bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stress Analysis Of Bent Sucker Rods
Authors: Bellow D.G. , Kumar A. 
Published: March 2010

Abstract
This paper describes an elastic analysis which can be applied to bent sucker rods to determine the effect of this imperfection on the stress behaviour or load-carrying capacity of the rod. It is shown that if the location of the bend in the rod is close to the sucker rod coupling, then high stresses can occur on the surface of the bend and this can seriously reduce the working capacity of the rod. Also, it is shown that for rods with bends in them a significant compressive stress can occur at the bend even though the rod is subjected to a large axial load. Experimental results are shown to agree quite favourably with the theory.
The problem of residual stresses in the rod is also discussed and a mechanism for analyzing this, problem is described along with some experimental results.

Introduction
A sucker rod passes through many operations and handling procedures from the time it originally takes its shape in the manufacturing industry until it is placed in a well in the field. To what extent do bends in a sucker rod influence the life of that rod when placed down a well? When a rod is permanently bent, plastic deformation has taken place; this not only reduces the flexibility of the rod, but, in the area of the, bend, the residual stresses can accelerate corrosion.
The object of this paper is to describe a means of evaluating the significance of bends on the -elastic behaviour of a sucker rod and provide a design formula for use in determining an acceptable degree of bend. Some experimental results are also presented which show the extent of plastic deformation that has occurred as a function of observable bends in a rod.

Theoretical Considerations
In the theoretical analysis, it was assumed that the initial shape of a bent rod could be represented by two straight lines, A-C and C-B, which meet at an apex called the bend position. The bend position is identified by dimension "a" and its location from one of the ends "c", as shown in Figure 1. It was also assumed that such a rod was bent before final heat treatment and therefore no residual stresses would be present when an axial load was applied. Thus, the analysis is a simple one of elastic behaviour of an initially bent circular rod. When the rod has been bent after heat treatment, there will be residual stresses and the total stress picture must be obtained by considering the elastic stresses added to the residual stresses. This is discussed in the treatment of the experimental program.
The procedure for the elastic analysis was based on attempting to provide a mathematical model which could be checked by experiment. Because the experimental apparatus available for loading a sucker rod was limited to one of the testing machines in the laboratory it meant that the segment of the rod had to be kept within 6 feet.
Deep Well Casing Cathodic Protection Requirements
Authors: Schellenberger Brian G. , Ingram William O. 
Published: March 2010

ABSTRACT
Failures of well casings as a result of external corrosion on bothcathodically protected and unprotected wells in the South Swan Hills Unit havebeen investigated. Previous testing indicated that an instantaneously appliedcurrent of 30.0 amperes would not provide adequate protection throughout thecorrosive Wabamun D-1 water-bearing zone which exists throughout the unit atdepths ranging between 1,676 m (5,500 ft) and 2,195 m (7,200 ft).
A four-well pilot project was initiated in early 1977 to determine if 30.0amperes and polarization would provide adequate cathodic protection throughoutthe D-1 zone. The results of the pilot project indicated that cathodicprotection with 30. 0 amperes and polarization is possible throughout thecorrosive zone and that cathodic protection currents can be successfullyprojected below high-resistance zones.

Introduction
The South Swan Hills Unit is located approximately 225 km (140 miles)northwest of Edmonton, Alberta (Fig. 1). The field was discovered in 1961 andwas placed on production the following year. The total daily Unit production isapproximately 9,540 m3 (60,000 barrels) of oil and 9,540m3 (60,000 barrels) of water from 161 producing wells. The Unitcontains a total of 228 wells.
A typical downhole diagram of a South Swan Hill Unit well is depicted in Figure 2. The average total depth of the wells in the Unit is 2,469 m (8,100ft) and the average calculated cement top is 1,280 m (4,200 ft). The wellsproduce from the Beaverhill A and B formations.
A total of 13 leaks attributed to external corrosion have been experiencedin Unit wells since 1966. As shown in Figure 2, the leaks have occurred in twodistinct ranges: 8 between 894 m (2,900 ft) and 1,340 m (4,400 ft) on wellsdrilled with low-pH gyp starch mud, and 5 between 1,890 m (6,200 ft) 2,286 m(7,500 ft) on both non-gyp starch and gyp starch mud wells. The corrosionoccurring over the lower level is attributed to the water-bearing Wabamun D-1zone. Previous testing had indicated that cathodic protection over the D-1 zonemay not be possible in the South Swan Hills field.
Deep-hole, High-temperature Submersible Pumping
Authors: Mustard R.W. , Van Heukelom J.C. 
Published: March 2010

Abstract
There were 96 electric submersible pumps operating in the harsh environment of the 230 °F (110 °C) Beaverhill Lake formation of the South Swon Hills Unit at the end of 1977. Here 95% of the pumps are installed in 4-1/2-in. (114-mm) and 5-1/2-in. (140-mm) casing at an average depth of 8,000 ft (2,438 mi. A miscible flood covering half of the Unit contributes to an average producing GOR of 1,100scf/STB (195) and a number of wells produce with GOR's in excess of 2,000 scf/STB (354). These conditions of close tolerances, high temperature and high GOR have resulted in many operational problems. A number of procedures which have been developed to improve pump performance are presented.

Introduction
The Swan Hills oil field is located 140 miles (225 km) northwest of Edmonton, Alberta (Fig. 1). The Amoco-operated South Swan Hills Unit (Fig. 2) was formed in 1962, with 193 wells on 160-acre (64.8-hectare) spacing. Production is from the 230 °F (110 °C) Swan Hills formation of the Beaverhill Lake group, a limestone reef complex. Waterflooding commenced in 1963, and was expanded from 5 to 22 injection wells by 1972.
In 1973, a secondary recovery miscible flood project was initiated in the central portion of the field. This project consists of alternate injection of enriched gas solvent and water (1973-1978), dry gas (1979-1987) and then water (198B-200B). The first electric submersible pump was run in January, 1971. By the end of 1977 there were 96 submersible pump installations. The Unit was producing approximately 60,000 BOPD (9,540 m3/day) and 60,000 BWPD (9,540 m3/day) at this time.

Production History
Production performance for the miscible flood area, since the first submersible pump was installed in 1971, is detailed in Figure 3. There are 95 producing wells in this area. By the end of 1977, 63 (66%) were submersibly pumped, producing 80% of the oil. Twelve of the producers were flowing, and the remainder were beam pumped. The average GOR's has risen from the solution GOR of about 750 scf/STB (133) to as high as 1,330 scf/STB (229) in 1976. Miscible fluid breakthrough in several wells has resulted in periodic GOR's as high as 10,000 scf/STB (1,772). The combination of small production casing I.D.'s and high GOR's has caused severe submersible pump operating problems.
Figure 4 is a production plot for the west waterflood area. There are 52 producers in this area. By the end of 1977, 33 (63%) were submersibly pumped, producing 85% of the oil. The remaining producers were beam pumped. No submersible pumps have been installed in the east waterflood area of the South Swan Hills Unit- This area is located off the main reef build-up and total production averages less than 200 BOPD (32 m3/d).

Submersible Pump

Equipment Configuration
The downhole submersible pumping equipment (Fig. 5) consists of the pump assembly (centrifugal pump, gas separator, motor protector and motor), No. 4 lead sheathed flat cable to the top of the pump, and high-temperature No.6 flat cable to the pothead connection at the motor.
A Reserves Review of the Pembina Cardium Oil Pool
Authors: Purvis R.A. , Bober W.G. 
Published: March 2010

Abstract
The Pembina Cardium pool was divided into 43 study areas having more or less similar properties and production characteristics. A performance forecast was made for each study based on its average properties and historical decline. Estimates of initial established reserves were made for economic limits of 8, 6 and 4 b/d/well. A production and performance forecast for the entire pool was then made by summing the forecasts for each study area. Harmonic decline was observed for many of the study areas and for the pool as a whole. Consequently, plots of fluid rates and 1 + WOR versus cumulative oil recovery facilitated extrapolation of the historical decline.
The estimates of the pool reserve are very sensitive to the economic limit and vary from 1.3 to 1.5 billion barrels for the 8- and 4-b/d/well cases, respectively. The limiting water-oil ratios depend on rock quality and are forecast to vary from 0.3 to over 40. Although the predominance of laboratory flood data indicate a residual oil saturation of about 35 per cent, values of 44 and 50 per cent were used for the Upper and Lower Sand members, respectively. The latter values were based on a recent special core analysis for a well drilled 300 feet from a water injection well.

Introduction
The Pembina Cardium pool was discovered in 1953 with the successful completion of Socony-Seaboard Pembina No. 1 (4-16-48-8 W5M), some 70 miles southwest of Edmonton. The early development and performance history of the pool has been the subject of several papers (1,2,3,4). The pool currently has some 4400 operated wells and has produced over 876 million barrels of oil and 700 billion cubic feet of solution gas.
The most distinguishing feature of the pool is its large area, stretching 60 miles east to west and 40 miles north to south. The reservoir is an immense stratigraphic trap which, despite its size, has neither a bottom water zone nor a gas cap. The Cardium zone is extremely heterogeneous, and is composed of two easily recognizable sand members which in places are overlain by a highly permeable conglomerate member. The bulk of the displaceable oil is in the Upper Sand, a fine grained, well-sorted quartzose sandstone interbedded with shale laminae. The thickness of the Upper Sand ranges from 0 to 25 feet, having been completely eroded in places. The Lower Sand is 10 to 35 feet thick, is generally very fine grained, and contains numerous shale lenses.
Some 2800 wells have been cored, including 27 with oil-base mud. The Cardium formation has a low connate water saturation despite the low permeability throughout much of the pool. Based on oil-base core data, and correlations of connate water saturation with porosity and permeability, net sand pay has generally been defined as having a porosity greater than 9 per cent and a permeability greater than 0.1 millidarcy. The net pay is very sensitive to the level of the permeability cutoff.
International Energy Financing-implications For Canadian Energy Developments*
Authors: White N.A. 
Published: March 2010

Abstract
This paper identifies and discusses the principal determinants of the future financial requirements of the energy resource industries for their world-wide operations. Factors discussed include the amount of finance required, alternative methods of financing and sources of funds.
Comparisons are made between Canada's energy industries requirements and those of the U.S.A. and the U.K. It concludes that Canada's requirements are propornonately greater on a per-capita basis.
Similarly, the Canadian petroleum producing industries requirements are examined in the context of those of the international petroleum industry. This shows that the unit investment cost of Canadian petroleum supplies is likely to be considerably higher than the average unit cost of Western World*** supplies. It also demonstrates a sharp? divergence between the financing patterns of the Canadian and international industries.
The paper also discusses the role of international capital markets in providing funds for Canada's energy developments in the future and suggests that such sources may not be as helpful as might initially be expected and that competition for such funds may be quite strong.
The paper concludes that a larger amount of finance in the future will have to be in the form of project-related loans. It suggests that these may be assisted if a new form of private-sector financial institution could be formed to provide third-party guarantees for such loans. Without this, it is feared that greater government intervention may be unavailable.

Introduction
The theme assigned to me for this address embraces a wide range of issues, including questions such as: What will be the capital requirements of the world's energy industries to the year 2000? Where will the necessary funds come from? Will there be a need for new methods of financing? What factors might frustrate the efficient development and financing of the world's energy resources? These are important issues, and the answers are far from obvious at first glance, but for this occasion I have been asked to examine the implications of these issues for Canadian energy resources and especially for the future development of the Canadian petroleum producing industry. For a visitor to talk about the future development of domestic industries is always a daunting and often a hazardous task. I therefore approach it with a certain degree of trepidation. I am also reminded of the Arab proverb:
"Those who foretell the future lie, even if they tell the truth."

Determinants of Financial Requirements
The future financial requirements of the energy resource industries will be primarily determined by the following basic factors:
market needs for energy; technological! geological complexity of resource recovery; environmental hostility at resource location; level of annual rate of inflation; political costs.
Based on past trends, the growth rate in market needs for energy will match (or at least be linked with) the prospective rate of growth in economic activities.
Obtaining Open-hole Cement Plugs On The First Attempt
Authors: Salahub W.F. , Ripley H.E. 
Published: March 2010

Abstract
The four common reasons for setting open-hole cement plugs are reviewed. Factors which influence the condition of a cement plug, as well as the various plugging techniques, are outlined. The effects of auxiliary equipment, spacers, flushers, drilling fluid and the cement slurry are discussed individually with emphasis on techniques and materials that eliminate the uncertainty of plug placement. A recommended job sequence for a typical cement plug placement is presented. Supportive data in the/arm of case histories from Western Canadian wells are reviewed.

Introduction
There are many reasons why an operator may decide to set a cement plug in his well. Regardless of the reason, he wants a plug that will satisfy the required conditions on the first attempt. Unfortunately, this is not always obtained.
Many people consider the setting of a cement plug to be one of the simplest operations performed on a well. This attitude is easy to acquire if the only cement plugs previously placed were those for abandonment purposes. Often abandonment plugs are recorded "as found" when they will support a few points on the weight indicator.
The stresses placed on a cement plug for sidetracking or testing, however, are much more demanding. Cement that is diluted and contaminated with drilling fluids will not gain sufficient strength to support DST tools or a whipstock, or prevent the bit from re-entering the original hole. Setting an open? hole cement plug for sidetracking or testing requires planning and precise execution or it can develop into an expensive, timeconsuming operation.
This paper will review the main purposes for setting openhole cement plugs and the well conditions that are often present during the placement operation. The various techniques that are used to place cement plugs and the problems that are encountered are discussed. Field-proven techniques and equipment used to ensure competent cement plugs are presented in point form and discussed in detail. Finally case histories of plugging procedures and results on wells in Western Canada are given (Appendix).

Purposes of Wellbore Plugs
A cement plug is set in an open wellbore for one of at least four reasons. These are:to provide a solid bottom and plug while sidetracking the drilled hole, while bypassing unrecoverable junk or while straightening a crooked hole(l);to seal open hole below a casing seat or zone to be tested;to overcome a lost circulation problem;to abandon a dry or depleted well.
During a drilling operation, problems may develop which make it desirable to sidetrack the drilling. This can be due to loss of junk in the hole, such as tools or pipe, which cannot be recovered by fishing methods. Sidetracking may also be necessary to ensure that the drilling target is reached. Regardless of the reason for sidetracking, the cement plug in the original wellbore should be harder to drill than the formation around it. The cement must be given adequate time to allow it to gain sufficient compressive strength before the sidetracking operation begins.
The Wizard Lake D-3A Pool Miscible Flood
Authors: Young Marshall N. , Martin W. Earl 
Published: March 2010

Abstract
A hydrocarbon miscible flood was initiated in the Wizard Lake D-3A pool in late 1969. The scheme involved placing a slug of LPG at the gas-oil interface, and displacing it vertically downward with dry gas while injecting water to stabilize the oil-water contact. Ultimate recovery is expected to be 323 million stock tank barrels, 84per cent of the original oil-in-place and 69 million stock tank barrels higher than under primary depletion.
The Wizard Lake D-3A pool, located in central Alberta, is one of nine Devonian reef pools connected to the Cooking Lake aquifer. It is a dolomitized bioherm reef with a maximum original oil zone of 648 feet. The pool was considered an ideal candidate for a miscible displacement process because of its vertical relief, small areal extent and the absence of any barriers that would be detrimental to displacement of the slug.
This paper reviews the implementation, monitoring techniques and performance of the miscible flood scheme.

Introduction
The Wizard Lake D-3A pool, located 55 kilometres (35 miles) southwest of Edmonton, as shown in Figure 1, was discovered in April 1951 with the drilling of Texaco Wizard Lake Crown 'B-I in 12-22-48-27-W4M. The pool, drilled on 4D-acre spacing, was fully delineated by the late nineteen fifties.
The reservoir is a dolomitized bioherm reef of Devonian age which is part of a prolific chain of Leduc member reefs appropriately known as the Golden Trend. The productive horizon attained a maximum recorded height of 197.5 metres (648 feet) above the Cooking Lake aquifer in which reef growth was initiated. The Cooking Lake aquifer pinches out to the west, but is extensive in the other three directions. This aquifer is very active and is common to other oil and gas accumulations which give rise to interference between pools (Figures 2 and 3).
The oil column covered an area of 1,507 hectares (3,725 acres) at the original oil-water contact of 1,230 metres subsea (4,034 feet subsea). Figure 4 presents a structure contour map of the top of the pool based on the gross reef section. The initial oil-in-place is estimated to be 61,200,000 m3 (385 MMSTB), with some 6.5 × 109 m3 (231 bcf) of solution gas dissolved in it.
The primary recovery mechanism, identified as a combination of gas expansion, water drive and gravity segregation, was allowed to continue until 1969, when a slug-type hydrocarbon miscible scheme was initiated (Fig. 5). In 1965, a secondary gas cap began to form and by the end of 1969 there existed a 24-metre (78-foot) gas column containing approximately 152 × 106 m3 (5.4 Bcf). Also, by 1969 the oil-water contact had risen by 15 metres (50 feet); leaving an relatively small quantity of available core and thus a method had to be developed to Overcome this shortcoming and also handle the edge effect on porosity that is characteristic of reef pools(1).
A Radial Model For Estimating Heat Distribution In Selective Electric Reservoir Heating
Authors: Harvey A. Herbert , Arnold M.D. 
Published: March 2010

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

Introduction
We have been investigating the possibility of using an alternating electric current to heat portions of an oil reservoir that are normally bypassed by injected fluids(1,2). Canadian and U.S. patent applications are pending on the process.
Electric heating is accompanied by water injection, and the process is expected to increase oil recovery in a waterflood. In a pattern flood, the application of heat to parts of the pattern that are normally bypassed by injected fluids will usually improve the mobility ratio at the displacement front, because the viscosities of most crude oils are more temperature-sensitive than the viscosity of water.