bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbon Dioxide For Enhanced Oil Recovery In Canada
Authors: McDonald S. , Mandybura F. , Sparks N. 
Published: March 2010

Abstract
major miscible so/vent in Canada and describes Shell Canada's carbon dioxide exploration efforts over the last few years. Enhanced oil recovery, specifically miscible flooding, has been recognized as a technically and economically feasible method for adding reserves and productive capacity to Canada's light and medium oil. The fiscal regime has been altered by both the federal and provincial governments to encourage miscible flooding development. As a result many projects have been initiated with others being evaluated and designed. This paper analyzes the history and the direction of miscible flooding in the United States, where carbon dioxide is becoming the predominant miscible solvent. The potential for future use of carbon dioxide in Canada is specifically addressed:potential oil recoverysolvent supply, andeconomics.
Shell's carbon dioxide exploration play currently underway is also discussed.

Introduction
Since the 1973 Arab oil embargo and subsequent rapid rise in oil price, oil self-sufficiency in Canada has been expressed as a national desire. Yet, since that time, yearly conventional oil production has not been replaced.
Figure 1 shows that domestic crude oil supply and demand are temporarily in approximate net balance, primarily due to the recent substantial reduction in the latter(1). Canadian demand is forecast to exceed production from established reserves and new discoveries by approximately 100,000 m3 per day (630,000 bbls/day) by the early 1990s. Canada must therefore turn to the non-conventional sources to achieve self-sufficiency.
This paper examines the contributions enhanced oil recovery (by miscible flooding) may be able to make in achieving oil self-sufficiency. An analysis of the history and future direction of miscible flooding in the United States, where the petroleum industry has changed from using light hydrocarbons to using carbon dioxide as the predominant solvent, is given. From these analyses carbon dioxide could emerge as the dominant solvent in Canada in the future.

Light and Medium Enhanced Oil Recovery Potential in Canada
Two-thirds of the original oil-in-place is usually left in the ground after conventional (water flood) recovery techniques have been applied. Miscible enhanced recovery processes involve the injection of a solvent such as carbon dioxide nitrogen or light hydrocarbons (ethane, propane and butane) to mobilize some of this remaining oil.
Miscible flooding has the potential to add 300 to 400 E6M3 (1.9 to 2.5 109 bbls) to Canada's remaining recoverable oil reserves. As shown in Figure 2 this reserve could increase Canada's remaining recoverable reserves by approximately 50% (2, 3, 4). This addition alone will not solve Canada's future oil shortage but can make a significant contribution toward the goal of eliminating reliance on imported crude oil. Miscible flooding in the United States has matured to a greater degree than in Canada. The United States experience and direction may give a strong indication of how the future will unfold in Canada.
In-situ Recovery From the Athabasca Oil Sands - Past Experience and Future Potential
Authors: Redford D.A. 
Published: March 2010

Abstract
Despite 60 years of effort, the Athabasca oil sands deposit, the largest of the Canadian oil sand deposits, is the only deposit for which a promising in-situ recovery process has not been developed.
This paper reviews the many field pilots which have been attempted in this deposit, plus a number of pertinent pilots from related deposits. It then reviews the recovery processes put forward by a number of authors and sums up our current knowledge of this immense untapped Canadian resource and the state of our technology as related to its recovery, With this background in mind, the author gives his views on the state of the technology and indicates the most promising recovery processes for a number of different geological conditions found in the Athabasca deposit. The author concludes with a review of some of the key problem areas where progress must be made if commercial recovery is to occur.

Introduction
In 1930, Absher(1) wrote to his shareholders" I feel that we have overcome the technical difficulties and are able to produce (the Athabasca deposit) on a commercial basis". Absherwas the first to attempt to recover oil from the Athabasca bituminous sands by in-situ means. In the sixty years since his attempts and despite Absher's confidence to his shareholders and numerous subsequent attempts by others, the Athabasca deposit remains a formidable challenge. While commercial exploitation is occurring from the shallower parts of the deposit by surface mining, and promising in-situ methods have been developed for the Cold Lake and Peace River oil sands deposit and for the Grosmont carbonate deposits, the 90% of the thabasca deposit which is too deep for surface mining still remains a tempting motherlode just beyond our reach. This paper reviews the many field attempts which have been tried and some of the concepts which have been considered to unlock this immense resource. It also comments on our experience o date and indicates the author's views on some of the more promising technologies which warrant further testing.

Review of Athabasca Field Tests

The Bituminous Sand Extraction Co-Limited
During the period 1926 to 1931, Absher as the principal engineer for the Bituminous Sand Extraction Co-Limited, attempted in-situ recovery from the Athabasca deposit. His early work using steam and superheated steam was at very shallow depth (10 m to 15 m). but in 1926, he sank several wells to a depth of 100 m (overburden 55 m), and produced some bitumen using superheated steam. The following year, and for the next few years, more wells were completed in the area and a type of downhole steam generator or in-situ combustion was employed, however, no attempt was made to drive between wells, but rather to produce back to another part of the same well. Although some bitumen was produced and Absher was enthusiastic about the results, difficulties with overheating of the wells and loss of tubing and casings where never completely overcome. The advent of the great depression seems to have cut short this pioneering effort.
Effective Well Testing Is The Key To Planning Of Major New Developments Particularly In Remote Areas And Offshore Operations
Authors: Pearson R.M. , Adams D.M. 
Published: March 2010

Abstract
This paper discusses the merits of conducting production and injection tests in the context of frontier areas be they offshore, deep sour gas wells or discoveries in remote, hostile areas. A discussion is included of the data that needs to be collected and how the results affect development planning. To illustrate this, various field development case histories are referenced both in the North Sea and western Canada. Reservoir and production engineering well test design requirements are outlined and the methods for obtaining this data discussed. The case for multirate and extended tests are examined in the context of defining a cost-effective test program. The importance of obtaining adequate fluid samples is also discussed. Finally, an example of the mechanical equipment needed to achieve these requirements is presented for an offshore well test.

Introduction
As the oil and gas industry explores for future petroleum reserves in increasingly "frontier" areas, the need for adequately designed, conducted and analyzed well testing becomes even more important. Whether it is a sour gas plant in the Foothills or an offshore platform off the East Coast, a proper understanding of the reservoir and fluid properties is essential for cost-effective and efficient development planning. Having spent millions of dollars drilling a delineation well to prove-up the reserve, it is negligent to leave that well without establishing the basic data that will be required for planning the exploitation of the reserve. There are numerous cases where operators have had to re-enter or redrill a well or, worse still, have installed ill-designed facilities and proceeded with an uneconomic development as a result of inadequately planned, insufficiently long, poorly supervised or misinterpreted well tests.
At this stage it is important to note that one of the major differences, and perhaps the most important, between conventional and frontier hydrocarbon fields is that large capital investments have to be made for frontier field development based almost completely on exploration and delineation well data. This situation is also applicable albeit on a lesser scale to development of land fields in remote areas, such as western Canadian deep sour gas wells in the Foothills. While the conventional field development can be periodically updated in a staged manner using the latest drilling and production results, most frontier field developments require a commitment to spend the majority of funds long before any production history is available. Logically then, the data obtained from the exploration and delineation wells must be comprehensive and of the best quality possible.
Application Of Measurement While Drilling In A Shallow, Highly Deviated Drilling Program
Authors: Johancsik C.A. , Leraandd A.E. , Petovello B.G. , Gust D.A. , Smith B.W. 
Published: March 2010

Abstract
In choosing a survey system for a directional drilling project, consideration must be given to the production penalties associated with an off-target wellbore as well as to the simple comparison of survey costs. Wellbore position accuracy requirements for Esso Resources' Norman Wells Expansion Project Drilling Program have resulted in the choice of Measurement While Drilling (MWD) as the primary surveying system. The accuracy achieved at Norman Wells using an MWD system is the product of many factors. In addition to tool design and calibration, the operating and data check procedures are fundamental to achieving the required accuracy in the severe magnetic environment at Norman Wells.

Introduction

Scope of Norman Wells Drilling Program
Esso Resources Canada Limited is currently undertaking a major expansion project of the Norman Wells oil field. This field is located in the Northwest Territories on the Mackenzie River, 145 km south of the Arctic Circle (Fig. 1). The expansion project includes drilling approximately 162 wells between July 1982 and April 1985. The wells are drilled from mainland and natural island locations and from six artificial islands in the Mackenzie River (Fig. 2). Seventy-eight per cent of the project wells are directionally drilled to reach reservoir targets under the Mackenzie River. As of March 31, 1984, 100 of the wells have been drilled.
The unique circumstances at Norman Wells demand a sophisticated directional program. The wells are relatively shallow with true vertical depths to the top of the producing zone ranging from 335 m in the mainland area to 490 m at the downdip end of the reservoir. Horizontal displacements to targets extend up to 750 m from the surface locations. Small targets and the requirement for the wellbore to be as vertical as possible through the producing zone have required the use of S-curve well profiles with rapid build and drop rates.
Directional wells have been divided into three types (based on displacement) as illustrated in Figure 3. Type 1 wells have displacements less than 270 m, Type 2 wells range from 271 to 550 m and Type 3 wells reach targets up to 750 m from the surface locations. All directional wells are kicked off between 30 m and 50 m and angle is built at a programmed rate of 8 degrees/ 30 m. Maximum angles of 50 degrees, 60 degrees and 70 degrees to Well Types 1, 2 and 3 (respectively) are reached and held. The wells are then dropped into the targets at rates of 4 degrees/ 30 m. Figure 3 illustrates three wells that were drilled fromartificial island locations in early 1984.

Target Accuracy Requirements
The choice of a survey system to use for wells of this type is dictated largely by the requirement for accuracy. Accurate positioning of wellbores to hit the relatively small targets is important because of the particular nature of the Norman Wells reservoir. Hydrocarbons at Norman Wells are pooled in the Devonian limestone reef complex called the Kee Scarp.
Casing Running Considerations In Highly Deviated Wellbores
Authors: Jordan R.O. 
Published: March 2010

Abstract
This paper presents the results of a study that was carried out to improve production casing running times in highly deviated wellbores. Inadequate hole cleaning can be a major problem when drilling, casing and cementing high-angle wells. The mechanisms of hole cleaning are discussed, along with case histories from several wells. Recommended operating parameters are presented, as well as benefits that can be realized by following them.

Introduction
During the early phase of Esso Resources' Expansion Project at Norman Wells, unacceptably long production casing running times were experienced. On Type II, 60-degree, 810-metre wells, average casing running rates were 98.9 metres per hour with 12.7 metres per hour the minimum (Fig. 1). On Type III, 70-degree, 980 metre wells, the average running rate was 61.1 metres per hour with a minimum rate for one well of 10.6 metres per hour.
Initial attempts to reduce casing running times on similar wells included picking up drill collars to 'spud' the casing string. Another attempt involved a cathead-pulley-slip elevator arrangement to snub the casing into the wellbore. When these efforts produced no appreciable benefit, a thorough analysis was warranted. Because inadequate hole cleaning was suspected to be the problem, the study concentrated on this aspect. Case histories of 35-highangle wells and current research into cuttings transport in deviated wellbores were examined.

Casing Running Mechanism
With improper hole cleaning and cuttings carrying capacity, drill cuttings accumulate in a bed on the low side of the wellbore. When casing is run, it pushes the cuttings to the side or ahead as it goes (Fig. 2). This idea is supported in actual practice by the fact that upon reciprocation and working of the casing through tight spots, it would, almost without exception, return to at least its previous position. Although drag is considerable on a 60-degree well, a pure drag effect would not produce the same result, and hence was not considered the problem.

Cutting Transport in Directional Wells
The actual mechanism for cuttings transport in deviated wellbores has been the subject of several research projects(1, 2, 3). These studies have indicated that the most important factors affecting the carrying capacity of a drilling fluid include the hole angle, annular velocity, fluid viscosity, fluid density, cuttings feed rate or ROP, and annular geometry. Drillpipe eccentricity and rotation also have a minor impact. Under normal drilling and circulating conditions in a deviated well bore, a bed of cuttings forms on the low side of the hole (Fig. 3). The cuttings bed forms quite rapidly because the cuttings have such a short distance to fall, especially at higher angles. As the bed forms, the annular area is reduced and thus the velocity increases. The increased annular velocity improves cuttings transport. A steady state condition is achieved when the rate of cuttings dropped onto the bed equals the rate of cuttings picked up.
Simulation Of A Large Steam-CO Co-Injection Experiment
Authors: Stone T. , Malcolm J.D. 
Published: March 2010

Abstract
A high-pressure steam-CO2 co-injection experiment, carried out in a 1.5 m diameter physical simulator packed with Athabasca oil sand, is described. The experimental run lasted/or 113 hours and consisted of two injection-drawdown cycles. During the run, 1454 kg of steam and 75.3 kg of carbon dioxide were injected (equivalent to 2.1 mole % CO2 in the mixture). This resulted in the recovery of 12.5% o/the initial bitumen in the oil sand.
The experimental data obtained was compared to the results of a numerical modelling study. Good agreement was obtained. Differences between the numerical simulation and experiment are discussed.
Results from steam-only predictions are used to discuss the merits of the steam-CO2 injection process relative to steam injection alone.

Introduction
Many experiments have been carried out at Alberta Research Council (ARC) in the last five years to test the effectiveness of additives on recovery of Athabasca bitumen. An adequate numerical simulation capability is useful in analyzing these runs. This capability also serves as a design aid for further experiments as well as serving a need for idealized studies.
The experiment that was simulated for this report (hereafter denoted "Run 15006") was the first run in the 150 cm pressure vessel in which stearn and CO2 were simultaneously injected into an oil sand pack of this physical size. The primary objective was to study recovery benefits from addition of CO2 to the injection stream. Other objectives were to study the rate of advance of temperature profiles in the bed during the run and to provide data to test a numerical simulation of the steam-C02 process. A three component model developed at ARC was used to simulate the above process. The model is a fully implicit thermal numerical simulator with the capability of handling a single additive. Objectives of the numerical simulation were principally to test the numerical model, and hence all its property data for a CO2/water/bitumen system.

Description of Experiment
The 150cm diameter simulator system (Fig. 1) consists of a large pressure vessel (150 cm ID by 270 cm high) designed to allow steam and gas to be injected simultaneously into the test bed under controlled flow rates. Oil sand is packed into this vessel and maintained at field overburden conditions by introducing a nitrogen blanket at the top of the cell. Feed streams were injected to the centre of the test bed via an injection well.
The three main systems are schematically illustrated in Figure 1. These are the injection system, test cell and production system. The steam portion of the injection system consists of a high pressure steam generator followed by a superheater. Flow turbines measure flow rate after the superheater and are marked "F" in Figure 1. Thermocouples and pressure, gauges are also in place, marked "T" and "P" in Figure 1. The steam generator operates at a constant flow rate. Pressure to the system is regulated by a control valve upstream of the superheater.
A New Regime For The Frontier
Authors: Parsons Robert B. 
Published: March 2010

Abstract
It's a new ball game for the oil and gas industry in the frontier. On October 30, 1985, Energy Minister Pat Carney released a package of measures which will replace virtually all of the measures contained in the now defunct National Energy Program insofar as exploration, development and production in the frontier is concerned. No aspect of doing business in the frontier will escape untouched by the wide range oj proposals in the new regulatory framework.

Introduction
It has taken the present Federal government less than one year to demolish the former government's much loathed National Energy Program. As reported in the last edition of Tax Topics, the March 1985 Western Accord and subsequent Federal and Provincial budgets started the demolition process, virtually revamping all aspects of the NEP except for he rules applicable in the frontier. In ctober this year, Energy Minister Pat Carney drove the final nails into the NEP's coffin upon announcing a new set of incentives and tax and other regulatory provisions for operations in the frontier.
A 19-page paper entitled "Canada's Energy Frontier" describes the Federal government's aspirations, plans, and new rules and regulations for oil and gas in the frontier.
There seems to be unanimity in the oil patch that the complexion of such future operations will be notably different under the new regime.

Incentives
The proposed changes to the incentive system for exploration in the Canada Lands will probably have the most dramatic effect on the way of doing business in the frontier in the future.
Under the NEP's Petroleum Incentive Program (PIP), an enterprise with a minimum 75% Canadian ownership rating was entitled to cash grants equal to 80% of eligible exploration expenditures. A less than 50% Canadian owned entity could obtain cash PIP grants of 25% of exploration costs. This meant, for example, that the after-tax cost to a wholly Canadian owned corporation of exploring in the frontier was $.10 on the dollar, while the comparable after-tax cost to a non-Canadian corporation was $.37 1/2 on the dollar.
Two phenomena of the NEP era are clearly attributable to this cash grant system. First, the relatively cheap after tax cost of frontier exploration led to a remarkable shift in exploration spending rom the conventional provincial lands to the frontier. Second, the preferential treatment accorded Canadian ownership gave rise to some interesting bedmates, with non-Canadian owned multi-nationals entering into highly complex and convoluted arrangements with smaller Canadian owned concerns in order to optimize the utilization of PIP grants. Over-all, the result was considered by many to be a politically driven exploration business, as compared to a market driven one.
One of the evident goals of the proposed new incentive system is to restore the exploration decision-making process to the market. Under the new system, PIP grants will be replaced by a royalty and tax credit system.
The first $5 million of eligible exploration costs per well will be eligible for a 25% royalty credit.