bluuebunny/crossref_metadata_2025_split huggingface dataset:
TheNorthSea-ANe\v Major Oil Province In a Changing World
Authors: Bexon R. 
Published: March 2010

Abstract
Current exploration in the North Sea is described and latest estimates of the reserves of oil and gas are given. The field development program is reviewed and forecasts of production presented. The principal economic constraints are identified and examined against the recent position taken by tile UK Government on tax and participation.
Events during the past few years have combined to make the oil developments in the North Sea, paticularly interesting. Technically, the deep and hostile water of this latest major new oil province have demanded new solutions for new problems. Economically, the incidence of runaway inflation on high-cost development at a time when massive new taxes have been introduced to take advantage of high oil prices has created unique financial stresses. Politically the impact of the development on industrial countries has bud considerable social and national repercussions within a short period.

History
SOME 6,000 exploration wells were drilled onshore in Western Europe during the period 1920–59, resulting in a maximum total production of only 250,000 bbls/ day and few important gas discoveries. There was little basis, therefore, for anticipating spectacular hydrocarbon accumulation. In 1959 however, the giant gas field of Slochteren was discovered in the Netherlands, in a geological setting which immediately suggested that similar prospects might lie under the North Sea.
The Southern North Sea basin was the first to be explored, and has subsequently proved to contain large gas reserves in the Permian sandstones similar to those of Slochteren. Five commercial gas fields have been put on production and eighteen other gas strikes have been made in UK waters. Not all are of commercial proportions, but none can apparently be developed, largely due to the low prevailing gas price negotiated with the monopoly buyer, the British Gas Corporation. Several gas fields have been found off the Netherlands and one of these is currently being developed. The high continental prices will encourage further development here. So far, 379 exploration and appraisal wells have been drilled in the southern part of the North Sea, including Danish waters, with a success ratio of approximately 1 in 20.
The Northern North Sea is predominantly an oil prospective region of younger geological age and now appears to be one of the most prolific areas, for its size, in the world. The basin covers both Norwegian and UK offshore acreage and so far exploration has been limited to the area south of latitude 62"N. There are three major types of prospect in this basin. In order of increasing age, the first and youngest prospect is in the Lower Tertiary sandstones, of which the Forties Field is an example. The second prospect (although the first discovered) is in the domed and fractured Upper Cretaceous and Danian limestone, typified by the Ekofisk Field. The third major prospect, and the most important, is in the. Jurassic sandstones in the northern part of the basin. as evidenced by the Brent group of oilfields.
Pattern Oversweep In Nine-Spot Waterflood Pilots
Authors: Dranchuk P.M. , Peters E.J. 
Published: March 2010

Abstract
A laboratory study has been conducted on isolated and partially confined five- and nine-spot water/load patterns. The results show that both isolated patterns continue to produce oil with continued injection, but that each pattern, when surrounded by a single ring of like patterns, behaves as if it were confined provided the injection rate is sufficiently high to ensure a stabilized flood.

Introduction
Although the five-spot is popular in test pilots, there are occasions where the nine-spot is used so as to increase the total injection rate into the pivot and thereby decrease the duration of the test. It was therefore decided to extend the above study to the nine-spot pattern. As the Rapoport, Carpenter and Leas scaling criterion(2) was developed for the five-spot pattern and its validity for the nine-spot was not established, it was decided to vary the injection rate for both the five- and nine-spot and to compare the results.

Equipment
The model studied was the same one used and described in the previous study. A new injection system was designed and built. This system was modelled after the old one, but was built to permit simultaneous injection into as many as forty wells. It consisted of 41 cylinder-pistonassemblies positioned between two 3/4-inch-thick steel plates. As in the previous study, the center cylinder-piston assembly was double acting and was used toctuate the remaining 40. Injection pressures were measured by means of manometers, as was the case in the earlier study. However, in order that up to 40 injectors could be used, the manometer anks had to be modified and extended.

Model & Fluid Properties
Although the model and beads used in the present study were the same as in the previous work, the system was cleaned and repacked. This resulted in a pack with a porosity of 36.4 percent and a permeability of 6.60 darcys.
The fluids employed had the properties shown in Table 1 and were essentially identical to those used in the previous study.

Procedure
The experimental procedure used was identical to that in the earlier stuoy, except that a different constant injection rate was used in each run. In each case, the range of rates was chosen so as to straddle the value required by the scaling criterion or its equivalent.

Observations
Flood tests were carried out on an isolated five-spot, a five-spot surrounded by eight other fivespots, an isolated nine-spot and a nine-spot surrounded by eight other nine-spots, as shown in Figure 1.
Isolated five-spot tests were conducted at constant injection rates ranging from 42.9 to 514.3 cc/hr well, as is indicated in Figure 2.
From the, results, it may be seen that in each case the flood oversweeps the pattern, but that an increased injection rate tends to increase the degree of confinement.
In the case of the isolated ninespot, tests were conducted at five different constant injection rates in the range of 21.4 to 257.1 cc/hr well.
Fracturing With Foam
Authors: Bullen R.S. , Bratrud T.F. 
Published: March 2010

Abstract
Foam has been successfully applied as a circulating fluid for workovers and drilling for several years. Now a new oilfield application has been developed for foam: formation stimulation by fracturing. Over 150 wells have been treated to date in Canada using foam as the fracturing fluid, with a high degree of success. Unique 'rheological properties of foam make it well suited to this application: high sand carrying capacity, low fluid loss coefficient, low fluid friction loss, quick load fluid recovery low formation damage, and little or no reduction of fracture conductivity due to residual fluid saturation. The cost of the treatment is competitive with that of conventional systems.

Introduction
Fracturing of oil and gas wells involves the injection of a fluid into a well at a sufficient rate and pressure to physically rupture the rock down hole. A crack, or fracture, is developed and extended deep into the reservoir with continued fluid injection. Sand is carried in the fracturing fluid to prop the crack open when pumping is stopped, leaving a new, more permeable route for oil and gas to flow into the wellbore.
Foam has recently been successfully used in place of conventional fracturing fluids, such as oil or water, for this process. The type of foam normally used is comprised of water, surfactants and a discontinuous gaseous phase of nitrogen. The volumetric gas content, referred to as "foam quality", is generally in the range of 65% to 95% under calculated downhole treating conditions:
Equation (1) Available In Full Paper.

Field Operations
During a Foam Frac ™ treatment, water from a tank is continuously mixed with sand in a blender, at sand-water ratios progressively increasing to as high as 8 lbs/gallon. A surfactant, or foaming agent, is then proportioned into this slurry at a ratio of .2%; to 1.0%, and the resultant fluid blend is transferred to a high-pressure triplex pumper. High-pressure nitrogen gas is manifolded into the discharge line of the triplex, and it is at this point that the foam is developed. KCl, gellants or other chemical treating agents may be added to the base water if required to improve its compatibility with the reservoir rock or fluids. Figure 1 schematically shows this process.
The blender and high-pressure pumper are conventional oilfield service equipment, modified to accurately proportion the high sand ratios pumped at slow discharge rates. The high-pressure N2 gas is also available from conventional oilfield N2 service units. Figure 2 illustrates an actual job in progress.
The foam injection rates and volumes are in the order of 4 to 5 times those of the liquid pump rates and volumes at the blender because of the expansion by introduction of N2. These total volumes and rates are increased by a factor F, as follows:
Equation (2) Available In Full Paper.
For example, using a 75% foam quality, the foam injection rate will be 4 times the fluid pump rate at the blender.
Drilling In the St. Lawrence Lowlands of Quebec
Authors: Thornton Harold P. 
Published: March 2010

Introduction
'The drilling of exploration holes in the St. Lawrence Lowlands region of Quebec has historically been a very costly venture, with many holes, drilled by several different operators, costing over a million dollars each and in some cases, exceeding $150 per foot. These high costs have been attributed to slow drilling of hard rocks, deviation problems and high-pressure/low-volume gas requiring 15 to 16 pound per gallon mud to control gas kicks. In addition, sloughing shale has been a severe problem on some holes. Located between Montreal and Quebec City, in one of Canada's most heavily populated regions, the area is really a frontier in terms of its remoteness from established oilfield supply points and the number of exploratory holes per unit area.
Cost reduction was of major importance in programming a three-well wildcat drilling project for Society Quebecoise d'Initiatives P?troliers (SOQUIP) during the winter of 1973/74. The wells, drilled on a farm-out from Shell Oil, earned an interest in a 2.87-million-acre spread of land between Montreal and Quebec City. The normal incentive to drill efficiently and cheaply was present, but, in addition, one of the major terms of reference in SOQUIP's charter is to lead the way for the oil industry to search for and develop the petroleum resources of the Province of Quebec. Certainly a major contribution toward that goal would be to substantially reduce drilling costs in an area of prime interest along the St. Lawrence River, thereby changing the exploration economics for the industry.

Engineering Philosophy
An analysis of geological conditions and operational problems encountered on other holes in the region of the proposed three-well rogram led to the conclusion that many problems were more created than real. The normal tendency in programming a new well is to observe troubles on previous holes and then program the new well in the same manner as the old ones, to "avoid all those problems".
Many times, such programming merely perpetuates the problems.
Of primary importance was the conclusion reached by the writer that the bulk of the section to be drilled in the Lowlands is not as hard as it appears to be from old bit records. Less than optimum hydraulics and mud-flow properties, together with high solids, high-density muds and bit selection consistently on the too-hard side, combined to create the appearance of hard formations. Study of logs and formation samples indicated that if better conditions existed at the hit, substantial improvements could be expected in penetration rates.
With this assumption as a basis on which to work, a mud program was designed by the engineers to create the minimum hydrostatic pressure and maximum bottom cleaning. Recognizing that the best drilling fluid is clear water, it was decided to use clear water with 18,000 parts per million KCI as a precaution against sloughing and possible damage to the formation. Inherent in drilling with a low density fluid is the risk of taking a gas kick which could lead to a blow-out.
Production Increase of Heavy Oils By Electromagnetic Heating
Authors: Abernethy E.R. 
Published: March 2010

Abstract
Several methods of accelerating oil flow by applying heat from the wellbore to the reservoir have been successfully field tested. However, it appears that the possibility of heating by high-frequency radiation has not been extensively investigated, either theoretically or experimentally The concepts involved are discussed and a mathematical model is developed in order to evaluate the temperature distributions and other physical effects resulting from the radiation of electromagnetic energy into an oil reservoir. Flow performance is compared to the unheated case on the basis of a steady-state temperature distribution, which is derived. The results of a pre-steady-state transient flow condition are also presented.
Calculations based on the mathematical model developed indicate that further work is warranted to prove or disprove the feasibility of this method of stimulation. A brief discussion of completion and engineering problems is included.

Introduction
From time to time, the technical literature has made reference to heat stimulation by the radiation of electromagnetic energy from the wellbore. A Russian paper(1) touched on one aspect of the subject, and compared electromagnetic and contact heating for a shut-in well, using a spherically symmetric model. The possibilities of concurrent flow and power input were not discussed.
It should be emphasized that this paper deals not with conduction or induction, but true radiation, as exemplified by the output of a short-wave radio station. In the broadest terms, electromagnetic effects are exhibited from the lowest frequencies (e.g. 60 cycle and lower) to the very highest (X-rays, gamma radiation, etc.). For the practical purpose of wellbore heating, however, the following discussion should be viewed in terms of those frequencies at which high power can be generated on a continuous basis. At the present, this includes frequencies up to about 20000 megacycles per second. Figure 1 shows schematically the mode of operation envisioned for radiation heating.
The Continuous Spilling of Hot Oil on Ice
Authors: Siu Sidney K. , Phillips Colin R. , Chen E. C. 
Published: March 2010

Abstract
The continuous spilling of hot Norman Wells crude oil onto an ice surface was investigated with oil temperature, ice temperature and spilling rate as parameters. An equation for spreading of the oil was developed in whick the oil slick area, A, was proportional to t(1,2), where t is the elapsed time. Experimental data showed that A was prow portional to t0.8. Increases in both oil and ice temperatures were found to cause an increase in A, and temperature effects could be taken into account by relating kinematic viscosity to a function of the geometric mean of the ice and oil temperatures.

Introduction
ALTHOUGH the spreading of hot oil on ice is of interest from the point of view of oil spills in Arctic regions, no controlled quantitative study taking several variables into account has been published. In previous work, Chen et al.(1) studied the instantaneous release of oil under controlled isothermal conditions, and Glaeser(2) and McMinn(3) carried out non-isothermal field tests under a single experimental condition. The present work concerns the continuous spilling of hot crude oil on ice at ice temperatures down to −40 °C and oil temperatures up to 60 °C. Continuous spilling would occur in the event of a pipeline leak. The oil and ice temperatures chosen cover likely pipeline conditions during the Arctic winter. In common with the previous work(1), crude oil from commercial production at Norman Wells, Northwest Territories, Canada, was used. Mackay, Charles and Phillips'" have discussed other aspects of the physical behaviour of crude oil in Arctic environments, with particular reference to Norman Wells crude oil and the Mackenzie Valley of the Northwest Territories.

Theoretical Background
It has been recognized(1–3, 5–7) that the spreading of a liquid over a solid surface passes through three distinct regions: gravity-inertia, gravity-viscous and surface tension-viscous. However, in continuous spreading, the gravity-viscous region is of primary importance because surface-tension spreading is not likely to occur due to the continuous flow, and the gravity-inertia spreading, which occurs only in the area around the point of deposition, will not be observed.
Using the same argument as that used by Chen et al.(1), the gravitational outward pressure force per unit volume is
(Equation Available In Full Paper)
In application of this model to the non-isothermal case of spreading of hot oil on ice, it should be noted that µ (or υ) must represent an effective viscosity, as there is a temperature gradient across the spreading oil film; any correlation of data in terms of equation (5) will therefore be in terms of such an effective viscosity. This notion is further reinforced by the observation that the spreading of hot oil on ice must of necessity involve flow of oil over a water film formed from the ice at the interface with the hot oil.
The Role of Geologyin Enhanced Recovery
Authors: Diehl A.L. 
Published: March 2010

Abstract
The following paper is taken from the text of a Keynote Address given by the author to the Joint Convention on Enhanced Recovery organized by the Petroleum Society of The Canadian Institute of Mining and Metallurgy and the Canadian Society of Petroleum Engineers, held in June of 1976 in Calgary, Alberta.
ENHANCED RECOVERY is a very timely theme and this joint convention, bringing together representatives from both the engineering and the geological societies, is very much in order. Enhanced Recovery projects are of course -capital-intensive, but they are also very manpower-intensive. Although they are primarily reservoir engineering projects, they are none the less interdisciplinary in nature and require the full involvement of many specialists, including reservoir engineers, geologists, petro-physicists, economists, field engineers and others. To help this interdisciplinary involvement along at the outset, it is a good idea to overcome any communications barriers that might exist. The geologist, for instance, may not be all that sure what it is the reservoir engineer needs and why and the reservoir engineer maynot fully appreciate what the geologist can and cannot contribute. During this joint convention, we will have the opportunity to listen to speakers from the various specialities discuss their own contribution, and with the engineers iistening to the geologists and the geologists listening to the engineers, we should all gain a much better appreciation of the problems related to Enhanced Recovery.
As an introductory speaker, it is not my intention to go into details an d certainly not to give a lecture on geology. The many papers to be presented will cover the subjects very well. What I would like to do, however, is to set the stage for these papers by talking about the more general aspects of the geological involvement.
What, exactly, is the role of the geologist in Enhanced Recovery' In my opinion, it is to provide a model of the reservoir that adequately describes its pore-space distribution and the distribution of the fluids within it.
Geologists have actually been doing this from the very beginning of the industry, but they may not have looked at it quite that way. In the early days, the field geologist with his surface maps led the way for the discovery of new oil fields. Subsurface mapping of the reservoirs during development fell naturally into his bailiwick. These maps, surface and subsurface, were primarily concerned with rock units the sand and shale and limestone layers that he could identify and correlate. With his correlations and dips and strikes he could work out the structural and stratigraphic configuration of the fields.
Because oil is produced from the pores of rocks, however, there is something more to mapping a reservoir than just mapping the rock layer itself. We really should concern ourselves with the pore-space distribution within the reservoirs and not just the rock layers themselves.
Overpressure Detection And Control At Imp ImmerkB-48 Using A Wellsite LVlud Gas Detector
Authors: Daw R.N. , Mercer R.F. , Myers D.L. 
Published: March 2010

Abstract
Continuous 1nud gas detection was used at Imp Immerk B-48 in the Mackenzie Delta during drilling operations to assist in the detection and control of overpressure due to undercompaction of fine-grained sediments.
Special techniques used in conjunction 'with the gas detector data improved the ability to relate the increase in formation pore pressure to the required mud weight as drilling proceeded.
Careful interpretation of the mud gas response to the drilling actions showed a repetitive cycle of events. Knowing the ca1we of these repetitive cycles and recognizing current position in the cycle increased drilling safety by providing better cont1'ol of mud weight.

Introduction
THIS PAPER describes the mud gas logging techniques used by Imperial Oil to assist in detecting and controlling overpressure due to under compaction at Imp Immerk B-48. We do not imply that these are the only techniques or the best techniques to detect and control overpressure, but we do believe that they are an important supplement to our pressure-monitoring program. In fact, we are now confident that we can safely penetrate over pressured sections.
Overpressure due to undercompaction results when pore waters which cannot escape from rapidly deposited, fine-grained, poorly permeable sediments support part of the weight of the overburden. Hydrocarbons dissolved in these pore waters, as well ns free hydrocarbons, affect the amount of gas detected in the mud. We will show specific examples of the relationships between overpressure due to undercompaction, mud gas and the mud weight required to maintain pressure balance.
To assure clarity of the terminology used in this paper, the following definitions are presented.
Mud gas is the total hydrocarbon gas removed from the mud (not from the rock formation) by a gas trap and measured with a detector. The amount of gas is expressed in Canadian Gas Units; 100 units equals the instrument response to 1% methane in air*. Mud gas is measured at the surface one lagtime after the down-hole event. One method of keeping the mud gas measurement current with bit penetration is to wash "bottoms-up"; i.e, stop drilling, but pump the mud from the bottom of the hole to the surface. This mud gas enters the mud stream as either:liberated gas from mechanical liberation or crushing of rock by the bit; orproduced gas, which is produced from the rock formation when the mud-column pressure is less than the formation pore pressure.
A dummy trip is a short trip, only part-way out of the hole, which simulates in a short period of time what would happen if a full trip was made.
A dummy connection is made by lifting the pipe off bottom and stopping circulation for a short time to simulate the conditions of a normal connection.
A flow check is made by shutting off the pump and stopping rotation to see if the well is flowing or taking fluid. A flow check is an extremely important safety measure, because it provides an immediate surface expression of the down-hole action.