bluuebunny/crossref_metadata_2025 huggingface dataset:
Simultaneous Nonsteady Flow of Oil And Water Through Linear Porous Media
Authors: Pascal H. , Kirkpatrick John W.
Published: March 2010

This paper is concerned with the behaviour of a linear oil reservoir which is produced at constant terminal pressure and is fed b:r a finite aquifer with a sealed outer boundary. The study is confined to the case where the water saturation in the oil reservoir exceeds the so-called irreducible minimum.

Specifically, this work presents a mathematical formulation of the system. The resulting partial differential equations express the pressure distribution in both zones, the wat.er saturation in the reservoir the oil and water flow rates, and the cumulative productions as functions of time. Although it appears that this set of equations can be solved only by numerical means, an approximate analytical solution, valid for large values of time is presented.

Introduction

SINCE AN OIL RESERVOIR call be exploited but once, and the possible exploitation schemes are many, it is necessary to predict the behaviour of the reservoir for each scheme, compare results and choose the scheme which is most suitable according to selected criteria. In order that this be done, mathematical formulation is required for each reservoir and scheme combination.

The object of this study is to examine H linear oil reservoir which is fed by a finite aquifer with a sealed outer boundary. Given the situation in which the water saturation in the reservoir exceeds the critical and the reservoir is operated at some constant pressure at the producing face, the question is can the following be expressed as function of time?water saturation in the reservoirpressure distribution in the reservoirpressure distribution in the aquiferoil production ratewater prodLlction ratecumulative oil productioncumulative water production.

If such functions can be formulated and the resulting equations solved, the information obtained may be used to predict the behaviour of such linear systems either in the field or laboratory.

Problem Formulation

If the cross-sectional area of the reservoir and aquifer are constant and equal, the system may he described pictorially by means of a plan view as shown in Figure 1, where zone I represents the reservoir, zone II represents the aquifer and I and L represent their respective lengths.

For the case where the water saturation in the reservoir is greater than the critical, the pressure in both zones is initially equal and constant al some value, say p, and production is initiated and continued by dropping the pressure at the out flow face to some

(Equation Available In Full Paper)

fixed value, say p one may describe the situation mathematically by means of the following initial and boundary conditions.

(Equation Available In Full Paper)

In addition, zones I and II are coupled by virtue of the fact that the water flux must be continuous across the reservoir-aquifer boundary.
Oil Reserves In Alberta
Authors: van de Panne C. , Kirkpatrick John W.
Published: March 2010

Introduction

IT IS OF CONSIDERABLE INTEREST TO KNOW the total amount of conventional crude oil which can be recovered in Alberta. The Energy Resources Conservation Board has estimatedl J1 this quantity at 20 billion barrels; it also estimated the annual increase of proved reserves at 450 million barrels.

These estimates were obtained by considering the curve of proved reserves of the province over the past 25 years and extrapolating linearly. This is similar to the methods applied to the crude oil reserves of the U.S. by Hubbert(1) and Moore (see Lovejoy and Homan(2)) though the curves fitted by Hubbert and Moore were somewhat more complicated.

Such curve-fittings have their disadvantages. There may be many reasons why a trend which has been present for many years suddenly changes. It is much better to formulate a relationship between the reserves and some other variables which explains the development of these reserves, To estimate such a relationship and to use it for projections is the main purpose of this article.

The increase of the initial recoverable proved reserves (that is all oil known to be recoverable plus all oil produced so far) in any year consists of reserves (that is all oil known to be recoverable plus exploratory wells and additions to and revisions of reserves of oil pools found previously; these additions and revisions are called the appreciation of reserves.

Let us indicate the total proved reserves of the province in year t by Pt and proved reserves in year t of an oil pool discovered in year τ by P (τ) it is obvious that P (τ)t = 0 for t < τ. We have then

(Equation Available In Full Paper)

P(t), are the proved reserves of pools discovered in year t and P(t0)?.P(t-1), are the proved reserves of pools discovered in previous years to, ..., t-l, where to is the year in which the first reserves were discovered.

The appreciation of oil reserves over the years is quite erratic. Nevertheless, it is possible to estimatethe average appreciation of reserves as a function of the years since discovery. The Energy Resources Conservation Board has used(3) the formula

(Equation Available In Full Paper)

where r(t) is the average multiple of the proved reserve in the year of discovery after t years, and a and b are estimated from curve 1 in Figure 1, which gives the averages resulting from the data available. Curve 2 gives the curve fitted in to curve 1, taking into account some other information which* results in the values a = 8.495, b*= 4.4505 or b = 0.7988.

Because the fit of curve 2 is not very good, the author of this article used a nonlinear least-squares procedure to fit (1,2) to curve 1, which resulted in a = 8.7711 and b = 0.88381.
A Three-Dimensional Model For Predicting Natural Gas Reserves And Availability
Authors: Richards Ross
Published: March 2010

A model is presented which analyzes the discovery and subsequent appreciation of natural gas in Alberta using data compiled by the Alberta Oil and Gas (now Energy Resources) Conservation Board. This model is then used for the prediction of new discoveries and subsequent appreciation of existing discoveries. This means that the volumes of gas discovered are analyzed and predicted both as a function of discovery year and year since discovery.

Introduction

PREVIOUS ATTEMPTS at statistically estimating natural gas reserves have dealt with the problem as a process which analyzed and subsequently predicted reserves as a cumulative quantity. No attempt was made at separating the appreciation of present reserves and the prediction of new reserves. Noteworthy of the studies that have been performed are two approaches. The first approach, presented by Hubbert(1) and Moore(2), uses cumulative gas reserves tabulated by calendar year and involves the fitting and extrapolation of S-shaped curves of either logistic or Gompertz form, respectively, with the latter curve giving a slightly better fit to the data presented here. The second approach, presented by the Alberta Oil and Gas Conservation Board(3,4) uses cumulative gas reserves tabulated by years since discovery and analyzes the growth pattern of the appreciation of existing gas reserves. This method does not predict an ultimate initial established marketable gas reserves, but does provide a very good fit on a cumulative basis of the appreciation of existing reserves.

This paper is aimed at statistically analyzing the way estimates of natural gas reserves grow. The model used for the analysis is referred to as a three-dimensional model because it is a function of three factors - the calendar year, the year since discovery and the amount of reserves known at these times. Alberta Oil and Gas Conservation Report data(3) used in this study are shown in Table 1. The Table shows) by year since discovery and by calendar year, the recognized reserves of some 400 natural gas pools discovered subsequent to 1950 which have initial reserves greater than 10 billion cubic feet. In total, it is estimated that these pools represent 72 per cent of the total reserves that have been recognized as being discovered prior to December 30, I970.

GENERAL STRUCTURE OF THE MODEL

Appreciation of Existing Reserves

Once given the amount of gas discovery in any one particular year (t), the appreciation of this gas is a very regular process which slows down exponentially with time and hence the cumulative growth has the form of a limited exponential of the following form.

(Equation Available In Full Paper)

Applying this model to the data presented in Table 1 for the years of discovery 1951 to 1960, the following results were obtained by non-linear least-squares techniques.

(Equation Available In Full Paper)

As can be seen from the above results, each individual model as well as the cumulative model provides a good description of the data.
A Laboratory Investigation of the Enriched Gas Displacement Process In Vertical Models
Authors: Alonso M. , Morineau Y. , Simandoux P. , Bradshaw A.D. , Bennion D.W.
Published: March 2010

The object of this study was to understand the enriched gas displacement process that is being applied in several kigh-relief carbonate reservoirs in Alberta. There is not yet sufficient field production history to determine the mechanisms affecting their performance. Therefore it is necessary to use laboratory data to show how the process works and the manner in which the various mixing zones develop and grow. Two programs were developed to study this phenomenon. The first was to define the behaviour of a simple three-component fluid system. The other was to use a multicomponent system in actual reservoir carbonate rocks performing the displacements at field pressure, temperature and rates.

These experiments indicate that the solvent is not directly miscible with the oil but rather acts to change the composition of the oil. This change iscaused by the solvent contacting the oil and coming into thermodynamic equilibrium with it, forming two phases (liquid and gas). The velocity of the gas phase is greater than the liquid phase; hence, it moves ahead contacting new oil and coming into equilibrium with it. This exchange takes place until the gas at the front is in equilibrium with the original oil.

These experiments showed that three zones develop. First there will be a zone having the composition of the original reservoir oil. The secondwill be a two-phase zone. This will be followed by a zone in which only a gaseous phase is flowing.

The utility of these experiments is only to explain the displacement mechanism. The sizing of the solvent bank and recovery prediction must be made by numerical simulation.

INTRODUCTION

MISCIBLE FLOODING of a petroleum reservoir is defined as a displacement process which- has zero interfacial tension between the displaced and displacing fluids. There are two types of miscibility.Direct miscibility, where the two fluids form a single phase on first contact with each other.Conditional miscibility, where the fluids are not miscible on first contact but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchange of components, the system becomesmiscible.

In summary, there are three general types of miscible displacements in active field use:

LPG solvent, which is directly miscible with the reservoir oil; high-pressure gas, which is conditionally miscible with the reservoir oil; and enriched gas, which is conditionally miscible with the reservoir oil.

Figure 1 is a constant pressure temperature pseudo-ternary diagram which is not thermodynamically rigorous but can be used to represent these three processes. The ternary representation is composed of four regions. The size and shape of these areas are determined by the dewpoint and bubble-point curves of the particular fluids being studied. Region A is a single-phase gas area, B contains two phases, C is a single-phase liquid area and region D is a single-phase fluid area.
Development of Low-Productivity Gas Reserves, Southeastern Alberta
Authors: Kloepfer C.V. , Last G.J.
Published: March 2010

The drilling and completion practices utilized in the development of the Milk River and Medicine Hat zones in southeastern Alberta reflect the limited productivity and economics of the resulting gas production. The opera ting costs applicable to the surface handling of this gas are kept to a minimum through efficient utilization of wells, flowline, roads and surface equipment.

Ultimate production for these zones is a function of individual well performance. Typical spacing to provide reasonable project lives are 320 acres for the Milk River development and 640 acres for the Medicine Hat pools. Initial productivity of the wells varies from 220 Mcf/D for a Milk River well to 500 Mcf/D for a Medicine Hat well. Production rate at abandonment could be as low as 20 Mcf/D. Typical recoveries for the Milk River and Medicine Hat zones are 2 Bcf/section.

The profitability of a typical southeastern Alberta gas producing operation is critically related to capital and operating costs and particularly dependent on field operating practice.

INTRODUCTION

FOR THE PAST FEW YEARS, a significant portion of Alberta's natural gas drilling and development activity has been centralized in the southeastern portion of Alberta (Fig, 1). During 1971, approximately 25% of Alberta's additions to gas reserves were credited to this area. The same proportion is expected to apply to the reserve additions for 1972. As of August/72, the initial marketable gas forecast for the Milk River and Medicine Hat zones amounted to 2.8 Tcf.

The recent study completed for the Alberta Government(1) indicates a gas reserve potential of 4 Tcf for the Suffield Block (currently a military reserve); once proven and developed, this could increase provincial gas reserves by 7%. The general industry activity forecast for southeastern Alberta for the next three years in currently undeveloped areas of reservoir potential could add an additional 4–6 Tcf of gas reserves to the provincial total.

Production from these shallow low-pressure reservoirs dates back to the very beginning of Alberta's gas industry. Natural gas was first discovered in the Province northwest of the town of Suffield by a well drilled in 1883 to the Milk River Formation, The much publicized Medicine Hat Field was discovered in 1904.

The performance of wells completed in the Milk River and Medicine Hat zones is typical of low-permeability reservoirs. Individual well rates are low. Recoveries are entirely dependent on the well productivity and the associated economics of production and compression. Because of these limitations, early production from the Milk River and Medicine Hat zones was primarily confined to local users. The low-cost energy source was quite successful, however, in attracting industry to the Medicine Hat area and was the beginning of the natural-gas-allied industry of the Province. As a matter of interest, in 1907, on a trip through the area and exposed to the many individual uses of natural gas, Rudyard Kipling exclaimed, "You people in this district have all hell for a basement".
Stability of Crude Oil-in-Water Enlulsions
Authors: Chen E.C.
Published: March 2010

A coulter counter was used to measure the droplet-size distribution of crude oil-in-water emulsion. The stability of the emulsion was determines by the decrease in oil concentration and the change in specific surface with time. All experiments core carried out at room temperature with initial oil to water volume ratios of 0.005 and 0.01. Six different types of crude oil were investigated. All of them behave similarly. Creaming was found to be pre-dominantly responsible for the instability of the emulsions. However, all the emulsion finally attained stability with an oil concentration or between 10−2 and 10−3 % volume, a specific surface of around 3 × 10 cm2/g and a droplet size belong 4 μm.

Introduction

WHEN CRUDE OIL SPILLS onto the surface of water, it spreads out into a layer the thickness of which depends on material properties and environmental conditions. Unless the spillage has been close to shore or the water is exceptionally calm, two types of emulsions will likely be formed(1) The oil-in-water emulsion, having droplets of oil dispersed in the water phase, is caused by the action of currents, wind, tides and waves and may be rendered stable by such hydrophilic groups a. - COO-, - OH, - CHO, - OSO3 and SO H which occur naturally in the crude. The water-in-oil emulsion consisting of droplets of water enclosed in sheaths of oil, is stabilized by the presence of various resinous and asphaltic materials which also occur naturally in crudes. The latter type of emulsion now generally referred to as "chocolate mousse", is known to be extremely stable(2,3). However, knowledge of the stability of the former, which is a useful input in assessing the effects of an oil spill has not yet been reported. The present work investigates the stability of crude oil-in-water emulsions by making use of a Coulter counter.

Experimental

Materials: Six different types of crude oil were used in this investigation. Their origin and physical properties are given in Table 1. The water was deionized, distilled and filtered twice using a Gel man membrane filter with a pore size of 0.2 μm. A 3% sodium chloride solution also filtered twice with the Gelman filte, was used as the diluent for the Emulsion and, at the same time served as the electrolyte solution for the Coulter counter. All the glassware employed was thoroughly washed and rinsed with filtered water. Traces of oil remaining in the glassware due to a previous experiment were removed by benzene and hot water.

Preparation of Emulsions: The crude (oil-in-water Emulsions were prepared using a Virtis 45 homogenizer as follows. The homogenizer falsely was first filled with 200 ml of water the crude oil was then pipetted in and the mixture was homogenized for 10 minutes at the medium speed (approximately 10,000 rpm). The emulsion as immediately transferred into a cylindrical separatory funnel and samples were withdrawn from the bottom at selected time intervals.
Computer Control of High-Pressure Sour Gas Wells, Kaybob South BHL Gas Unit No: 3
Authors: Kernaghan F.K.
Published: March 2010

This paper describes the computer- controlled supervisory and control system which was installed to measure and control production tram and injection into the gas wells of the Kaybob South Beaverhill Lake Gas Unit No. 3. Items to be covered include: reasons for installation of an automation, scheme in this field, initial configuration of the system, field installation and start-up, changes that have been made and an assessment of the systems performance after one year of operation.

Introduction

THE KAYBOB SOUTH BEAVERHILL LAKE GAS UNIT No. 3 is located approximately 130 miles west of Edmonton. The plant, which is one of the largest gas plants in North America, is located centrally in the 12- by 6-mile field. The terrain in this area is heavily wooded and has high relief, with ground elevations ranging from 2600 to 4150 feet above sea level.

Temperatures at the Kaybob plant range from -50 °F in the inter to +80 °F in the summer. Precipitation averages 75 inches of snow in the winter and 30 inches of rain in the summer.

The plant was designed for an inlet rate of 445 MMcf/D of very rich, sour gas, yielding a daily output of 3,065 long tons of elemental sulphur, 32,720 barrels of pentanes plus, 17,950 barrels of LPG's and 284 MMcf of dry residue gas. Of the residue gas, 54 MMcf is sold and the remaining 230 MMcf is re-injected into the formation in a recycling scheme designed to enhance the recovery of pentanes plus and sulphur.

Prior to plant start-up, the well count was 37 producing wells, 11 injection wells and one well that could be used as either an injector or a producer. The effluent from the producing wells is carried as two-phase flow through lateralpipelines to one of the three-trunk lines feeding the plant. These gathering lines operate at pressures of 1200 to 1500 psig and temperatures of 90 °F to 150 °F. At these conditions, the liquid hydrocarbon ratio is as high as 150 barrels per MMcf of gas.

The residue gas from the plant to the reinjection wells is carried in a three-trunk line to lateral sy.3terns operating- at a maximum discharge pressure of 4700 psig at the plant.

Reasons for Automation At Kaybob South

Operating problems within the gas plant make frequent cuts in plant inlet rate necessary. This could be accomplished by reducing the producing flow rates or diverting part of the inlet gas to flare. If consideration is given to pollution of the environment and conservation of energy resources, it is obvious that flaring of inlet gas is not acceptable.

A method of reducing well flow rates that is used by many gas plants is to increase the, back pressure that the plant exerts on the gathering system. Two-phase flow in pipelines installed in hilly terrain produces liquid heads wherever the flow is uphill. The amount of liquid build-up increases as the flow rate is reduced, up to the point at which the liquid starts to move as a slug.
The Influence of Freezing-Thawing On the Stability of Crude Oil-in-Water Emulsions
Authors: Chen E.C.
Published: March 2010

The effect of freezing-thawing on the stability of crude oil-in-water emulsions was studied. Four different types of crude at three freezing temperatures were investigated. The experimental methods were the same as those used in a previous investigation. It has been found that freezing-thawing causes an increase in the droplet size and lowers the oil-drop concentration in the emulsion.

INTRODUCTION

THE STABILITY of crude oil-in-water emulsions was the subject of a previous investigation(J). It has been found that crude oil and water form fairly stable oil-in- water emulsions if sufficient mixing energy is available. This means that when crude oil spills on water, a persistent oil-in-water emulsion may form due to the actions of currents, tides and waves. If the spillage occurs on an arctic water, where the temperature is above freezing point in daytime and below freezing during the night, the emulsion will then be subjected to freezing and thawing cycles. What is the fate of this emulsion? Will it behave differently from the emulsions not subjected to freezing and thawing? The present work attempts to obtain some answers to these questions.

Experimental

The experimental methods employed were the same as those used in the previous investigation(l), except that a Model T Coulter counter was used instead of the Model Z. The ''Model T is capable of counting simultaneously the number of droplets at 15 selected size ranges and thus completing an analysis within a few seconds. A 50-pm aperture tube was used and droplets down to 1 pm in size were counted.

Four different crudes, two from the Northwest Territories and two from Alberta, were investigated. The physical properties of the crudes are given in Table 1. The properties of Crude No, 3 are said to be close to those of the Prudhoe Bay crude.

Identical crude oil-in-water emulsions were prepared with an initial volume ratio (oil to water) of 0.05 and stored in wide-mouth, 16-ounce glass bottles. One sample was kept at room temperature throughout the period of the experiments, Other samples were allowed to stand at room temperature for one day and then were subjected to one or two freezing-thawing cycles. Freezing was carried out by placing the emulsions in a Revco Freezer for one day at −5, −15 find −40°C, respectively. Temperatures of the emulsion during freezing was recorded continuously by means of a probe which was placed centrally in the bottle.

(Figure in full paper)

The freezing took place as follows; the emulsion was first supercooled to a temperature T5 (T5 was about – 12, −8, −11 and −4ºC for Crude No. I, 2, 3 and 4, respectively) and began to solidify (at this point, the temperature rose suddenly to 0º C). The frozen emulsion remained at its freezing point, 0ºC, for several hours before it cooled down gradually to the temperature of the surroundings. It should be noted that at −5ºC, only the Crude No. 4 emulsion was frozen. Thawing was allowed to proceed at room temperature.
Design of Pipelines For Multiphase (Gas-Condensate) Flow
Authors: Gregory G.A. , Aziz K.
Published: March 2010

Problems peculiar to the design of multiphase (gas-liquid) pipelines are discussed using a multiphase-flow pipeline design program- A number of design methods currently used by the petroleum industry are compared in detail, with partieu1u"r reference to pipelines transporting natural gas – condensate mixtures. It is demonstrated that large differences in "predicted pressure drop may be obtained with different methods.

INTRODUCTION

IN SPITE OF THE FACT that many principles of single phase pipe flow also govern the pipe flow of gas liquid mixtures, in general, the design problem for the latter is unique. Because of complex interactions between the fluid phases, neither a rigorous analytical approach nor conventional single-phase flow correlations can usually be applied with much success. In this paper, some of the problems peculiar to two-phase flow are identified and pressure-drop predictions by a number of design methods currently used in the petroleum industry are compared for a typical gas-condensate pipeline.

Design Considerations For Two-Phase Flow

A number of characteristics of two-phase flow pose special problems for the pipeline designer that are not encountered with single-phase flow. These are discussed in detail in the book by Govier and Aziz(1) and will only be dealt with briefly here.

FLOW PATTERN

Depending on the relative gas and liquid flow rates, two-phase flow may exist as anything from a continuous gas phase with finely dispersed liquid droplets to a continuous liquid phase with finely dispersed gas bubbles. A number of well-defined flow patterns exist which result, in some cases, from the domination of buoyancy forces and, in others, from the domination of shear forces. It has been demonstrated by Mandhane et al.(4) and Gregory et al.(2) that the accuracy of most of the available friction-pressure-drop or in-situ-liquid- volume-fraction correlations can depend on the flow regime. It is thus important that the designer be able to predict the expected flow pattern from readily available information before performing his pressure-drop calculations. A number of correlations for doing this are available in the literature, including one recently proposed by Mandhane et al(J)

LIQUID HOLDUP

Almost invariably, the gas and liquid phases travel through a pipe at different velocities. This gives rise to a liquid holdup effect, because the fraction of the pipe volume occupied by the liquid phase under flowing conditions will be significantly different from the volume fraction of the liquid in the two-phase mixture entering the pipe. The total pressure losses for a two- phase mixture generally include a hydrostatic-bead contribution, which is calculated using a mixture density. Thus, the designer must be able to predict the in-situ liquid volume fraction under flowing conditions, as this is directly related to the mixture density. Numerous correlations are available in the literature for this purpose and, as noted above, these correlations may be more accurate for some flow regimes than others.
TheNorthSea-ANe\v Major Oil Province In a Changing World
Authors: Bexon R.
Published: March 2010

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

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

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

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

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

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.