bluuebunny/crossref_metadata_2025 huggingface dataset:
Of “Superfluous And Tedious Statutes ”
Authors: Parsons R.B.
Published: March 2010

Nobody knows better than the petroleum industry that the legislative network confronting the industry is one of Canada's most infamous growth stories, as this country's legislators continue to complicate the income tax and other laws. At some magical point, there is presumably some balance to be struck between legislation which is equitable and unambiguous on the one hand, and at the same time is efficiently complied with and administered. It is becoming increasingly clear that the legislation is not in balance, and that there is a pressing need for some simplification of the income tax rules and regulations —especially in areas of critical importance to the resource industries — even though such simplification will likely involve some sacrifice of equity and certainty.

Introduction

"I would wish that...the superfluous and tedious statutes were brought into one sum together, and made more plain and short, to the intent that men might better understand them." Edward VI, King of England 1547–1553.

Regal decree notwithstanding, the legislation of most developed nations continues to become more complex, lengthy, and confusing than ever before. Canada's income tax system cannot escape the accusatory finger pointing at examples of this serious problem which plagues all of us today.

Although many areas of our tax law could easily warrant some degree of simplification, for those who are involved with this country's resource sector, that horrendous, almost unreadable, part of our tax legislation which deals with resource taxation must be regarded as a prime candidate for simplification.

In recent decades, but particularly in the past ten years since tax reform in 1972, budget after budget, both federal and provincial, have amended, massaged, modified, and manipulated the resource tax rules to the point where not only are taxpayers totally lost in their attempts to make some sense of the entanglement of rules, but also the draftsmen themselves acknowledge that the outer limits of complexity are being reached, and that the whole set of rules is on the verge of grinding to a groaning halt under its own weight of nonsense and frustration.

In fact, the petroleum industry probably suffers considerably more than other industries, in terms of having to deal with complex fiscal regimes. No other industry has to face the multiple perils of the Petroleum and Gas Revenue Tax, the Natural Gas and Gas Liquids Tax, the Incremental Oil Revenue Tax, and the Petroleum Compensation Charge. In addition, each of the producing provinces levies its own production royalties, with rates and bases varying from province to province, and even within a province depending on the type of oil, the age of the discovery, and other factors.

The clamor for simplification of the tax system is nothing new, but little, if anything, has been done about it. Why not? The easy answer is that "nothing can be done about tax simplification ". This answer is unacceptable! As this article suggests, something can be done about minimizing the complexities of our income tax legislation.
Oin And Gas Prices-a Moving Target
Authors: Parsons Robert B.
Published: March 2010

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

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

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

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

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.
Simulation Of A Directly Miscible Vertical Dlisplacement Hydrocarbon Solvent Flood
Authors: Bennion D.W. , Stewart B.
Published: March 2010

A simulation of the performance of the hydrocarbon miscible flood in the Rainbow Keg River ‘E’ Pool is presented. The reservoir has been under continuous hydrocarbon solvent injection since June 1972. The direct contact miscible flood is being conducted downward in a maximum oil column of172 m.

A review of the geology, rock and fluid characteristics is given. The pool was produced on primary depletion from July 1966 to August 1967, and shut-in from August 1967 until the solvent injection commenced in 1972. The black oil model history match of the primary depletion and shut-in is presented. The hydrocarbon solvent flood performance was modeled using J.S. Nolen and Associates' Miscible Vectorized Implicit Program. The simulation study provided an estimate for the efficiency of the hydrocarbon solvent flood of the ‘E’ Pool.

Introduction

The Rainbow Keg River ‘E’ Pool was discovered in March 1966. The discovery well penetrated a small biohermal pinnacle reef of Middle Devonian age located in the Rainbow Lake Area of Alberta (Fig. 1).

The pool began production under primary depletion in June 1966 and was shut-in in August 1967. Due to the initial in-availability of miscible fluid the pool was shut-in for 56 months until May 1972 when injection was commenced.

The solvent injection commenced in May 1972. Solvent breakthrough occurred in the two producing wells two to three years later. The third or last well was drilled and completed in ‘E’ Pool in 1978. This well produced solvent immediately even though it was placed in an area of the pool opposite to the two former wells. The field solvent-oil ratio in late 1982 was 650 m3/m3 with a cumulative oil production of approximately 1100 × 103 m3 or 33% of the original oil-in-place (OOIP).

This paper discusses the rock and fluid properties. It also describes the reservoir simulation history match of the primary and solvent injection periods. Following the history match the future performance of the reservoir was predicted.

History

The discovery well of Rainbow Keg River ‘E’ Pool was the 7-18-109-7 W6M well (Fig. 2). It was spudded on 1966-02-22 and drilled to a depth of 2018 m penetrating 172 m of oil-bearing Keg River Reef. The well was completed 89.8 to 83.7 m above the original oil/water contact (AOOWC) in April 1966 (Fig. 3).

The pool went on production in July 1966 and continued until August 1967 when it was shut-in. The production data are shown in Figure 4. The pool produced 51 × 103 m3 of oil with no water. The gas to oil ratio (GOR) was very erratic.

The initial pool pressure was 17 408 kPa at the mid-point of the perforations (MPP) as shown in Figure 5. There were four pressure surveys during the primary production period. The MPP pressure decreased 3524 kPa to the end of the primary depletion. The pressure was recorded eleven times during the shut-in period. The MPP pressure increased 795 kPa during the shut-in period from September 1967 to March 1972.
Is Gasoline Overpriced?
Authors: Cleland N.A.
Published: March 2010

Introduction

Changes in the price of gasoline cause more concern to consumers than changes in the prices of almost any other item which are purchased on a regular basis. Recent dramatic decreases in the price of crude oil, of which everybody is aware, have not resulted in the same degree of decline in the price of gasoline. Why is this?

The purpose of this paper is to identify who gets what from the price of a litre of gasoline so that one will be able to answer the question "is gasoline overpriced?". First, the most recent results of the quarterly survey of Ontario gasoline pump prices, made by the Petroleum Resources Communication Foundation, will be compared with the survey results in January 1986, when crude prices were at their peak. Then, these current data will be compared with the results in January 1986 for Quebec and Alberta.

To give a broader overview, Canadian gasoline prices will be compared with the most recent information available for prices in the United States (U.S.) and United Kingdom (U.K.). Like Canada, both of these countries are oil producers as well as oil consumers.

The Petroleum Resources Communication Foundation (PRCF) supplied most of the basic data used in this paper. PRCF was formed in 1975 with the objective of increasing public awareness and understanding of Canada's petroleum industry. It is supported by 100 different companies and has established a reputation for providing factual and objective data on the industry.

Ontario Gasoline Prices

In January 1986, Ontario pump prices for regular unleaded gasoline at full-service stations average 53.5 cents per litre, with an average crude oil price at the wellhead of $37.50 per barrel. In the first week of April 1988, pump prices for the same gasoline in Ontario averaged 48.5 cents per litre with an average crude oil price of $20.66 per barrel. The consumers' reaction is, of course, if crude price fen by 45%, why did gasoline only fall by 9%? Is the consumer being treated fairly?

If the breakdown of gasoline prices is examined, then it can be established if the consumer has received the full benefit of falling world oil prices over the last 27 months. How much of the total price is in fact made up of the cost of crude oil?

Gasoline

The price of gasoline is shared as follows:

Dealer Margin

This is the amount charged by the service station operator. In Ontario, this margin varies from station to station with a range from 0 to 10 cents per litre. The average for the four major companies was 3.9 cents per litre in April 1988. It has declined by 0.6 cents per litre since January 1986. All the costs of operating the service station come from this margin of 3.9 cents.

Provincial Tax

This tax varies from province to province, with the lowest tax in Alberta at 5 cents per litre and a maximum of 14.4 cents per litre in Quebec.
Bending Stresses In Otherwise Straight Sucker Rods
Authors: Bellow D.G. , Howe R.K.
Published: March 2010

In many cases sucker rods fail in the upset portion near the pin end. This may be due to bending stresses resulting from lack of straightness in the rod, even though it was manufactured to be within the API Specification 11B. A number of new, unused rod coupling pairs were analyzed for straightness and a model was developed to predict the bending stresses. It was found, that for some rod coupling configurations, there existed bending stresses as high as 68% of the axial stress. This suggests that the API 11B Specification may not be stringent enough.

Introduction

Research into sucker-rod problems has been ongoing for 50 years or more, resulting in several significant improvements in rod-coupling performance. Nevertheless, failures of rod strings continue to be a problem for the oil producer. As down-hole components get older and well conditions become more corrosive this problem will become more severe. However, there are three avenues which can be followed to alleviate the problem:Reduce the loads on rods appropriate to the specific well conditions (dog-leg, etc.) and environment (i.e. apply more stringent design service factors).Replace current rods using materials with improved properties.Improve the current design and manufacturing techniques to eliminate the weaknesses inherent in existing rod strings.

While (1) above may not be practical except under a total replacement program and (2) requires long-term research and careful examination, (3) may provide the most benefit In the short term but, like (1), would only apply to replacement rods and strings.

The purpose of this paper is to describe a problem related to the third category involving the lack of straightness in suckerrods which are made within API 11B Specification(l). It will be shown that non-straight rod ends can lead to undesirable bending stresses near the upset pin-end.

Statement of Problem

For the purpose of this study, a rod end is defined as the length from the pin end to a point 860 mm (34 in.) back towards the rod body. The rod end is defined as non-straight if its centre line deviates from a theoretical centre line with extends through the pin.

To examine bending stresses in non-straight rod ends, a dimensionless bending stress ratio (DB) is dermed as:

Equation (Available In Full Paper)

The dimensionless bending ratio (DB) can be defined in terms of the axial load P, second moment of area I, cross-sectional area A, and y the distance from the theoretical straight line to the rod centre. Thus,

Equation (Available In Full Paper)

In an earlier work(2) it was shown that bending stresses can be determined in rods of uniform cross section with sharp bends in them by considering elementary beam theory where the bending moment M is given by

Equation (Available In Full Paper)

and yo-y = deflection of bar from the unloaded position, EI is the rod stiffness and z the distance along the rod as measured from the pin end.
Upgrading Alberta Ngls - Some Preliminary Ideas
Authors: Onn William D.
Published: March 2010

The objective of this paper is to provide an overview as to why Alberta should be looking at NOL (natural gas liquid) upgrading. There are a number of factors in the global NGL environment as well as in Alberta that point to the need to add value. In addition, several approaches to NGL upgrading which have not been commercialized in Alberta or Canada are described. The emphasis will be commercial, not technical, and an attempt is made to put the project in an Alberta context. It should be noted that the projects described are examples only, and that there are a number oj other processes and projects which could add value to Alberta's NOLs. Finally, it must be emphasized that the analysis particularly the economics, should be considered directional and preliminary.

Introduction

There are several trends under way in the industry which may result in excess, NGL supply and pressure on NGL pricing.

Increased Worldwide NGL Availability

Since the late 1970s/early 1980s, many countries, particularly the major OPEC producers, have built facilities to extract NGLs from gas produced in association with oil. Saudi Arabia's "Master Gas System", with capability of approximately 38 000 m3/d of LPG (liquid propane gas), double previous capacity, is a prime example of this development. The facilities were built when OPEC was producing nearly double the amount of oil produced today, and when continued growth was expected. With much lower oil production, significant OPEC NGL extraction capacity, estimated at about 95 000 m3/d of LPG excluding Iran and Iraq, is underutilized. This represents roughly 15% of current consumption. As OPEC oil production increases over time, this capacity will be used to produce additional LPG, whatever the conditions of the market at the time.

One result may be continuing pressure on prices, particularly prices relative to other energy products. The impact of excess LPG production may already be materializing as evidenced by the LPG/crude oil price trend. LPG and crude oil are roughly at price parity on a BTU basis, significantly lower than the approximate 1.2 ratio during the latter half of the 1970s and the 1.1 to 1.5 ratio over the last ten years. While price volatility makes it difficult to be precise about this trend, it does appear that a long-term drop in the ratio is under way.

Reduced Gasoline Volatility in U.S.A.

Because ozone levels in the U.S. exceed legal limits in areas containing over 40% of the country's population, the Environmental Protection Agency (EPA) has proposed to significantly reduce gasoline volatility. The mechanism would be to reduce the gasoline Reid Vapour Pressure (RVP) during the mid-May to mid September period in two steps: a 1 RVP drop in 1989 followed by an additional 1.5 reduction in 1992. This is a significant change in relation to the current RVP average of approximately 11. The easiest approach to reducing RVP is to back out direct blended n-butane from the gasoline pool. While n-butane has a high octane and is relatively inexpensive, it has a very high RVP, approximately 52.
International Trade Implications For U.S.S.R. Sulphur In The 1990S
Authors: Wenzel Werner J.M.
Published: March 2010

Major expansions in the processing capacity of natural gas and crude oil are bringing the U.S.S.R. into the forefront as one of the largest producers of recovered elemental sulphur. Annual production capacity for elemental sulphur, oil and gas processing and mining in the U.S.S.R. may be expanding from 5.7 Mt/yr in 1987 to almost 12 Mt/yr by the year 2000.

The U.S.S.R. is preparing to enter offshore export markets. A major sulphur prilling, storage and rail car loading facility is to be built at the large Astrakhan gas plant complex located northwest of the Caspian Sea. Initial annual export capacity of 1 Mt can be expanded to 3 Mt at a later date. An offshore sulphur terminal is planned for a port near Odessa on the Black Sea.

Tenders for prilling, storage and rail car loading facilities were submitted late in 1987. As of this date no commitments to commence construction have been made. Construction and commissioning is estimated to take 1.5 to 2.5 years.

It is currently estimated that the U.S.S.R. could participate in the world market with relatively modest volumes of sulphur by 1991 and increase its presence judiciously thereafter following a build-up of strategic inventories.

In the longer term and about the year 2000, the U.S.S.R. is likely to balance supply and consumption of sulphur in all forms at the 14 Mt level and net exports may be insignificant. The U.S.S.R. is, in the foreseeable future, unlikely to become a major long-term exporter of sulphur.

Introduction

In this paper estimated sulphur production is probed in various forms and estimated sulphur consumption in all forms in the U.S.S.R. to the year 2000.

Long-term predictions about the production and consumption of sulphur anywhere in the world are certain to be incorrect. Like Columbus, the best that can be done, is chart a likely course and correct frequently, using the best information obtainable.

Technological changes related to the manufacture of fertilizers and industrial goods, advances in genetic plant engineering, changes in world weather patterns, fossil fuel energy demands, energy and transportation costs, reservoir behaviour and econopolitical upheavals are only a few of the variables that make predictions indeed a difficult task.

Production of Elemental Sulphur

Production of elemental sulphur in the U.S.S.R. is derived from three sources: desulphurization of natural gas and oil, Frasch mining and open pit mining. Other forms of sulphur are derived mainly from pyrites.

TABLE 1. Estimated supply of sulphur in all forms in the U.S.S.R. (000 tonnes). Available in Full Paper.

Table 1 provides an overview of estimated sulphur supply in all forms to provide a better all encompassing overview that can be compared to sulphur consumption in all forms.

Table 2 gives an overview of the major producing sources of recovered sulphur. Growth in the U.S.S.R. sulphur production can be attributed almost solely to gas and oil processing capacity expansions now under way or planned.
An Overview Of Bank Security For The Oil And Gas Professional
Authors: Laffin Michael J.
Published: March 2010

Introduction

Initially involvement by banks in the oil and gas industry was limited to production loans. However, in today's climate of mergers, takeovers, megaprojects, relatively low oil prices, and because of the need for external financing, banks are becoming increasingly involved in financing oil and gas undertakings. Therefore, it is incumbent on well-informed and interested engineers and geologists to be aware of what security banks will request before they lend money to an oil company, and the advantages and disadvantages of each type of security. This paper presents an overview of the various types of security that banks request from an oil company before they advance money to that company, in an effort to provide technical professionals with a working knowledge of concepts and documents they may encounter when dealing with banks.

The first section of this paper examines debenture security with a view to explaining what is a debenture, the various types of debentures, and what happens should a borrower default under the terms of a debenture.

Section 177 security is addressed in the second section of this paper. This type of security, while once the only type of security taken by lending Institutions when dealing with oil and gas properties has given way to the debenture and is now used primarily as a corollary to debenture security. Section 177 security raises several questions and has numerous potential uncertainties, some of which will be examined in this section.

In addition to debenture security and Section 177 security, banks often request that borrowers execute assignments that allow a specific revenue stream or several revenue streams received by the borrower to be diverted to the bank. Section 3 of this paper examines a few of these types of assignments.

Debenture Security

In almost every commercial transaction, whether it be a loan by a bank to a company or a sale of shares and/or assets from one company to another, certain basic documentation is used to secure repayment of the loan or the payment of the purchase price for the shares or assets - one of the most fundamental documents used to secure repayment is the debenture.

What is a Debenture?

The broad definition given to the term "debenture" is that it is a written document evidencing the indebtedness of the company issuing the debenture, which is either secured or unsecured and which may be negotiable. A debenture is "secured" if it gives the holder of the debenture a mortgage or other security on the assets of the company issuing the debenture that may be used should the debtor fail to make payment. An "unsecured" debenture is merely evidence of the debt, and upon default by the borrower the lender has no recourse other than to sue on the debenture. A document is "negotiable" if it is legally capable of being transferred by endorsement or delivery, for example, cheques, stocks and bonds, and promissory notes are usually negotiable in that they can be transferred or sold freely and without notice from one corporation or person to another.
Computer Model Evaluates Oil Pumping Units in Inclined Wells
Authors: Lukasiewicz S.
Published: March 2010

The paper analyzes the dynamic behaviour of the sucker rod string in the inclined well. In this case, due to the curvature of the tubing the rod vibrates longitudinally as well as transversally. A mathematical model of the vibrating string consisting of two coupled differential equations was developed. The paper describes the fundamental assumptions and simplifications which can be used in the numerical analysis. The examples of the results are also presented. They include the effect of the distortion of the geometry of the rod string on the plunger load-displacement diagram and the diagram of the friction forces along the rod string.

Introduction

The evaluation of pumping units in the inclined wells has been a serious problem in engineering practice. The common practice at present is the application of the program developed for vertical wells to the analysis of deviated wells. This introduces substantial errors in the calculations of the stresses in the rod string and as regards the gearbox torques. Generally, the maximum torques calculated properly for the actual geometry of the slant hole pumping unit can be up to 40% larger than the corresponding values obtained from the calculations for vertical units. Besides, the application of the program for vertical wells to the evaluation of inclined, wells gives results in which all the friction forces from the rod string are concentrated at the plunger. This gives false prediction of high compressive forces at the bottom of the rod string and can be the reason for the wrong conclusions regarding the rod stability.

The rod in the inclined well is under different static and dynamic forces than in the vertical one. It is supported by the tubing of wheeled couplings but it is also transversely loaded by its own weight. Therefore, the dynamic behaviour of the sucker rod in the deviated well is much more complicated and different from a vertical one. The differences are caused by the friction between the rod string and the tubing and the rod curvature. If the tubing is curved, the dynamically loaded rod string deforms and comes into contact with the wall of the tubing. The curvature causes the lateral displacements of the rod inside the tubing. It couples the longitudinal vibrations with the transverse vibrations. The axial compressive forces at the bottom of the well can buckle the rods. In this case, the problem becomes nonlinear and difficult to solve.

The need to obtain a model for use in the evaluation of pumping units and downhole equipment in the inclined and deviated wells resulted in the development of an applicable design and optimization technique. SRPUMP computer program was developed a tool that allows a high level of expert knowledge to be applied daily in the field, dealing with problems of the inclined wells.

Fundamental Assumptions

An accurate prediction of the performance of the sucker rod string and the bottomhole equipment requires careful modelling of the dynamic behaviour of the rod.