta crude oil reserves fell by four percentage points [Column (2), Table 1], a reflection of a shift in the mix of reserves toward those with lower primary recovery factors especially heavy oil deposits such as Suffield and Provost. The relatively static volume of enhanced recovery reserves [Column (3) has somewhat reduced the share of such reserves in the over-all total [Column (4)] 2. The decline of late in the enhanced reserves recovery factor [Column (5) J is caused by the downward revision of many light and medium oil waterflood schemes. Examples here include Judy Creek BHL and Pembina Belly River.
In short, the story of the last decade is that enhanced recovery reserves have shown no distinctive trends: they account ow for much the same proportion of provincial reserves as they did in 1973;similarly, the average recovery factor for enhanced recovery schemes has remained virtually constant.
These trends seem disappointing in that although oil prices have been subjected to government controls nevertheless average wellhead prices rose over the decade by some $164/m3 ($26/bbl), an increase very considerably in excess of the rate of inflation. In other words, prices rose markedly in real terms. Ostensibly, suchan environment should and/or would ake the inception of new enhanced recovery schemes-especially those economically dubious at lower price levels more attractive and lead one to expect a strong growth in enhanced recovery reserves3. What, then, has happened to thwart the inception of more enhanced recovery schemes? The answer must lie in the interaction of the key elements of costs, ‘net back’ prices and technological scope. We look at each of these in turn.
Round-Up Of 1984 Tax Cases
Authors: Parsons Robert B. 
Published: March 2010

Abstract
Some years go by without Canada's courts hearing any tax cases of interest to the oil and gas sector. However, 1984 offered ample reading for the industry. This month, Tax Topics reviews four cases which could impact in some way on various aspects of doing business in the oil and gas industry. The score: Revenue Canada 2 – taxpayers 2. Read on.

Investment Tax Credits
The investment tax credit system was first introduced in 1975 as a means of stimulating capital expenditures in Canada. Under the system, taxpayers can earn a credit equal to a percentage of the actual cost of qualifying expenditures. The credit can be applied to reduce the taxpayer's federal income tax liability. The rate of credit varies from 7% to 35% of the cost of eligible assets. The determination of the amount and availability of the credit depend upon the asset's location, the type of asset, the activity in which it is employed, and the tax status of the taxpayer.
Section 13(7.1) of the Income Tax Act requires, generally speaking, that a taxpayer reduce the capital cost of a fixed asset by the amount of government assistance received by the taxpayer with respect to the asset.
In two recent decisions by the Federal Court, Trial Division, the court concluded that the income tax legislation did not require the taxpayers to reduce their capital cost of fixed assets for capital cost allowance purposes by the amount of investment tax credits claimed by the taxpayers during their 1975 to 1977 taxation years. Although these particular cases did not deal specifically with the oil and gas industry, the issue addressed by these cases should be of interest to any oil and gas investment which involved fixed asset acquisitions in the years 1975/77.
In the 1984 cases of AEL Microtel Limited vs The Queen and British Columbia Forest Products Limited vs The Queen, the court held that Section 13(7.1) did not apply from 1975 to 1977 to investment tax credits available under the Income Tax Act. The court noted that the intention of subsequent amendments to Section 13(7.1) in 1978 was to enact, in explicit language, that investment tax credits claimed by a taxpayer are to be deducted from the capital cost to the taxpayer. Since no such explicit provision was in the prior legislation, the court concluded that there was no intention that investment tax credits should reduce the capital cost. "The amendment demonstrates a different intention clearly expressed, but applicable only to the 1978 and subsequent taxation years." Revenue Canada has appealed the decision. In the interim. Revenue Canada has stated that their position remains unchanged.
In light of the decision, aggressive taxpayers may consider the possibility of adding the amounts of any investment tax credits claimed in the period 1975 to 1977 to the opening balance of the current year's undepreciated capital cost of fixed assets, if the amounts were previously excluded.
Heavy Oil Research In Saskatchewan
Authors: Hutchinson Jim 
Published: March 2010

Saskatchewan's estimated 25 billion barrel heavy oil resource presents a ajor business opportunity for the oil industry, a major economic opportunity for the province, and a significant source of supply of petroleum products for Canada. However, the nature of the oil -viscous and heavy, and the nature of the reservoirs-thin and heterogeneous -make it a difficult resource to recover, transport and process. Less than two per cent of our heavy oil resource is, at present, considered to be producible and of this less than half remains.
What are the opportunities and challenges that lie ahead? The 1990 demand for Saskatchewan heavy oil ranges from 100,000 to 150,000 barrels/day. Primary production by 1990 is expected to be between 50,000 – 60,000 barrels/day. Therefore, enhanced recovery of heavy oil will need to be between 40,000 and 100,000 barrels/day to meet the anticipated demand in 1990. This is a far cry from the present 9,000 barrels/day. Thus with the added complications of price uncertainty and diluent supply, the oil industry in Saskatchewan faces a major challenge over the next five years.
What can the government do to help? The Saskatchewan Government has made it a priority to encourage greater production and use of this very large, but elusive heavy oil resource in order to optimize the economic benefits to the province. The four-point strategy being used to realize this policy to increase heavy oil production has been designed to:Create a more attractive fiscal regime.Establish more secure markets for heavy crude.Stimulate the development of the technology and know-how needed to effectively recover and utilize heavy oil.Ensure environmental and land-use issues are addressed.
This article deals with the third point stimulating the development of new heavy oil technology.
New technology is not the factor that will drive heavy oil development-prices and markets will But new technology is needed to allow heavy oil development. Permit me an analogy. Current recovery technology is analogous to a family sedan. While prices may fuel activity and markets may provide a destination to set out for, it is enhanced recovery technology that is our vehicle to get there. Unfortunately, heavy oil represents very rough terrain. Our current recovery technology-the family sedan-is not likely to get us over this terrain, ven if prices provide the necessary fuel and markets provide a clear destination. What we will need to get over this rough terrain is new enhanced recovery technology that is the equivalent of a 4 by 4 off-road vehicle. That is, new recovery technology and know-how will be needed if we are to take full advantage of improved prices and markets.
How will we solve these technical problems? From a "funding" point of view, the oil industry is allocating funds to in-house research and to field pilot demonstrations. As well, the Governments of Saskatchewan and Canada have established The Heavy Oil Research Program, which is making $28 million available between April 1985 and March 1988.