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Chapter # 01

Introduction and scope of study

1.1 Introduction:

This project is related to viscosity reduction techniques and effect of viscosity reduction on

the brake horse power (BHP) of submersible especially duplex positive displacement pumps.

At the start we discussed some basics of heavy oils and their viscosity and the instruments

related to viscosity measurement , then there is detailed study of Enhanced oil recovery

(EOR) methods such as thermal flooding, water flooding and CO2 flooding with a main focus

on thermal recovery techniques and steam generation methods. After this different co relation

for dead, saturated and unsaturated heavy oils were thoroughly studied and compared. Some

portion is dedicated to steam injection and steam generators, in this portion we also discussed

the mathematical equations for steam injection, these equations enables us to calculate heat

transfer, and heat transfer area for a specific amount of steam injected during steam injection.

At the end there is solution of a sample problem, the result showed that only a differential of

100 0F can decrease the viscosity of dead oils in such a way that the required BHP for the

pump reduced by 50%.

1.2 Methodology:

First of all to understand the basics of heavy oil, we studied bulk and fractional properties of

heavy oil and different criteria of classification of heavy oils such as on the basis of

geographical location, API value, sulphur contents, density.

A heavy oil from Kuwaiti oil fields having API of 17O was taken as reference and its

viscosity was determined by using different co-relations such as Beal‟s co-relation, Beggs

and Robinson‟s co relation, and Glasso‟s co-relation. The viscosity was calculated for all

three basic types of heavy oils which are dead, saturated and unsaturated heavy oils. Then

effect of temperature on viscosity was analyzed for all type of co-relations by using different

values of temperature and inverse relation between temperature and viscosity was found in

calculations. Then root mean square value of viscosity was calculated and results from

different co relations were compared and percentage error was calculated from root mean

square value.

As effect of viscosity on pump work was motive of study, so to understand basics first we

studied basic terminologies and working of different types of pumps. Then effect of viscosity

on two basic types of pumps (Positive displacements and centrifugal) was studied and from

literature data, it was found that viscosity has a little effect on positive displacements pumps

than on centrifugal pumps. Therefore, positive displacement pumps are recommended for

viscous fluid pumping. And in positive displacement pumps, to improve performance and

reliability duplex and triplex type pumps are used in petroleum industry for pumping of

heavy oils. At the end a duplex type positive displacement pump was taken and effect of

reduced viscosity on brake horse power BHP) of the pump was studied.

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1.3 Review of previous work:

Different books and papers available in literature were studied including Reservoir

Engineering Handbook by Tarek Ahmed, Properties of Petroleum Reservoir Fluids by Burcik

E. J, Enhanced Oil Recovery by LATIL.M, heavy oil viscosity and density predictions at

normal and elevated temperatures by Osamah Alomair, Mohammad A.J.Ali, Abdullhaq

Alkoriem and Mohamed Hamed etc. In this literature different techniques for enhanced oil

recovery were present. A review of this work is given below.

Beal (1946) stated that it is highly unlikely to correlate the viscosity of the crude with high

accuracy due to the variation in compositions. Beal presented a chart that describes viscosity

of 655 dead oil samples at 38 oC. The samples represented 492 oil fields around the world,

covering viscosity rang of 0.8 to 155 cP, gravity range of 10.1 to 52.5 API, and temperatures

from 38 to 105 oC. Kartoatmdjo and Schmidt (1994) developed an empirical correlation to

measure the viscosity of dead oil of 3588 data point using 661 dead oil samples. The work

was done on temperature range of 75 to 320 oF, gravity range of 14.4 to 58.9 API covering

viscosity range of 0.5 to 682 cp. Labidi (1992) also correlated the dead oil viscosity as a

function of the temperature and the gravity. His correlation was developed using 91 data

points, covering viscosity range of 0.66 to 4.79 cP, temperature range of 38 to 152 oC and

API range of 32.2 to 48.0 API. Labidi claims that his Equation was more accurate than Beal

and Beggs which might have been true on his tight range of viscosity range, but it was found

to have a high error if applied out of this range. Hossain M.S. et. al. (2005) statistically

analyzed a data bank covering dead oil viscosities range of 22 to 415 cp and temperatures

range of 51 to 93 oF for oil samples with gravity in the range of 15.8 to 22.3 API.

1.4 Scope of study:

As we know that the performance of a pump can be improved by varying different factors

such as suction diameter, discharge diameter, length of stroke, swept volume, and density of

fluid. In heavy viscous oil reservoirs, we need to pump fluids having a high value of

viscosity. But as the pumps are designed on the basis of water viscosity, so when a viscous

fluid is pumped it causes a reduction in power or increase in cost to get a pump of higher

power. The alternative to improving above mentioned techniques for performance

improvements is to reduce the viscosity of heavy oils to save work by the pump. This

technique is preferable because overhauling or replacement of pumps is not required.

Differential of reservoir temperature by 100 oF reduces viscosity in such a way that brake

horse power of pump reduces by more than 50%. So in this way a lot of economic benefits

can be achieved.

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Chapter # 02

Heavy oils

2.1 What is heavy oil?

Heavy crude oil or extra heavy crude oil is oil that is highly viscous, and cannot easily flow

to production wells under normal reservoir conditions heavy oil is a type of crude oil

characterized by an asphaltic, dense, viscous nature (similar to molasses), and its asphaltene

(very large molecules incorporating roughly 90 percent of the sulfur and metals in the oil)

content. It also contains impurities such as waxes and carbon residue that must be removed

before being refined. Although variously defined, the upper limit for heavy oil is 22° API

gravity with a viscosity of 100 cp (centipoise).

In 2010, the World Energy Council defined extra heavy oil as crude oil having a gravity of

less than 10° and a reservoir viscosity of no more than 10 000 centipoises.

API Gravity:

A specific gravity scale developed by the American Petroleum

Institute (API) for measuring the relative density of various

petroleum liquids, expressed in degrees. API gravity is

gradated in degrees on a hydrometer instrument and was

designed so that most values would fall between 10° and 70°

API gravity. The arbitrary formula used to obtain this effect

is:

API gravity = (141.5/SG at 60°F) - 131.5,

where SG is the specific gravity of the fluid

2.2 Properties of heavy oils:

There are two basic types of properties of heavy oil

Bulk properties

Fractional properties

Bulk properties:

Bulk properties include specific gravity, sulfur content, nitrogen content, metal (Ni, V, Fe

etc.) content, asphaltene content, C/H ratio, pour point, flash point, freeze point, smoke point,

aniline point, cloud point, viscosity, carbon residue, light hydrocarbon yields (C1–C4), acid

number, refractive index and boiling point curve.

Figure 1: Oil classification

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Specific gravity:

We generally use the API (American Petroleum Institute) gravity to specify the specific

gravity (SG) of the crude oil as API = (141.5/SG) – 131.5. SG is the specific gravity defined

as the ratio of the density of the crude oil to the density of water both at 15.6 °C (60 °F). The

API gravity varies from less than 10 for very heavy crudes, to between 10 and 30 for heavy

crudes, to between 30 and 40 for medium crudes, and to above 40 for light crudes.

Sulfur contents:

The sulfur content is expressed as a percentage of sulfur by weight, and varies from less than

0.1% to greater than 5%. Crude oils with less than 1 wt.% sulfur are called low-sulfur or

sweet crude, and those with more than 1 wt.% sulfur are called high-sulfur or sour crude.

Sulfur-containing constituents of the crude oil include simple mercaptans (also known as

thiols), sulfides, and polycyclic sulfides.

Pour point:

The pour point is a measure of how easy or difficult to pump the crude oil, especially in cold

weather.

The pour point of an oil is the lowest temperature at which the oil will just flow, under

standard test conditions. The failure to flow at the pour point is usually attributed to the

separation of waxes from the oil, but can also be due to the effect of viscosity in the case of

very viscous oils. Also, particularly in the case of residual fuel oils, pour points may be

influenced by the thermal history of the sample, that is, the degree and duration of heating

and cooling to which the sample has been exposed. From a spill response point of view, it

must be emphasized that the tendency of the oil to flow will be influenced by the size and

shape of the container, the head of the oil, and the physical structure of the solidified oil. The

pour point of the oils is therefore an indication, and not an exact measure, of the temperature

at which flow ceases.

Water Content:

Some of the oil samples received by ESD contain substantial amounts of water. Because any

process that would separate the oil and water would also change the composition of the oil,

most properties were determined on the oils as received. Exceptions are noted in the

individual data tables. Therefore, for those oils with significant water contents (>5%), many

of the properties measured do not represent the properties of the „dry‟

Oil Density:

Density is defined as the mass per unit volume of a substance. It is most often reported for

oils in units of g/mL or g/cm3, and less often in units of kg/m3. Density is temperature-

dependent. The table below gives the density of fresh and salt water at various temperatures.

Oil will float on water if the density of the oil is less than that of the water. This will be true

of all fresh crude oils, and most fuel oils, for both salt and fresh water. Bitumens and certain

residual fuel oils may have densities greater than 1.0 g/mL and their buoyancy behaviour will

vary depending on the salinity and temperature of the water. The density of spilled oil will

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also increase with time, as the more volatile (and less dense) components are lost. After

considerable evaporation, the density of some crude oils may increase enough for the oils to

submerge below the water surface.

Two density-related properties of oils are often used: specific gravity and American

Petroleum Institute (API) gravity. Specific gravity (or relative density) is the ratio, at a

specified temperature, of the oil density to the density of pure water. The API gravity scale

arbitrarily assigns an API gravity of 10° to pure water.

Fractional properties:

Fractional properties of the oil sample that reflects the property and composition for specific

boiling point range to properly refine it into different end products such as gasoline, diesel

and raw materials for chemical process. Fractional properties usually contains paraffins,

naphthenes and aromatics (PNA) contents, sulfur content, nitrogen content for each boiling-

point range, octane number for gasoline, freezing point, cetane index and smoke point for

kerosene and diesel fuels.

2.3 Classification of crude oils:

Classification of crude oil is based upon these important bases

Classification on the bases of geographical location

Classification on the bases of API‟s

Classification on the bases of sulphur contents

Classification on the bases of density

Classification on the bases of geographical location

Benchmark oils are used as references when pricing oils. There are approximately 161

different benchmark oils, of which the main three West Texas Intermediate, Brent Crude, and

Dubai Crude. Crude oil is the most actively traded commodity and is bought and sold in

“contracts.” A contract trades in units of 1,000 barrels of oil and benchmarks help to

determine the price of a barrel of oil in a contract.

Classification on the bases of API’s

API gravity is calculated using the specific gravity of an oil, which is nothing more than the

ratio of its density to that of water (density of the oil/density of water). Specific gravity for

API calculations is always determined at 60 degrees Fahrenheit. API gravity is found as

follows:

API gravity = (141.5/Specific Gravity) – 131.5

Though API values do not have units, they are often referred to as degrees. So the API

gravity of West Texas Intermediate is said to be 39.6 degrees. API gravity moves inversely to

density, which means the denser an oil is, the lower its API gravity will be. An API of 10 is

equivalent to water, which means any oil with an API above 10 will float on water while any

with an API below 10 will sink.

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The API gravity is used to classify oils as light, medium, heavy, or extra heavy. As the

“weight” of an oil is the largest determinant of its market value, API gravity is exceptionally

important. The API values for each “weight” are as follows

Heavy oil (Class A) has a specific gravity between 18 and 25 °API and viscosity ranging

from 10 to 100 cP.

Extra-heavy oils (Class B) has a specific gravity below 20 °API and viscosity of up to

10,000 cP.

Oil sands and bitumen (Class C) have a specific gravity in the range of 7 to 9 °API and

viscosity above 10,000 cP.

Classification on the bases of Sulphur contents

Two main types on the sulphur contents

Sweet

Sour

Sweet:

The terms sweet and sour are a reference to the sulfur content of crude oil. Early prospectors

would taste oil to determine its quality, with low sulfur oil actually tasting sweet. Crude is

currently considered sweet if it contains less than 0.5% sulfur. Sweet crude is easier to refine

and safer to extract and transport than sour crude. Because sulfur is corrosive, light crude also

causes less damage to refineries and thus results in lower maintenance costs over time. Due to

all these factors, sweet crude commands up to a $15 dollar premium per barrel over sour.

Major locations where sweet crude is found include the Appalachian Basin in Eastern North

America, Western Texas, the Bakken Formation of North Dakota and Saskatchewan, the

North Sea of Europe, North Africa, Australia, and the Far East including Indonesia.

Sour:

Sour crude oil will have greater than 0.5% sulfur and some of this will be in the form of

hydrogen sulfide. Sour crude also contains more carbon dioxide.

Sour crude is more common in the Gulf of Mexico, Mexico, South America, and Canada.

Crude produced by OPEC Member Nations also tends to be relatively sour, with an average

sulfur content of 1.77%.

Classification on the bases of density:

Crude oil may be considered light if it has low density or heavy if it has high density. If the

raw petroleum is of a high density then the petroleum classification is termed „heavy' and if it

is of a low density the petroleum classification is termed 'light'. Density of oil is determined

by the length of the hydrocarbons it contains. If it contains a great deal of long-chain

hydrocarbons, the petroleum will be denser. If it contains a greater proportion of short-chain

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hydrocarbons it will be less dense. Besides chain length, the ratio of carbon to hydrogen also

helps to determine the density of a particular hydrocarbon. The greater the amount of

hydrogen in relation to carbon, the lighter the hydrocarbon will be. Less dense oil will float

on top of denser oil and is generally easier to pump.

Classification on the bases of hydro-carbons contents:

Hydrocarbons in crude oil can generally be divided into three categories:

Paraffins:

These can make up 15 to 60% of crude and have a carbon to hydrogen ratio of 1:2, which

means they contain twice the amount of hydrogen as they do carbon. These are generally

straight or branched chains, but never cyclic (circular) compounds. Paraffins are the desired

content in crude and what are used to make fuels. The shorter the paraffins are, the lighter the

crude is.

Napthenes:

These can make up 30 to 60% of crude and have a carbon to hydrogen ratio of 1:2. These are

cyclic compounds and can be thought of as cycloparaffins. They are higher in density than

equivalent paraffins and are more viscous.

Aromatics:

These can constitute anywhere from 3 to 30% of crude. They are undesirable because burning

them results in soot. They have a much less hydrogen in comparison to carbon than is found

in paraffins. They are also more viscous. They are often solid or semi-solid when an

equivalent paraffin would be a viscous liquid under the same conditions

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Chapter # 03

Viscosity Basic and Measurement Techniques

3.1 What is viscosity?

The viscosity of a fluid is a measure of its resistance to gradual deformation by shear

stress or tensile stress.

For liquids, it corresponds to the informal notion of "thickness". For

example, honey has a higher viscosity than water.

3.2 Factors that Affect Viscosity:

Attraction between the particles.

Space between the particles.

The speed of the particle movement.

The amount of energy in the particles (heat).

3.3 Types of viscosity:

There are following types of viscosity.

Dynamic viscosity

Kinematics viscosity

Bulk viscosity

Dynamic viscosity:

The dynamic (shear) viscosity of a fluid expresses its resistance to shearing flows, where

adjacent layers move parallel to each other with different speeds.

Units

Poise

Poise (symbol: P):

Named after the French physician Jean Louis Marie Poiseuille (1799–1869), this is the cgs

unit of viscosity, equivalent to dyne-second per square centimeter. It is the viscosity of a fluid

in which a tangential force of 1 dyne per square centimeter maintains a difference in velocity

of 1centimeter per second between two parallel planes 1 centimeter apart .

Kinematic viscosity:

The kinematic viscosity is the ratio of the dynamic viscosity μ to the density of the fluid ρ. It

is usually denoted by the Greek letter nu (ν). It is a convenient concept when analyzing

the Reynolds number, which is expressed as the ratio of inertial forces to the viscous forces:

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e

uL LR

(1)

Units:

Stokes

Stokes (symbol: St):

This is the cgs unit, equivalent to square centimetre per second. One stokes is equal to the

viscosity in poise divided by the density of the fluid in g cm–3. It is most usually encountered

as the centistokes (cSt) (= 0.01 stokes).

Bulk viscosity

When a compressible fluid is compressed or expanded evenly, without shear, it may still

exhibit a form of internal friction that resists its flow. These forces are related to the rate of

compression or expansion by a factor σ, called the volume viscosity, bulk viscosity or second

viscosity.

3.4 Laws related to Viscosity:

Newton’s law of viscosity:

Viscosity is the physical property that characterizes the flow resistance of simple fluids.

Newton's law of viscosity defines the relationship between the shear stress and shear rate of a

fluid subjected to a mechanical stress. The ratio of shear stress to shear rate is a constant, for

a given temperature and pressure, and is defined as the viscosity or coefficient of viscosity.

Newtonian fluids obey Newton's law of viscosity. The viscosity is independent of the shear

rate.

u

y

(2)

where F

A and

u

y

is the local shear velocity.

Stoke’s law:

In 1851, George Gabriel Stokes derived an expression, now known as Stokes' law, for the

frictional force – also called drag force – exerted on spherical objects with very

small Reynolds numbers(e.g., very small particles) in a continuous viscous fluid. Stokes' law

is derived by solving the Stokes flow limit for small Reynolds numbers of the Navier–Stokes

equations

6dF Rv (3)

Figure 2: Newton's law

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Where Fd is the frictional force known as Stokes' drag acting on the interface between the

fluid and the particle (in N), μ is the dynamic viscosity (kg /m*s),R is the radius of the

spherical object (in m), and v is the particle's velocity (in m/s).

3.5 Newtonian and non-Newtonian fluids

Newtonian Fluids:

A fluid that behaves according to Newton‟s law, with a viscosity μ that is independent of the

stress, is said to be Newtonian.

Gases, water and many common liquids can be considered Newtonian in ordinary conditions.

Non-Newtonian fluids:

There are many non-Newtonian fluids that significantly deviate from that law in some way or

other.

For example:

Shear thickening liquids, whose viscosity increases

with the rate of shear stress.

Shear thinning liquids, whose viscosity decreases with

the rate of shear stress.

Thixotropic liquids, that become less viscous over time

when shaken, agitated, or otherwise stressed.

Rheopectic liquids, that become more viscous over

time when shaken, agitated, or otherwise stressed.

Bingham plastics that behave as a solid at low stresses

but flows as a viscous fluid at high stresses.

3.6 Viscid and inviscid fluids:

When two fluid layers move relative to each other, a

friction force develops between them and the slower layer

tries to slow down the faster layer. This internal

resistance to flow is quantified by the fluid property

viscosity, which is a measure of internal stickiness of the

fluid. Viscosity is caused by cohesive forces between

the molecules in liquids and by molecular collisions in

gases. There is no fluid with zero viscosity, and thus all

fluid flows involve viscous effects to some degree. However,

in many flows of practical interest, there are regions (typically regions not close to solid

surfaces) where viscous forces are negligibly small compared to inertial or pressure forces.

Figure 3: Shear stress vs. Strain

Figure 4: Viscid and Inviscid fluids

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3.7 Viscosity Measurements:

Rheology:

It is the study of the flow of matter, primarily in the liquid state, but also as 'soft solids' or

solids under conditions in which they respond with plastic flow rather than deforming

elastically in response to an applied force. It applies to substances which have a complex

microstructure, such as muds, sludges, suspensions, polymers and other glass

formers (e.g.,silicates), as well as many foods and additives, bodily fluids (e.g., blood) and

other biological materials or other materials which belong to the class of soft matter.

Viscosity is measured with various types of viscometers and rheometers.

Rheometer:

It is a laboratory device used to measure the way in which a liquid, suspension or slurry flows

in response to applied forces. It is used for those fluids which cannot be defined by a single

value of viscosity and therefore require more parameters to be set and measured than is the

case for a viscometer. It measures the rheology of the fluid.

Viscometers:

There are following viscosity meters.

U-tube viscometers:

These devices also are known as glass capillary viscometers or Ostwald viscometers, named

after Wilhelm Ostwald. Another version is the Ubbelohde viscometer, which consists of a U-

shaped glass tube held vertically in a controlled temperature bath. In one arm of the U is a

vertical section of precise narrow bore (the capillary). Above this is a bulb, with it is another

bulb lower down on the other arm. In use, liquid is drawn into the upper bulb by suction, then

allowed to flow down through the capillary into the lower bulb. Two marks (one above and

one below the upper bulb) indicate a known volume. The time taken for the level of the liquid

to pass between these marks is proportional to the kinematic viscosity. Most commercial

units are provided with a conversion factor, or can be calibrated by a fluid of known

properties. The time required for the test liquid to flow through a capillary of a known

diameter of a certain factor between two marked points is measured. By multiplying the time

taken by the factor of the viscometer, the kinematic viscosity is obtained.

Figure 5: U-tube viscometer

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Falling sphere viscometers:

Stokes' law is the basis of the falling sphere viscometer, in which the

fluid is stationary in a vertical glass tube. A sphere of known size and

density is allowed to descend through the liquid. If correctly selected, it

reaches terminal velocity, which can be measured by the time it takes to

pass two marks on the tube. Electronic sensing can be used for opaque

fluids. Knowing the terminal velocity, the size and density of the

sphere, and the density of the liquid, Stokes' law can be used to

calculate the viscosity of the fluid. A series of steel ball bearings of

different diameter are normally used in the classic experiment to

improve the accuracy of the calculation.

In 1851, George Gabriel Stokes derived an expression for the frictional

force (also called drag force) exerted on spherical objects with very

small Reynolds numbers (e.g., very small particles) in a continuous viscous fluid by changing

the small fluid-mass limit of the generally unsolvable Navier-Stokes equations:

6dF Rv

If the particles are falling in the viscous fluid by their own weight, then a terminal velocity,

also known as the settling velocity, is reached when this frictional force combined with

the buoyant force exactly balance the gravitational force. The resulting settling velocity

(or terminal velocity) is given by:

22 ( )

9

p f

s

r gV

(4)

Where

Vs = particles' settling velocity (m/s) (vertically downwards if p f , upwards if p f ),

=Stokes radius of the particle (m),

g = gravitational acceleration (m/s2),

ρp =density of the particles (kg/m3),

ρf = density of the fluid (kg/m3), and

=(dynamic) fluid viscosity (Pa s).

Note that Stokes flow is assumed, so the Reynolds number must be small.

Figure 6: Falling sphere viscometer

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Falling Piston Viscometer:

It is also known as the Norcross viscometer after its inventor,

Austin Norcross. The principle of viscosity measurement in

this rugged and sensitive industrial device is based on a

piston and cylinder assembly. The piston is periodically

raised by an air lifting mechanism, drawing the material

being measured down through the clearance (gap) between

the piston and the wall of the cylinder into the space which is

formed below the piston as it is raised. The assembly is then

typically held up for a few seconds, then allowed to fall by

gravity, expelling the sample out through the same path that

it entered, creating a shearing effect on the measured liquid,

which makes this viscometer particularly sensitive and good for measuring

certain thixotropic liquids.

The time of fall is a measure of viscosity, with the clearance between the piston and inside of

the cylinder forming the measuring orifice. The viscosity controller measures the time of fall

(time-of-fall seconds being the measure of viscosity) and displays the resulting viscosity

value. The controller can calibrate the time-of-fall value to cup seconds (known as efflux

cup), Saybolt universal second (SUS) or centipoise.

Figure 7: Falling piston viscometer

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Chapter # 04

Pumps

4.1 What is a Pump?

Pumps are the devices that convert the mechanical energy into fluid energy.

4.2 Basic terminology related to pumps:

Control volume:

Limits imposed for the theoretical study of a system. The limits are usually set to intersect the

system at locations where conditions are known.

Datum plane:

A reference plane. A conveniently accessible known surface from which all vertical

measurements are taken or referred to.

Friction:

The force produced as reaction to movement. All fluids produce friction when they are in

motion. The higher the fluid viscosity, the higher the friction force for the same flow rate.

Friction is produced internally as one layer of fluid moves with respect to another and also at

the fluid/wall interface.

Viscosity:

A property, which measures a fluid's resistance to movement. The resistance is caused by

friction between the fluid and the boundary wall and internally by the fluid layers moving at

different velocities

Vapor pressure:

The pressure at which a liquid boils at a specified temperature

Head:

Refers to the pressure produced by a vertical column of fluid

Suction Static Head:

The difference in elevation between the liquid level of the source of supply and the centerline

of the pump. This head also includes any additional head that may be present at the suction

tank fluid surface.

Discharge Static Head:

The difference in elevation between the liquid level of the discharge tank and the centerline

of the pump. This head also includes any additional head that may be present at the discharge

tank fluid surface.

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Suction Static Lift:

The same definition as the Suction Static head. This term is only used when the pump

centerline is above the suction tank fluid surface.

Total Static Head:

It is the difference between the discharge and suction static head including the difference

between the surface pressure of the discharge and suction tanks

Friction head difference:

The difference in head required to move a mass of fluid from one position to another at a

certain flow rate

Velocity Head difference:

It is the difference in velocity head between the outlet and inlet of the system.

Total Head:

The difference between the head at the discharge and suction flange of the pump

Total Dynamic Head:

It is the Identical to Total Head. This term is no longer used and has been replaced by the

shorter.

Shut-off head:

The Total Head corresponding to zero flow on the pump performance curve

Negative pressure:

Pressure that is less than the pressure in the external environment..

Net Positive Suction Head (N.P.S.H.):

The head in feet of water absolute as measured or calculated at the pump suction flange, less

the vapor pressure (converted to feet of water absolute) of the fluid.

Performance curve:

A curve of flow vs. Total Head for a specific pump model and impeller diameter.

Operating point:

The point on the system curve corresponding to the flow and head required to meet the

process requirements.

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Best Efficiency Point (B.E.P.):

The point on a pump's performance curve that corresponds to the highest efficiency.

4.3 Classification of pumps

This classification is based on the mechanical method through which mechanical energy is

transferred.

Positive displacement pumps

Gear

Vane screw

Progressing cavity

Lobe or cam

Pump Formulas

Variable Word Formula w/ Units Simplified Formula

Pump Output Flow –

GPM

GPM = (Speed (rpm) × disp. (cu. in.))

/ 231

GPM = (n ×d) / 231

Pump Input

Horsepower – HP

HP = GPM × Pressure (psi) / 1714 ×

Efficiency

HP = (Q ×P) / 1714 × E

Pump Efficiency – E Overall Efficiency = Output HP /

Input HP

EOverall = HPOut / HPIn X 100

Overall Efficiency = Volumetric Eff.

× Mechanical Eff.

EOverall = EffVol. × EffMech.

Pump Volumetric

Efficiency – E

Volumetric Efficiency = Actual Flow

Rate Output (GPM) / Theoretical Flow

Rate Output (GPM) × 100

EffVol. = QAct. / QTheo. X

100

Pump Mechanical

Efficiency – E

Mechanical Efficiency = Theoretical

Torque to Drive / Actual Torque to

Drive × 100

EffMech = TTheo. / TAct. ×

100

Pump Displacement –

CIPR

Displacement (In.3 / rev.) = Flow Rate

(GPM) × 231 / Pump RPM

CIPR = GPM × 231 /

RPM

Pump Torque – T Torque = Horsepower × 63025 / RPM T = 63025 × HP / RPM

Torque = Pressure (PSIG) × Pump

Displacement (CIPR) / 2π

T = P × CIPR / 6.28

Table 1: Pump Formulae

Page | 17

Kinetic pumps

Radial flow (centrifugal)

Axial flow ( propeller)

Mixed flow.

Figure 8: Pump classification

4.4 Positive Displacement Pumps:

Positive displacement pumps are distinguished by the way they operate: liquid is

taken from one end and positively discharged at the other end for every revolution.

In all positive displacement type pumps, a fixed quantity of liquid is pumped after

each revolution. So if the delivery pipe is blocked, the pressure rises to a very high

value, which can damage the pump.

Positive displacement pumps are widely used for pumping fluids other than water,

mostly viscous fluids.

Positive displacement pumps are further classified based upon the mode of displacement:

Reciprocating pump if the displacement is by reciprocation of a piston

plunger. Reciprocating pumps are used only for pumping viscous liquids and

oil wells.

Page | 18

Rotary pumps If the displacement is by rotary

action of a gear, cam or vanes in a chamber of

diaphragm in a fixed casing. Rotary pumps are

further classified such as internal gear, external

gear, lobe and slide vane etc. These pumps are

used for special services with particular

conditions existing in industrial sites.

4.5 Dynamic or Kinetic pumps:

These are also characterized by their mode of operation: a rotating impeller converts kinetic

energy into pressure or velocity that is needed to pump the fluid.

There are two types of dynamic pumps:

Centrifugal pumps are the most common pumps used for pumping water in

industrial applications. Typically, more than 75% of the pumps installed in an

industry are centrifugal pumps.

Special effect pumps are particularly used for specialized conditions at an

industrial site ( axial or mixed flow).

A centrifugal pump is one of the simplest

pieces of equipment in any process plant.

The figure shows how this type of pump

operates:

Liquid is forced into an impeller

either by atmospheric pressure, or

in case of a jet pump by artificial

pressure.

The vanes of impeller pass kinetic

energy to the liquid, thereby causing the liquid to rotate. The liquid leaves the

impeller at high velocity.

The impeller is surrounded by a volute casing or in case of a turbine pump a

stationary diffuser ring. The volute or stationary diffuser ring converts the kinetic

energy into pressure energy.

Figure 9: Positive displacement pump

Figure 10: Dynamic pump

Page | 19

When to use a Positive Displacement Pump

When to use a centrifugal or a Positive Displacement pump ("PD Pump") is not always a

clear choice. To make a good choice between these pump types it is important to understand

that these two types of pumps behave very differently.

Flow rate versus pressure

By looking at the performance chart to the right you can

see just how different these pumps are. The centrifugal has

varying flow depending on pressure or head, whereas the

PD pump has more or less constant flow regardless of

pressure.

Flow rate versus viscosity

Another major difference between the pump types is the

effect; viscosity has on the capacity of the pump. You will

notice in the flow rate chart how the centrifugal pump loses

flow as the viscosity goes up but the PD pump's flow

actually increases. This is because the higher viscosity

liquids fill the clearances of the pump causing a higher

volumetric efficiency. Remember, this chart shows only the

effect of viscosity on the pump flow; when there is a

viscosity change there is also greater line loss in the system. This means you will also have to

calculate the change in pump flow from the first chart

for this pressure change.

Efficiency versus pressure

The pumps behave very differently when considering

mechanical efficiency as well. By looking at the

efficiency chart to the right you can see the impact of

pressure changes on the pump's efficiency. Changes in

pressure have little effect on the PD pump but a dramatic

one on the centrifugal.

Efficiency versus viscosity

Viscosity also plays an important role in pump mechanical

efficiency. Because the centrifugal pump operates at

motor speed, efficiency goes down as viscosity increases

due to increased frictional losses within the pump.

Graph 1: head vs. flow rate

Graph 2: Flow rate vs. viscosity

Graph 3: efficiency vs. pressure

Graph 4: Efficiency vs. viscosity

Page | 20

Net Positive Suction Head Requirements

Another consideration is NPSHR. In a centrifugal the NPSHR varies as a function of flow,

which is determined by pressure and viscosity as discussed above. In a PD pump, NPSHR

varies as a function of flow which is determined by speed. The lower the speed of a PD

pump, the lower the NPSHR.

Operating at different points on the curve

Another thing to keep in mind when comparing the two types of pumps is that a centrifugal

pump does best in the center of the curve. As you move either to the left or right, additional

considerations come into play. If you move far enough to the left or right, pump life is

reduced due to either shaft deflection or increased cavitation. With a PD pump you can

operate the pump on any point of the curve. In fact the volumetric efficiency as a percent

actually improves at the high speed part of the curve. This is due to the fact that the

volumetric efficiency is affected by slip, which is essentially constant. At low speed the

percentage of slip is higher than at high speed.

The data presented in these charts is the actual data for a specific application. The centrifugal

was picked at its Best Efficiency Point (BEP) and the PD pump (Internal Gear) was selected

to match the flow, viscosity, and pressure. Different applications will have different curves

and efficiencies. These curves are presented as an example of the performance behavior

differences of the two pump principles.

Pump Selection Scenarios

Now that you have a clearer understanding of the performance differences between these two

pump principles, when would you choose to use a PD pump? The following chart lists several

such scenarios.

High Viscosity

As illustrated by the graphs above, even modest viscosities dramatically affect the flow rate

and efficiency of a centrifugal pump. While many centrifugal are cataloged to 1,000 cSt and

higher, PD pumps are clearly the better choice when considering the high energy costs

resulting from this lost efficiency.

Operating Away from the Middle of the Curve

Centrifugal do not operate well when being run too far off the middle of the curve. At best,

this results in reduced efficiency which would require larger motors and higher energy costs.

At worst, this can result in cavitation damage, shaft deflection, and premature pump failure.

PD pumps on the other hand can be run at any point on their curve without damaging the

pump or greatly affecting the efficiency.

Page | 21

Variations in Pressure

The first graph above clearly illustrates the effect that even modest changes in pressure can

have on the flow rate of a centrifugal pump. Additional restrictions such as debris in a filter,

corroded / rough piping, or a valve left too far closed (or too far open) can have a dramatic

effect on a centrifugal pump's flow rate and efficiency. PD pumps maintain their flow rate

and efficiency even with significant changes in pressure.

Variations in Viscosity

Many liquids vary in viscosity depending on temperature or due to chemical reaction. A rise

in viscosity will independently alter the flow rate and efficiency. Add to that the rise in

pressure due to the increase in frictional line losses and PD pumps become the clear choice

for variable viscosity applications.

High Pressures

While some centrifugal can be run in series to boost their pressures, none can compete with

PD pumps for high pressure applications. Pressure limits will depend on the design of each

pump, but pressures of 250 PSI (580 feet) are not unusual for a PD pump, with some models

going over 3,000 PSI (7,000 feet). The capability for a PD pump to produce pressure is so

great that some type of system overpressure protection is required.

Shear Sensitive Liquids

Generally speaking, pumps tend to shear liquids more as speed is increased and centrifugals

are high speed pumps. This makes PD pumps better able to handle shear sensitive liquids.

Suction Lift Applications

By their nature, PD pumps create a vacuum on the inlet side, making them capable of

creating a suction lift. Standard ANSI centrifugals do not create a vacuum and cannot create a

suction lift. There are self-priming centrifugal designs that can lift liquid an average of 15

feet when partially filled (13" hg vacuum). Many dry PD pumps can pull that or better and

wetted PD pumps (a pump that is not full of liquid but with some liquid in it) can often reach

vacuums of 25 to 28" hg. PD pumps are the logical choice when a suction lift is required.

Page | 22

Chapter # 05

Enhanced Oil Recovery

5.1 What is Enhanced Oil Recovery?

There are three basic types of recovery of oil.

Primary oil recovery

Secondary oil recovery

Tertiary oil recovery

In primary oil recovery, oil has sufficient pressure that it moves itself through the well.

Secondary recovery is used where pressure is not sufficient and all we need to do to recover

oil is to maintain its pressure. Water flooding is generally used for this purpose. Normally 20

to 40 percent of oil can be recovered using primary and secondary recovery. Tertiary

recovery is that type of recovery in which we use different techniques to extract oil from

reservoirs where its natural pressure is not sufficient to extract oil through well. This tertiary

recovery is called Enhanced Oil Recovery and sometimes secondary recovery is also

considered under Enhanced Oil Recovery.

Enhanced Oil Recovery (abbreviated EOR) is a generic term for techniques for increasing the

amount of crude oil that can be extracted from an oil field. Enhanced oil recovery is also

called improved oil recovery or tertiary recovery (as opposed to primary and secondary

recovery). Sometimes the term quaternary recovery is used to refer to more advanced,

speculative, EOR techniques. Using EOR, 30 to 60 percent or more of the reservoir's original

oil can be extracted, compared with 20 to 40 percent using primary and secondary recovery.

5.2 Methods of Enhanced Oil Recovery

There currently are several different methods of enhanced oil recovery including steam flood

and water flood injection and hydraulic fracturing. Following are available methods.

Water flooding and Gas injection

Use of surfactants to stabilize emulsions

Use of carbon dioxide

Heating

Page | 23

Water Flooding and Gas injection:

Water flooding methods generally falls under secondary recovery methods category. It is one

of the oldest methods in enhanced oil recovery. In 1970 80% of enhanced oil recovery was

carried by this method. Along with enhanced oil recovery this method is also used sometimes

to maintain the pressure of reservoir and in that case this will not be called as enhanced oil

recovery. Now both gas and water injection has some advantages and disadvantages. Gas

injection falls under two categories.

Miscible gas injection

Non-miscible gas injection

Now both technical and economic considerations are to be made before deciding which

method is to be used.

If all conditions are suitable for both methods, then water flooding is to be preferred, as the

mobility ratio is higher in this case. In reservoirs containing under saturated oil, water

flooding is suitable, because a low gas-oil ratio would result in requirement of large amount

of gas for recovery. In reservoirs containing saturated oil, water flooding is preferred as long

as permeability of water is sufficiently high. And if conditions are suitable for gas injection

miscible gas injection is more suitable as compared to non-miscible gas injection.

Use of surfactants

One of the methods utilized in the transportation of heavy crude oil is the formation of the

emulsions. In such a method the heavy oil is suspended as micro-spheres stabilized in a water

continuous phase by the use of surfactants and detergents forming an O/W emulsion, and thus

achieving a reduction in the apparent viscosity. The emulsified solvent flooding can

potentially provide the high recovery efficiency of miscible solvents at a fraction of the cost.

Surfactants reduce viscosity by reducing the surface tension of a liquid while fibers and

polymers orient themselves in the main direction of the flow, limiting eddies appearance

which results in drag reduction. This method was first introduced in 1920‟s but was

considered as a failed attempt. Later it was found that the failure actually occurred because

interfacial tension was not reduced sufficiently to have an effect on trapped oil.

To use a surfactant it is necessary to reduce the interfacial tension between oil and surfactant

bearing water to a level of 0.01 to 0.001dyns/cm and to maintain this level during

displacement of oil. This reduction in interfacial tension can be achieved by using sodium

Page | 24

chloride concentration (0.2 to 0.3 moles/litter). Thus it is necessary to inject water of certain

salinity before injecting the surfactant solution. This thing flushes away the accumulated

brine which is a hindrance in the way of contact between heavy oil and surfactant solution.

Surfactants used today are petroleum sulphonates. These are cheaper, easy to use and have a

high interfacial activity. Further efforts are being made to understand the action of surfactants

and it has been found that there is a relationship between the amount of reduction of

interfacial tension and equivalent weight of surfactant (the equivalent weight is the ratio of

molecular weight to the number of sulphonate groups present in molecule), and it has been

found that surfactant with high equivalent weights cause a greater reduction in interfacial

tension between oil and surfactant being used.

Disadvantages

The main problem with technique is the proper selection of surfactants and their cost. The

surfactants should not only stabilize the emulsion, but it should also be easily separates at the

final destination.

Use of carbon dioxide

Carbone dioxide can be used as a gas or dissolved in water. Carbon dioxide has a very high

solubility in oil and very less solubility in water, so this thing results in

A large reduction in oil viscosity and less increase in oil viscosity. This causes a

significant improvement in oil mobility in the reservoir.

Swelling of oil from 10 to 20% depending on its type and composition.

A reduction in oil density.

A lowering of interfacial tension.

Chemical action on carbonate and shaly rocks.

Disadvantages

High cost of CO2 is important issue in use of this technique and is the major reason for this

method not being used commercially. Some field tests are done but commercial applications

are limited so far because of this economic factor.

Heating

The basic difference between this method and other method lies in the fact that fluids used in

this method supply heat to reduce the viscosity of heavy oil. Viscosity of fluid falls

sufficiently with rise in temperature. For example it has been seen experimentally for a crude

Page | 25

oil that has a viscosity of 50,000 CST at 40oC and less than 20,000 CST at 50

oC. So this

shows the significance of thermal recovery methods. A very small increase in temperature

can cause a large drop in viscosity of oil. A figure explaining the relationship between the

rise in temperature and reduction in viscosity is given below. This was experimentally

determined for different crude oils.

This figure clearly shows the reduction in viscosity by increase in temperature.

Now to have a complete understanding of reduction of viscosity with rise in temperature, we

must have some relationship between these two quantities i-e temperature and viscosity.

Various co-relations are available to the date and each having certain constraints. Some

important of these are discussed here.

Graph 5: temperature vs. viscosity

Page | 26

5.3 Oil Viscosity Co-Relations:

Various co-relations are available in literature and can be divided on the basis of heavy oil for

which they are applicable. Basically co-relations are divided into 3 categories being Dead,

Saturated and Under-Saturated. These three can be defined as follow

Under-saturated oil contains gas in solution, but not as much as it can possibly contain.

Therefore its temperature can be raised, or its pressure reduced, by a certain amount before

gas bubbles start to form in it. "Dead" oil is the extreme case when there is no dissolved gas

at all and saturated oil has all the gas in solution that it possibly can, so the slightest increase

in temperature or decrease in pressure will cause gas bubbles to form as the gas begins to

come out of solution

Most of the co-relations relate viscosity of heavy oils with temperature and oAPI. Where

oAPI can be defined as

oAPI=(141.5/RD)-131.5

where RD= relative density which can be defined as the ratio of density of oil to density of

standard fluid. Water is usually taken as standard fluid also known as specific gravity.

RD= Density of oil/Density of water

Some important co-relations used to determine the viscosity of dead oils are given below.

In 1946 Beal took 753 values of viscosity at and above 100oF and developed a graphical co-

relation which was published in the form of equation in 1981, to determine the viscosity of

dead oils. According to his co-relation viscosity of dead oil depends upon temperature and

API gravity. His co-relation is given below.

7

4.53

1.8(10 ) 3600.32

260

a

odAPI T

(5)

Where

8.330.43

10 APIa

Page | 27

and

μod= viscosity of dead oil at 14.7psia and reservoir temperature in cp.

And

T= Temperature, oR

Similarly Beggs and Robinson in 1975 developed a co-relation for to determine the viscosity

of dead oils. For this derivation a data set of 460 viscosity measurements were used. Its

mathematical form is given here.

10 1x

od (6)

Where

1.163

460x y T

10zy

3.0324 0.02023oz API

An average error of -0.64 with a standard deviation of 13.53% was reported when tested

again the data set used to derive this co-relation.

Another co-relation for finding the viscosity of dead oil was given by Glaso in 1980. This co-

relation was developed by taking a sample of 26 oils. It‟s mathematical for is given below.

10 3.4443.141 10 460 loga

od T API (7)

Where

10.313 log 460 36.447a T

Page | 28

This expression is found to be valid for a temperature range of 50-300oF and for API gravity

ranging from 20o to 48

o.

In 1989 Sutton and Farshad concluded that this co-relation derived by Glaso is the most

accurate among Beal‟s Beggs-Robinson‟s and Glasso‟s co-relation.

Now some co-relations to determine the viscosity of saturated oils are given here.

In 1959 Chew and Connally presented a graphical co-relation which was derived as a

mathematical formula in 1977. Its mathematical form is given here.

Here.

10ba

ob od (8)

With

7 42.2 10 7.4 10s sa R R

0.68 0.25 0.062

10 10 10c d eb

58.62 10 sc R

31.1 10 sd R

33.74 10 se R

μob= viscosity of oil at bubble point pressure, cp

and

μod= viscosity of dead oil at 14.7psia and reservoir temperature, cp

The data that was used to develop this co-relation falls under following limitations.

Page | 29

Pressure, psia= 132-5,645

Temperature, oF= 72-292

Dead oil viscosity, cp= 0.377-50

Beggs and Robinson also developed a co-relation for saturated oil viscosity from a measured

data set of 2073 oils, as below.

b

ob oda (9)

where

0.515

10.715 100sa R

0.338

5.44 150sb R

The accuracy of co-relation for the data set from which this co-relation was developed was

reported to be -1.83% and a standard deviation of 27.25%.

The ranges for this co-relation are as follow.

Pressure, psia= 132-5265

Temperature, oF= 70-295

API gravity= 16-58

Now given below are the existing co-relations for the viscosity determination of under-

saturated oils, which are the oil in which gas is present but not as much as can be. Since this

is the viscosity of oils at bubble point, so it is calculated by calculating viscosity of oils at

bubble point and then adjusting it for pressure above bubble point.

Bubble point can be defined as the pressure at which the first bubble of gas comes out of oil.

In 1980 Vasquez andBeggs proposed the following co-relation to calculate the viscosity of

under-saturate d oils.

m

o ob

b

p

p

(10)

Page | 30

Where,

1.1872.6 10am p

53.9 10 5a p

The data used to develop this co-relation falls under following ranges

Pressure psia = 141-9,151

Viscosity, cp = 0.117-148

API gravity = 15.3-59.5

The average error for this co-relation is reported to be -7.54%.

Now as we can see that to find the viscosity of under-saturated oils, we need to find the

viscosity at bubble point (viscosity of saturated oils), and to find the viscosity of saturated

oils, we need to find the viscosity of dead oils, so for that purpose, above mentioned co-

relations will be used.

5.4 Methods for thermal recovery

Basically these methods can be categorized into two groups.

In-situ combustion

Hot fluid injection

In second method, combustion is carried out at surface and then hot fluid is supplied to

reservoir while in first combustion is carried out in formation. In second case the fluid

carries heat while in first one applied fluid is one of the components (reactant) of exothermic

reaction taking place to provide heat. Now it can be concluded easily that heat losses are

much more in second case than in first case. This is because fluid loses heat during its travel

to the place from where oil is to be displaced, while in first case heat is provided where it is

needed. So the success of second method largely depends on the thermal efficiency of the

method. Thermal efficiency can be improved by various methods in which heat is recovered

after oil is displaced from reservoir.

Page | 31

In-Situ Combustion

As stated above that in In-Situ combustion, combustion is carried out in formation. In this

method a combustion zone is formed in the injection well and oil is recovered through

production well and both these are vertical wells. Oxygen containing air is injected through

injection well and a portion of hydrocarbons present in the reservoir is used as the fuel. Now

as this combustion front propagates downward, it gives its heat to heavy oil which causes a

reduction in its viscosity. This process is also called fire flooding to describe the movement

of a burning front inside the reservoir. Based on the respective directions of front propagation

and air flow, the process can be either of the following:

Forward (when the combustion front advances in the same direction as the air flow)

Reverse (when the front moves against the air flow)

Reverse combustion

This process has been studied extensively in laboratories and tried in the field. The idea is

that it could be a useful way to produce very heavy oils with high viscosity. In brief, it has

not been successful economically for two major reasons.

Combustion started at the producer results in hot produced fluids that often contain

unreacted oxygen. These conditions require special, high-cost tubular to protect

against high temperatures and corrosion. More oxygen is required to propagate the

front compared to forward combustion, thus increasing the major cost of operating an

in-situ combustion project.

Unreacted, coke-like heavy ends will remain in the burned portion of the reservoir. At

some time in the process, the coke will start to burn, and the process will revert to

forward combustion with considerable heat generation but little oil production. This

has occurred even in carefully controlled laboratory experiments.

Forward combustion

Because only forward combustion is practiced in the field, we will only consider this case.

Forward combustion can be further characterized as either of the following:

“dry,” when only air or enriched air is injected

“wet,” when air and water are co-injected

Page | 32

Dry Combustion

The first step in dry forward in-situ combustion is to ignite the oil. In some cases, auto

ignition occurs when air injection begins if the reservoir temperature is fairly high and the oil

is reasonably reactive. This often occurs in California reservoirs. Ignition has been induced

with:

Downhole gas burners

Electrical Heaters

Injection of pyrophoric agents or steam injection

After ignition, the combustion front is propagated by a continuous flow of air. Rather than an

underground fire, the front is propagated as a glow similar to the hot zone of a burning

cigarette or hot coals in a barbecue. As the front progresses into the reservoir, several zones

exist between injector and producer as a result of:

Heat

Mass transport

Chemical reaction

Wet combustion

A large amount of heat is stored in the burned zone during dry forward in-situ combustion,

because the low heat capacity of air cannot transfer that heat efficiently. Water injected with

the air can capture and advance more heat stored in the burned zone.

During the wet combustion process, injected water:

Absorbs the heat from the burned zone

Vaporizes

Moves through the burning front

Expands the steam plateau

Depending on the water/air ratio, wet combustion is classified as

Incomplete when the water is converted into superheated steam and recovers only part

of the heat from the burned zone

Normal when all the heat from the burned zone is recovered and quenched

Super wet when the front temperature declines as a result of the injected water.

Page | 33

When operated properly, water-assisted combustion reduces the amount of fuel needed,

resulting in increased oil recovery and decreased air requirements to heat a given volume of

reservoir. Up to a 25% improvement in process efficiency can be achieved. Determination of

the optimum water/air ratio is difficult because of reservoir heterogeneities and gravity

override that can affect fluid movement and saturation distributions. Injecting too much water

can result in an inefficient fire front, thus losing the benefits of the process.

Some authors recommend, as a best practice, injecting water at high rates to achieve

"partially quenched combustion." This method has limited application. A high-temperature

burn is preferred but is difficult to achieve with oils that are not highly reactive. Injecting

large amounts of water can lower combustion temperatures, resulting in a greater fraction of

oil burned and higher costs for oxygen. At the same time, these types of burns only partially

oxidize the oil. This partial oxidation results in a much more viscous liquid, which in turn

lowers the flow rate. So, in brief, if water injection is used, great care should be taken to

assure that liquid water never reaches the high-temperature combustion front.

Now one main problem with vertical injection and production wells in in-situ combustion is

that at injection well due to burning the viscosity of combustion front (oil present in that

location) is very low, so that oil flows with higher velocities (moves quickly), while on the

other hand in production well heavy oil is present whose viscosity is higher, so it moves

slowly (at lower velocities). Thus, the capacity of the reservoir to flow hydrocarbons is much

less near the production well than near the injection well. This results in a condition which is

sometimes referred to as “fluid blocking”. When this condition occurs, flow of the lower

viscosity hot bank of hydrocarbons near the injection well is retarded by the slower rate of

flow of the higher viscosity hydrocarbons near the production well. Under severe conditions

where highly viscous fluids are present in the reservoir, the hydrocarbons near the production

well may be relatively immobile and thus may, to a large extent, prevent the hot bank of

hydrocarbons from flowing toward and into the production well. This result in a loss of

efficiency and an excessive amount of the hydrocarbons may be burned in the reservoir. In

order to overcome this problem, a horizontal well in made at lower (bottom) of the reservoir

and a vertical well is located at upper side of the reservoir to avoid “fluid blocking”. At least

one horizontal production well is located in a lower portion of the reservoir and at least one

vertical injection well is located in an upper portion of the reservoir. Oxygen-enriched gas is

injected down the injector well into the upper portion of the reservoir. Such gas is ignited in

the upper portion of the reservoir to create a combustion zone that reduces the viscosity of oil

Page | 34

in the reservoir as the combustion zone advances downwardly toward the horizontal

production well, the reduced viscosity oil draining into the horizontal production well under

force of gravity.

Hot fluid injection

Hot fluid injection is basically a technique, in which a fluid carries heat to the oil, gives its

heat to the oil and thus reduces its viscosity. In most thermal recovery projects, saturated

steam is the injectant of choice although air is an interesting alternative.

Steam Injection

In steam injection steam is used as the fluid to carry the heat to the required formation. It is

the most common method used in EOR now a day. According to a 2000 Oil & Gas Journal

survey, steam enhanced oil recovery (EOR) projects accounted for 417,675 barrels of oil per

day (BOPD), or 56% of the total for all tertiary enhanced recovery methods. That production

rate has been essentially flat for more than 15 years. Hydrocarbon gas injection and CO2 gas

injection are the only other significant contributors and amount to only 17 and 24%,

respectively. Fuel used to fire the steam generator is of importance in this method. On

energy content per unit of CO2 generated, natural gas is the least carbon intense fuel. Lease

crude oil would have somewhat greater carbon implications. Coal or petroleum coke as a

boiler fuel produces about twice as much CO2 in comparison to natural gas. Hence, current

practice of employing natural gas appears to be the most environmentally friendly from a

fossil fueled steam generator perspective. On the other hand, the petroleum coke produced

from bitumen is low cost and insulates operations from variability in the cost of natural gas.

From a water perspective, thermal recovery varies from water being essential (steam) to not

needed (dry in-situ combustion). The so-called oil–steam ratio (OSR) and its inverse the

steam–oil ratio (SOR) are metrics commonly used to gauge the energy efficiency of steam

EOR. They also give an indication of the water requirements for oil recovery. The OSR is the

volume of oil produced per volume of steam injected. The steam volume, however, is

recorded as condensed water at standard conditions. Accordingly for an OSR equal to 0.2, 5

volumes of water (as steam) are required to produce a barrel of oil. The range of OSR in field

operations generally spans from 0.1 to 0.5 implying that the water needed for steam EOR

ranges from 10 to 2 volumes of water per volume of oil produced, respectively. To date, the

reported OSR for steam-based thermal recovery projects in Alberta, Canada have been

somewhat on the larger and more water efficient side. About 2.5 to 4 barrels of water is used

for every barrel of bitumen produced (Alberta.ca, 2012). Differences in water requirements

are related to the maturity of the project, the geology of the oil-sands deposit, and so on. Oil

sands recovery operations have made active use of water recycling as well as substitution of

non-potable aquifer water to reduce volumes of fresh water needed. With recycle ratios of 70

to 90 %, as little as 0.5 barrels of fresh water is needed to produce a barrel of bitumen

(Alberta.ca, 2012). Given the scope of expansion of oil sands recovery operations, however,

total water withdrawal from the Lower Athabasca River in Alberta has become significant.

The withdrawal was 0.74% of the annual average flow in 2010 (Alberta.ca, 2012). Strict

limits are in place for current and future water withdrawal from the Lower Athabasca River

and a so-called Water Management Framework is in place. In total, all oil sand projects

(including both surface mining and in-situ recovery techniques) are allowed to withdraw no

more than 3% of the average annual flow. Regulations are also in place to manage water

withdrawal on a week-to-week basis. During times of low water flow in the river, the amount

Page | 35

of water that may be removed is reduced significantly. From a fuel perspective, steam

generation using natural gas is generally acknowledged to produce relatively little air

pollution. Further, various standardized technologies are available to reduce emissions of

nitrogen oxides (NOx). If, however, lease crude or petroleum coke is used to fire a steam

generator, flue gases may contain substantial sulfur in the form of SO2, SO3, and

particulates. The sulfur oxides in flue gas are readily removed by passage through a wet

scrubber that absorbs the sulfur oxides and neutralizes the acid by reaction with alkaline

components of the wet scrubbing solution.

Despite its success to date and the significant volumes of heavy-oil and bitumen remaining to

be produced, thermal recovery, and in particular steam injection, is challenged by factors

including access to inexpensive and clean-burning fuel to generate steam ,water for steam

generation, energy intensity that increases life-cycleCO2 emissions, air pollution, and

ultimately public acceptance. These are considerable, but not insurmountable environmental

challenges.

Steam injection can be divided into three major categories.

Steam assisted gravity drainage

Cyclic steam injection

Steam flooding

Steam assisted gravity drainage (SAGD) is an outstanding

example of a steam injection process devised for a specific type of

heavy oil reservoir utilizing horizontal wells .It is widely used in

Alberta, Canada for recovery of heavy oil and tar sand resources.

Several variations of the basic process have been developed, and

are being tested. The original SAGD process utilizes two parallel

horizontal wells in a vertical plane, the injector being the upper

well and the producer the lower well. If the oil/bitumen mobility

is initially very low, steam is circulated in both wells for

conduction heating of the oil around the wells. Steam is then

injected into the upper well, while producing the lower well. As a

result, steam rises forming a steam chamber with oil flowing at the sides of the chamber and

condensate flowing inside the chamber.

Cyclic Steam Injection, also called Huff n‟

Puff, is a thermal recovery method which

involves periodical injection of steam with

purpose of heating the reservoir near

wellbore, in which, one well is used as both

injector and producer, and a cycle consisting

of 3 stages, injection, soaking and

production, repeats to enhance the oil

production rate. Steam is injected into the

well for certain period of time to heat the oil

Figure 11: Steam assisted gravity

Figure 12: cyclic steam injection

Page | 36

in the surrounding reservoir to a temperature at which it flows (200~300°C under 1MPa of

injection pressure). When enough amount of steam has been injected, the well is shut down

and the steam is left to soak for some time no more than few days. This stage is called

soaking stage. The reservoir is heated by steam, consequently oil viscosity decreases. The

well is opened and production stage is triggered by natural flow at first and then by artificial

lift. The reservoir temperature reverts to the level at which oil flow rate reduces. Then,

another cycle is repeated until the production reaches an economically determined level.

Properties of Steam used:

Like other substances, water can exist in the form of a solid (ice), as a liquid (water), or as a

gas (loosely called steam). Steam flooding processes are concerned with the liquid and gas

phases, and the change from one phase to the other. The phase change region, in which water

coexists as liquid and gas, is where our interest lies when considering steam for use in the oil

field. The term "steam" is an imprecise designation because it refers to a water liquid/gas

system that can exist from 32°F to any higher temperature; from 0.1 psia to any higher

pressure; and from nearly all liquid to 100% gas. Steam quality refers to the phase change

region of liquid to gas and is defined as

vs

v l

mf

m m

(11)

Where

fs= steam quality

mv= mass of vapor, lbm [kg]

ml= mass of liquid, lbm [kg]

Now, different parameters of steam can be found using following formulas. 0.2229116.79s sT p ,

oF (12)

Where

Ts= steam temperature, °F

ps= steam pressure, psia [kPa]

4430.02 0.02s s

s

v fp

(13)

Where

Vs= steam zone volume, acre ft [m3]

fs= steam quality

ps= steam pressure, psia [kPa]

0.0003595.06 5s se p ,lbm/ft

3 (14)

Where

ρs= density of dry steam, lbm/ft3 [kg/m3]

Page | 37

0.257491f sh p , BTU/lbm (15)

Where

hf= enthalpy of liquid portion of saturated steam, Btu/lbm [kJ/kg]

0.087741318fv sh p , BTU/lbm (16)

Where

hfv= enthalpy of vapor portion of saturated steam, Btu/lbm [kJ/kg]

0.012671119v sh p , BTU/lbm (17)

Where

hv= enthalpy of 100% quality (saturated) saturated steam, Btu/lbm [kJ/kg]

And

0.2574

0.08774

131891

s

s

f s

s

fh p

p , BTU/lbm (18)

Where

hfs= enthalpy of < 100% quality saturated steam, Btu/lbm [kJ/kg]

These equations are for hand calculation. More accurate equations are available which use

software to do calculations. However for most of the cases and in thermal recovery also,

these equations are more than accurate.

5.5 Heat transfer during Steam Injection

Heat transfer during steam injection was first calculated by Marx and Langenheim by

assuming that the equations for temperature response in a thin plate, backed in perfect contact

to a semi-infinite solid after sudden exposure to constant-heat input, were analogous to steam

injection into an oil-bearing reservoir.

According to this model, heated area for a specific amount of steam supplied can be

calculated as below.

24

D

s

i r t G tT

AtQ M h

, ft2

(19)

Page | 38

Where

At = time-dependent heated area, sqft [m2]

Qi = total heat injected, Btu [kJ]

ht= gross reservoir thickness, ft [m]

MR = volumetric heat capacity of the reservoir, Btu/(ft3-°F) [kJ/m3•K]

ΔT = steam temperature/reservoir temperature, Ts/TR , °F

λS= thermal conductivity of surrounding formation, cp [Pa•s]

α = thermal diffusivity of reservoir, ft2/D [m2/d]

And

G(tD) is a function of dimensionless time, tD.

Where

tD is time of injection, t, multiplied by a few reservoir properties

G(tD) can be defined as

2 1Dt DD D

tG t e erfc t

(20)

Where “erfc” is the error function present in heat conduction calculations.

Now tD can be defined as

2

24 s s

D

R

Mt t

M h

(21)

Here

MR = volumetric heat capacity of the reservoir, Btu/(ft3-°F) [kJ/m3•K]

Ms= volumetric heat capacity of steam zone, Btu/(ft3-°F) [kJ/m3•K]

h = enthalpy per unit mass, Btu/lbm [kJ/kg]

αs= thermal diffusivity of surrounding formation, ft2/D [m2/d]

Different tables are available for G(tD) but van Lookeren offers a simple equation with

sufficient accuracy for most calculations, which is written as

1

1 0.85D

D

G tt

(22)

Heat loss during process to the adjacent formations can be given as

2 DD

tG t

l iQ Q

(22)

Here

Ql= heat lost in reservoir, Btu [kJ]

Qi = total heat injected, Btu [kJ]

Page | 39

And

π = constant pi, 3.141

Rate of heated zone growth can be given as follow

2 143,560

DD

i r t

dA ti G tdt T M h

Q

(23)

Here,

MR = volumetric heat capacity of the reservoir, Btu/(ft3-°F) [kJ/m3•K]

ΔTi= change in influx water temperature, °F

ht= gross reservoir thickness, ft [m]

Heat remaining in the reservoir can be calculated as

2 2

24

r t

D

s s

M hi G t

MQ

Q

(24)

And cumulative heat loss to adjacent formation can be given as

i iQ Q t Q (25)

And reservoir efficiency or fraction of injected heat remaining in the reservoir can be written

as

D

h

Di

G tQE

tQ t

(26)

MR is used above, needs definition. It can be defined as volumetric heat capacity of the

composite formation including rock and fluids. Its mathematical form is as follow

1 1 sR o o W W g s g s s WM M S M S M S f M f C

T

(27)

Here,

Ф = porosity

Mσ= volumetric heat capacity of reservoir rocks, Btu/(ft3-°F) [kJ/m3•K]

Mo = volumetric heat capacity of oil, Btu/(ft3-°F) [kJ/m3•K]

Mw = volumetric heat capacity of water, Btu/(ft3-°F) [kJ/m3•K]

Mg = volumetric heat capacity of gas, Btu/(ft3-°F) [kJ/m3•K]

So = oil saturation

Sw= water saturation fraction

Sg= gas saturation fraction

fs= steam quality

Cw= isobaric specific heat of water, Btu/(lbm-°F) [kJ/kg•K]

ρs= density of dry steam, lbm/ft3 [kg/m3]

And

Page | 40

ΔT = steam temperature/reservoir temperature, Ts/TR , °F

And thermal diffusivity α, is the ratio of the thermal conductivity to the volumetric heat

capacity and is given as

C

(28)

5.6 Steam Generators

Steam generators used in enhanced oil recovery steam injection process for generation of

steam are once through steam generators (OTSG). It uses the concept of combines gas and

steam turbines. These are very similar to Heat Recovery Steam Generators (HRSGs) except

for the actual process of steam generation in their evaporator section(s). It utilizes two single

pass evaporator stages to evaporate and partially superheat the steam flow in the once through

evaporator section. The primary stage evaporates the water to an intermediate steam quality

and the secondary stage completes the evaporation and superheats the steam to a minimum

level. In a typical system the HP EVAP is an OTSG while the IP and LP systems may be

OTSGs or natural circulation with a steam drum. Outside of the actual evaporator design, the

SHTRs, RHTRs, and ECONs of the HRSG and the OTSG are identical (though the actual

heating surfaces may vary somewhat). Unlike a drum boiler where natural circulation is used,

water is forced through the tubes by a boiler feed-water pump, entering the OTSG at the cold

end and maintaining constant flow through the tube bundle .The OTSG has no steam drum

since the water flow is 100% evaporated within the two evaporator passes. This requires

somewhat better Feedwater quality than the corresponding HRSG design including the use of

condensate polishing. The water treatment regime within the systems may be very different

since the OTSG must utilize all volatile treatment while the HRSG does not. In OTSG Gas

(From Gas Turbine) flow is in the opposite direction to that of the water flow (counter current

flow).

Since the thick HP steam drum has been eliminated in the OTSG design there are startup

speed advantages. The startup of a HRSG is limited by the maximum allowable startup

saturation temperature rise in the thick HP steam drum (typically in the 2-10°F/minute range).

In the absence of the thick HP drum the OTSG can achieve higher startup ramp rates in the

HP saturation temperature. This has the advantage of decreasing the overall elapsed OTSG

startup time versus the corresponding HRSG for COLD startup times. Warm and hot startup

times tend to be very similar for the OTSG and the HRSG.

An OTSG consists of:

An enclosed structure with an inlet at the bottom end that accepts heated air (usually

exhausted at high velocity from a gas turbine) and an outlet at the top of the structure

that allows the air to escape;

Inside this enclosed structure is an uninterrupted bank of high quality steel tubes.

Feedwater is fed into the top of the tube bank and is heated by the turbine‟s exhaust

gas to create steam at the outlet end of the tube bank.

Figure 13: steam Generator schematic

Page | 41

The region of the tube bundle where water is converted into steam, known as the steam-water

interface, is free to move through the tube bundle. Depending on the available heat from the

gas turbine, the feed-water pressure and the mass flow rate of feed-water, the steam-water

interface will move forward or back in the bundle. In a 50 row bundle, this point can migrate

up or down 4 rows.

The single point of control for the OTSG is the feed-water control valve; actuation depends

on predefined operating conditions that are set through the distributed control system (DCS).

The

DCS is connected to a feed forward and feedback control loop, which monitor the heat input

from the gas turbine, load changes and outlet steam conditions, respectively. If a load

transient from the gas turbine is monitored, the feed forward control system will adjust the

feed-water flow to a new predicted value based on the turbine exhaust temperature, thus

producing steady state superheated steam conditions. The GTI-OTSG can be controlled using

one of the following control schemes:

1) Steam temperature control, 2) steam pressure control 3) GT demand control

When configured for GTI/OTSG operation we typically arrange the system with horizontal

gas flow and vertical heat extraction tubes as can be seen in Figure below. The vertical tube

configuration results in a smaller footprint, pushing the units vertically rather than

horizontally and allowing for installation in an existing gas path.

This type of steam generators have many unique features such as.

Faster installation – OTSG units are manufactured in modules so they install quickly

(typically 48 weeks versus 60 weeks for conventional drum type generators)

Figure 14: Control Scheme

Figure 15: Installation rate of OTSG

Page | 42

Run-dry capability – no need to shut down gas turbines- because of the alloy steel

used in IST‟s OTSG tube bundles, they can continue to operate when steam is not

required

Drum less steam generation – there are no blow-down systems, steam drum level

worries or boil out and chemical cleaning requirements with OTSGs. OTSGs have

significantly fewer components and approximately 50 less I/O points- for reduced

maintenance costs.

Flexible operation – run dry capability and the drum less simplicity of OTSG

installations means lower maintenance and greater flexibility- including easy and fast

cycling from 0% to 100% steam capacity.

Operation of OTSG:

The GTI-OTSG heat recovery system can be started simultaneously with the start of the gas

turbine or after the gas turbine is on line and fully loaded. When the stack temperature of the

OTSG reaches greater than 300 F, feed-water is admitted into the OTSG. For the first six

minutes, feed-water is introduced slowly and in a controlled manner, so as to stabilize the

flow in the feed-water header and avoid tube quenching. From seven minutes to

approximately fifteen minutes, the rate of feed-water introduction is increased reaching 20%

of the design flow. At this point the OTSG will produce superheated steam at the same

temperature as the gas turbine inlet temperature (an attemperator is used to control steam

temperature to the desired temperature level). Standard practice is to hold the steam output

constant at approximately 20% of the maximum flow level for several minutes. This is done

to warm up the GT steam supply piping with the required length of time determined by the

design of the supply piping and usually approximately ten minutes. Once the balance of plant

piping is warm, the OTSG continues to ramp-up both steam pressure and feed-water flow

rate. After approximately thirty minutes of ramp time, the feed-water flow rate has reached

85% to 90% of the design flow rate. At this point the feed-water flow rate is brought into

closed loop control based on the superheater steam temperature feedback signal. After a

further five minutes, the temperature of the steam produced by the OTSG is in full

temperature control. Full steam production is available after thirty-five minutes time.

Figure 16: Comparison of normal steam generator and OTSG

Page | 43

Dry – Run Operation

The GTI/OTSG unique ability to run dry provides the owner/developer with reduced

operational risk and lower investment cost. Two stacks, extra bypass ducting and dampers are

not required for the GTI/OTSG unit to run in by-pass mode. Consequently, the GTI can be

cycled up and down very quickly as demand requires. When steam is not required for

injection as during nonpeak hours, the feed-water flow is simply turned off, and the OTSG is

allowed to boil dry.

Approximately, fifteen minutes later the OTSG boiler is dry and safe for dry-run operation

without a fear of damage.

Limitations Limitations present in OTSG are that these are available only in limited sizes. An OTSG only

can handle up to 300,000 lb/hr of steam.

Page | 44

0

100

200

300

550 600 650 700

μo

d

Temperature

Beal's co-relation

Beal's co-relation

Expon. (Beal's co-relation)

Chapter # 06

Results and calculations

Viscosity calculations:

In these calculations we calculated the viscosity of following heavy oils

Dead oils

Saturated oils

Unsaturated oils

6.1 Dead oils:

For deal oil viscosity calculation we use the following co-relations:

Beal‟s co-relation

Beg and Robbinson‟s co-relation

Galsso co-relation

Kuwaiti oils co-relation

Beal’s co-relation:

Beals'corelation

T API a μod

560 17 8.3176 220.2

580 17 8.3176 128.73

585 17 8.3176 113.16

590 17 8.3176 99.663

595 17 8.3176 87.946

610 17 8.3176 61.092

630 17 8.3176 38.481

640 17 8.3176 30.826

660 17 8.3176 20.12

Table 2: Beal's co-relation

Graph 6: μod vs Temperature

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Beg and Robbinson co-relation

Table 3: Begg's and Robbinson co-relation

Graph 7: μod vs. Temp.

0

50

100

150

200

250

540 560 580 600 620 640 660 680

μo

d

Temperature

Beggs-Robbinson co-relation

Beggs-Robbinson co-relation

Expon. (Beggs-Robbinson co-relation)

Begg's Robbinson co-relation

T API Z Y X μod

560 17 2.68849 488.0789 2.30404 200.3909

580 17 2.68849 488.0789 1.863812 72.08234

585 17 2.68849 488.0789 1.777394 58.89544

590 17 2.68849 488.0789 1.698142 48.90471

595 17 2.68849 488.0789 1.625219 41.1909

610 17 2.68849 488.0789 1.437791 26.40257

630 17 2.68849 488.0789 1.243019 16.49925

640 17 2.68849 488.0789 1.163076 13.55714

660 17 2.68849 488.0789 1.028945 9.689192

Page | 46

0

20

40

60

80

100

120

140

160

180

550 600 650 700

μo

d

Temperature

Glasso co-relation

Glasso co-relation

Expon. (Glasso co-relation)

Glasso’s co-relation:

Glasso co-relation

Temperature API a μod

560 17 -15.821 152.81707

580 17 -15.0044038 96.608926

585 17 -14.821567 87.181897

590 17 -14.6459022 78.992253

595 17 -14.4768678 71.838912

610 17 -14.0049708 55.115238

630 17 -13.4443803 40.230247

640 17 -13.1883747 34.843122

660 17 -12.7164777 26.731849

Table 4: Glasso'co-relation

Graph 8: μod vs. Temperature

Page | 47

0

50

100

150

200

250

300

0 50 100 150 200 250

μo

d

Temperature

Kuwaiti oil fields

Kuwaiti oil fields

Expon. (Kuwaiti oil fields)

Kuwaiti oils co-relation

Kuwaiti oils co-relation

T(F) API μod

100 17 254.4417

120 17 152.8958

125 17 136.4175

130 17 122.2609

135 17 110.0274

150 17 81.97424

170 17 57.78688

180 17 49.25889

200 17 36.69958

Table 5: Kuwaiti oils co-relation

Graph 9 : μod vs Temperature

Page | 48

0

1

2

3

4

5

6

050100150200250

μo

b

μod(Beal's)

saturated heavy oils( Chew and Connally )

saturated heavy oils( Chewand Connally )

Linear (saturated heavy oils(Chew and Connally ))

6.2 Saturated oils

For Saturated oils we use following co-relations

Chew and Conally co-relation

Beg and Robbinson‟s co-relation

Chew and Conally co-relation

saturated heavy oils( Chew and Connally )

Rs μod(beals) E D c b a μob

2800 220.2038212 0.10472 3.08 0.24136 0.439 -0.3472 4.800642

2800 128.7336499 0.10472 3.08 0.24136 0.439 -0.3472 3.792749

2800 113.1582559 0.10472 3.08 0.24136 0.439 -0.3472 3.583996

2800 99.66335249 0.10472 3.08 0.24136 0.439 -0.3472 3.389662

2800 87.94559773 0.10472 3.08 0.24136 0.439 -0.3472 3.208554

2800 61.09219213 0.10472 3.08 0.24136 0.439 -0.3472 2.734306

2800 38.48136815 0.10472 3.08 0.24136 0.439 -0.3472 2.232155

2800 30.82596525 0.10472 3.08 0.24136 0.439 -0.3472 2.025041

2800 20.12008003 0.10472 3.08 0.24136 0.439 -0.3472 1.679164

Table 6: Chew And Conally co-relation for Saturated oils

Graph 10 :μob vs μod(Beal's)

Page | 49

0

1

2

3

4

5

6

050100150200250

μo

b

μod(Begg's)

Saturated heavy oils(Chew and Connally )

Saturated heavy oils(Chewand Connally )

Linear (Saturated heavyoils(Chew and Connally ))

Table 7: Chew and Conally co-relation for Saturated oils

Saturated heavy oils(Chew and Connally)

Rs uod(Begg's) e D c b a uob

2800 200.3909372 0.10472

3.08 0.24136

0.439 -0.3472 4.605998

2800 72.08234268 0.10472

3.08 0.24136

0.439 -0.3472 2.940264

2800 58.89544216 0.10472

3.08 0.24136

0.439 -0.3472 2.6907

2800 48.90470838 0.10472

3.08 0.24136

0.439 -0.3472 2.479844

2800 41.19089729 0.10472

3.08 0.24136

0.439 -0.3472 2.299838

2800 26.40257326 0.10472

3.08 0.24136

0.439 -0.3472 1.891918

2800 16.49924829 0.10472

3.08 0.24136

0.439 -0.3472 1.539098

2800 13.55713645 0.10472

3.08 0.24136

0.439 -0.3472 1.411957

2800 9.689192316 0.10472

3.08 0.24136

0.439 -0.3472 1.218372

Graph 11: μob vs μod(Begg's)

Page | 50

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

050100150200

μo

b

μod(Glasso)

satureated heavy oils(Chew and Connally )

satureated heavy oils(Chewand Connally )

Linear (satureated heavyoils(Chew and Connally ))

Table 8:Chew and Conally co-relation for Saturated oils

satureated heavy oils(Chew and Connally)

Rs μod(glasso) e d c B a μob

2800 152.8170742 0.10472 3.08 0.24136 0.439 -0.3472 4.089316

2800 96.60892589 0.10472 3.08 0.24136 0.439 -0.3472 3.343658

2800 87.18189735 0.10472 3.08 0.24136 0.439 -0.3472 3.196292

2800 78.99225301 0.10472 3.08 0.24136 0.439 -0.3472 3.060828

2800 71.83891245 0.10472 3.08 0.24136 0.439 -0.3472 2.9359

2800 55.11523829 0.10472 3.08 0.24136 0.439 -0.3472 2.613471

2800 40.23024707 0.10472 3.08 0.24136 0.439 -0.3472 2.276135

2800 34.84312207 0.10472 3.08 0.24136 0.439 -0.3472 2.136923

2800 26.73184922 0.10472 3.08 0.24136 0.439 -0.3472 1.90224

Graph 12:μob vs μod(Glasso's)

Page | 51

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

050100150200250

μo

b

μod(Beal's)

saturated oils (Beggs and Robinson )

saturated oils (Beggs andRobinson )

Linear (saturated oils (Beggsand Robinson ))

Begg and Robinson co-relation

saturated oils (Beggs and Robinson )

RS μod(beals) A b μob

2800 220.2038212 0.176546 0.365426 1.26761

2800 128.7336499 0.176546 0.365426 1.04182

2800 113.1582559 0.176546 0.365426 0.993864

2800 99.66335249 0.176546 0.365426 0.948797

2800 87.94559773 0.176546 0.365426 0.906406

2800 61.09219213 0.176546 0.365426 0.793418

2800 38.48136815 0.176546 0.365426 0.670114

2800 30.82596525 0.176546 0.365426 0.617939

2800 20.12008003 0.176546 0.365426 0.528734

Table 9: Beggs and Robbinson co-relation for saturated oils

Graph 13:μob vs μod(Beal's)

Page | 52

0

0.2

0.4

0.6

0.8

1

1.2

1.4

050100150200250

μo

d

μod(Begg's)

saturated oils (Beggs and Robinson )

saturated oils (Beggs andRobinson )

Linear (saturated oils (Beggsand Robinson ))

saturated oils (Beggs and Robinson )

Rs μod(beggs) A b μob

2800 200.3909372 0.176546 0.365426 1.22468

2800 72.08234268 0.176546 0.365426 0.84286

2800 58.89544216 0.176546 0.365426 0.782872

2800 48.90470838 0.176546 0.365426 0.731458

2800 41.19089729 0.176546 0.365426 0.686985

2800 26.40257326 0.176546 0.365426 0.583933

2800 16.49924829 0.176546 0.365426 0.491756

2800 13.55713645 0.176546 0.365426 0.4577

2800 9.689192316 0.176546 0.365426 0.404829

Table 10: Beggs and Robbinson co-relation for saturated oils

Graph 14: μob vs μod(Begg's)

Page | 53

0

0.2

0.4

0.6

0.8

1

1.2

1.4

050100150200

μo

b

μod(Glasso)

saturated oils (Beggs and Robinson )

saturated oils (Beggs andRobinson )

Linear (saturated oils (Beggsand Robinson ))

saturated oils (Beggs and Robinson )

Rs μod(glasso) A b μob

2800 152.8170742 0.176546 0.365426 1.1092

2800 96.60892589 0.176546 0.365426 0.938066

2800 87.18189735 0.176546 0.365426 0.903522

2800 78.99225301 0.176546 0.365426 0.871532

2800 71.83891245 0.176546 0.365426 0.841819

2800 55.11523829 0.176546 0.365426 0.764122

2800 40.23024707 0.176546 0.365426 0.681086

2800 34.84312207 0.176546 0.365426 0.646229

2800 26.73184922 0.176546 0.365426 0.586584

Table 11: Beggs and Robbinson co-relation for saturated oils

Graph 15: μob vs μod(Glasso's)

Page | 54

Chapter # 07

Pump calculations

7.1 Problem Statement:

Consider a duplex positive displacement pump with maximum flow rate of 95 GPM,

maximum suction pressure of 82.65 PSI and maximum discharge pressure of 249.4 PSI.

Calculate the brake horse power (BHP) for following cases if mechanical efficiency is taken

to be 60%.

a) If it is used to pump water (ρ=1000 kg/m3)

b) It is used to pump dead oil having API 17o and dynamic viscosity of 220.2 cp at 560

oF.

c) If the temperature of dead oil is increased from 560 oF to 660

oF. Its dynamic viscosity

decreases to 20.12 cp.

d) Also find percentage decrease in BHP after applying heating to reduce viscosity.

Solution:

7.2 Assumptions taken:Following assumptions are taken while solving this problem.

a) Pump suction and discharge pressure and flow rate remains same for all cases.

b) The density of dead oil also remains invariant.

Case 1:

Ps= Suction pressure= 82.65 PSI

Pd= Discharge pressure= 249.4 PSI

Q= Flow rate= 95GPM

η=Mechanical efficiency = 60%

As we know that the formula for BHP for positive displacement pumps is

1714

d sP PBHP Q

(29)

By putting above values, we get

BHP= 15.409 hp

Page | 55

Case 2:

Now we consider a dead oil having an API 17o and dynamic viscosity of 220.2cp.

As we know that pumps are designed on the basis of water viscosity. So, if heavy oils having

viscosity more than water are to be pumped, we have to consider viscosity correction factor

for efficiency and flow rate.

Consider that correction factor for viscosity is Cq and Cu for flow rate and efficiency

respectively.

Consider that actual flow rate and efficiency after considering correction factor are Qv and ηv

v qQ C Q (30)

v uc (31)

In order to calculate Cq and Cu we require differential head and density.

For density we use

API= (141.5/R.D) – 131.5

Where R.D = Relative density

As we taken oil of oAPI= 17, so

17= (141.5/R.D) – 131.5

R.D = 0.952

ρoil = 1000* R.D

ρoil = 1000* 0.952

ρoil = 952 kg/m3

For differential head

ΔP = Pd - Ps

ΔP = ρghd - ρghs

17.2 – 5.7 = ρgΔh

So,

Page | 56

Differential head = Δh = 11.5*105/ρg

Δh = 123m

Using these values we get

Cq=0.761

Cu =0.452

So, the new flow rate and efficiency are given as

Qv = 0.761*95

Qv= 72.295 GPM

ηv = 0.6*0.452

ηv= 0.2712

Now, using the same formula for BHP

1714

d s

v

P PBHP Q

BHP = (72.295*(249.4 – 82.65))/1714*ηv

BHP = 25.944 hp

Page | 57

Case 3:

Now using the dead oil with dynamic viscosity of 20.12 cp at 660 oF.

For this data

Cq = 0.97

Cu = 0.89

So,

Qv = Cq * Q

Qv = 0.97 * 95

Qv= 92.15 GPM

ηv = Cu * η

ηv= 0.89 * 0.6

ηv= 0.534

Now to find BHP, we use formula below.

1714

d s

v

P PBHP Q

BHP = (92.15*(249.4 – 82.65))/1714 * ηv

BHP = 16.795 hp

Now, we find percentage reduction in BHP.

%age reduction = (25.999 – 16.795)/16.795

%age reduction = 54.47%

7.3 Results:

These conclusions can be drawn from above calculations

These calculations show that heating is an effective method for viscosity reduction.

A differential of 100 oF can decrease BHP by 54.47%.

Page | 58

Chapter # 08

Conclusions and Recommendations

8.1 Conclusions:

From all the calculation made for viscosity and pumps different conclusions can be made.

From Graph 4, it was found that positive displacement pumps are affected little by

viscous fluid compared to centrifugal pumps. In positive displacement pumps, viscous

fluids enter into clearances, which improve its volumetric efficiency, and hence

improve overall efficiency. So these pumps are recommended for viscous fluid

pumping.

From problem 7.1, it was found that heating viscous fluid by a difference of 100oF,

reduced input horse power above 50% for a duplex positive displacement pumps.

From article 5.2, it is clear that different techniques are available for viscosity

reduction such as CO2 flooding, water flooding, use of surfactants, emulsification and

heating etc. Among all these techniques heating is simpler, but its initial cost is high

because of need of insulation on the side of long injection well, and even on

production well side sometimes heat exchangers are required.

From article 5.3, it is found that different co-relations were used for viscosity

calculation and error from mean value was found because of unavailability of

practical data. A Kuwaiti oil was selected as reference and it was found that among

the available co-relation, beal‟s co-relation gave best results. But this does not imply

that it is best co-relation. Because viscosity of heavy oil and its reduction both depend

upon geographical location as well. So a co-relation which is best for one specific

location may not give same results for another location. And different co-relations

give different co-relations give different results for different geographical locations.

Page | 59

8.2 Recommendations:

For steam generation:

As steam is generally generated using natural gas, but there are some problems associated

with that. For example natural gas may not be available for a specific geographical location.

And piping it to that location will definitely cost high. Also generation of steam costs high if

cost for the whole process is considered and produces CO2 as well which is greenhouse gas

causing global warming. So instead of using natural gas to generate steam, following

techniques can be recommended.

Solar Steam Generation:

The oil and gas industry has been injecting steam into oil reservoirs for decades. Steam

enhanced oil recovery (EOR) is both an accepted and effective methods of increasing

production from heavy oil resources and tight formations. While the simple premise of steam

injection to increase the reservoir temperature and pressure hasn‟t changed significantly over

time, the method and source of generating steam has. With the advent of robust cost-effective

solar steam equipment, steam generation is set for a further revolution, one that removes

industry reliance on volatile fuel costs and replaces it with a free and abundant resource, the

sun‟s thermal energy. The only problem so far was the high cost of solar troughs. But with

the development of solar system now some companies like GlassPoint claim to produce

steam at half a price as compared to the steam produced by natural gas. Also older solar

thermal designs incorporate stainless steel, which is chemically incompatible with boiler-

grade water, and require expensive reboilers and deionizing units. The need for pure,

dematerialized water can quadruple water treatment costs adding up to a dollar per barrel of

water used. But with the modern technologies, now solar eor uses same water as used by gas-

fired steam generation.

Solar EOR has several key advantages:

No fuel costs, and very low operations and maintenance (O&M) costs allowing solar

steam generators to operate long after the economically viable lifespan of an

equivalent gas-fired unit. By steaming for a longer period of time, solar EOR will

increase proven reserves and maximize ultimate recovery from a field.

Simple integration with existing gas fired steam generation systems allow for a hybrid

design that generates steam 24 hours a day, 365 days per year, rain or shine.

Page | 60

Reduces volatility in field operating costs. The cost of steam generated via solar is

completely decoupled from the price of natural gas allowing operators to reduce fuel

gas volatility risk.

Can be installed in oilfields where there is no availability of natural gas providing a

way to create and inject steam for EOR with no capital investment in a gas

infrastructure. This is especially attractive in regions where natural gas is unavailable

or in limited supply, such as parts of the Gulf Cooperation Council (GCC).

No emissions. Going forward the regulatory burden for fuel-fired equipment will

increase with rising costs for emissions of both criteria pollutants and carbon dioxide

(CO2). Solar steam generation produces no nitrogen oxides (NOx), no particulate

emissions, and no CO2, eliminating the financial risk of permits costs, ongoing cycles

of burner upgrades and carbon taxes.

Incentives and subsidies. Many governments now offer subsidies and incentives in the

form of tax credits and accelerated depreciation for renewable energy installations.

Downhole Steam Generation:

Downhole steam generation (DHSG), which combines thermal, and nitrogen or CO, EOR,

offers several benefits to accelerate the production of oil. Moreover, the CO2 that is generated

in-situ can be used elsewhere.

The steam that is generated on the surface loses its quality while reaching down to a deep

reservoir.

A simulation and field economic model for a 2,000-ft-deep reservoir in California showed

that steam quality drops to 50% or below at approximately 700 m (approximately 2,300 ft.)

Therefore, surface steam injection is generally limited to reservoirs no deeper than 800 m

and, more typically, is applied in reservoirs less than 500 m deep.

In order to overcome this problem instead of generating steam on

surface it is generated down near the reservoir using a downhole steam

generator (DHSG). A schematic diagram for DHSG is shown.

The baseline DHSG tool is designed to operate with natural gas and a

combination of several oxidizer/diluent mixed sand stoichiometries.

The tool is connected to the surface by an umbilical, which contains

Figure 17: Working of OTSG

Page | 61

fit-for-purpose conduits carrying fuel, inert gases, oxidizers, and water as well as sensors and

control systems communications. The tool is designed to fit into standard casing and be

positioned just above the formation. The steam generator requires a design that ensures

reliable performance over a minimum 3-year operating period, without intervention and

across a range of operating conditions.

The generator is supported by three major surface infrastructure systems, the water-treatment

plant (high-quality water is needed to make steam, and produced water is recycled and

reused), an air-separation unit to supply the oxidizer, and product-treatment units that clean

produced oil for sale and dry produced gas for reinjection or use as fuel. Excess CO2, (beyond

that required to support DHSG application) may be vented, or sold to nearby fields as a

means to conduct miscible or immiscible EOR projects.

Reduction in viscosity:

A downhole steam generator is installed just above the reservoir sand. It is fed by an

umbilical from the surface that carries natural gas, water, and a mixture of gases, which might

include oxygen, nitrogen, or CO, or some combination of these. Such a configuration could

be implemented with vertical injectors and producer wells or with pairs of steam-assisted

gravity-drainage wells. The injected steam is at least 80% quality at the sandface because no

heat losses occur in the wellbore. The flue gases (which could be nearly 10% CO2, to nearly

100%CO2) move ahead of the steam front, dissolving into the oil and reducing its viscosity

and swelling it. The steam front heats the oil, and the condensed water drives the oil to the

production well. Because this process is operated at a few hundred psig or more, the steam

chest and viscous forces are the primary means of recovery, as opposed to gravity. In this

scenario, an air-separation unit could be used to generate enriched air (having 35%O2) for the

downhole steam generator. An on-site water treatment system fulfills a dual role by providing

clean water for the generator and treating produced water for reuse or disposal to nearby

injection wells. Produced fluids and gases are separated at the well pad, with separate streams

piped to central facilities for oil treatment and gas treatment.

By injecting both steam and CO2, a larger amount of energy is delivered at a relatively lower

temperature because of a phase equilibrium shift by gases (a partial-pressure effect). In

addition, CO2 moves ahead of the steam bank, mobilizing the oil ahead of the steam front,

which further leverages the drive mechanisms of an engineered steam front.

Page | 62

High-Pressure Reservoir Management and its Effect on Thermal EOR

In conventional heavy-oil projects using surface-generated steam, reservoir pressures

typically range from 15 to 50 psig. Heavy-oil production can be improved with gas by

operating at higher pressures (500 to r1200psig), with DHSG, higher pressures are

maintained through the use of backpressure at the producer well, flow rate and composition

of injectants at the injector well, and combustion activity and combustion-byproduct flows

into the reservoir. Operating at higher pressure provides the following benefits:

Delayed steam condensation in the reservoir accelerates oil production.

Higher production rates reduce heat losses to base rock and cap rock.

Higher backpressure allows the use of inflow-control devices in horizontal wells.

Page | 63

Nomenclature

Re= Reynold No

FD= Drag force

ρp =Density of the heavy oils

=Dynamic viscosity

ν= Kinematic viscosity

μod= viscosity of dead oil

μob= viscosity of saturated oi

μo= viscosity of unsaturated oil

fs= steam quality

mv= mass of vapor

ml= mass of liquid

Ts= steam temperature

ps= steam pressure

Vs= steam zone volume

fs= steam quality

ps= steam pressure

ρs= density of dry steam

hf= enthalpy of liquid portion of saturated steam

hfv= enthalpy of vapor portion of saturated steam

hv= enthalpy of 100% quality (saturated) saturated steam

hfs= enthalpy of < 100% quality saturated steam

At = time-dependent heated area

Qi = total heat injected

ht= gross reservoir thickness

Mr = volumetric heat capacity of the reservoir

ΔT = steam temperature/reservoir temperature

λs= thermal conductivity of surrounding formation

α = thermal diffusivity of reservoir,

G(tD)= function of dimensionless time

tD = time of injection, t, multiplied by a few reservoir properties

Ms= volumetric heat capacity of steam zone

h = enthalpy per unit mass

αs= thermal diffusivity of surrounding formation

Ql= heat lost in reservoir

Qi = total heat injected,

ht= gross reservoir thickness

Ф = porosity

Mσ= volumetric heat capacity of reservoir rocks

Mo = volumetric heat capacity of oil

Mw = volumetric heat capacity of water

Mg = volumetric heat capacity of gas

So = oil saturation

Sw= water saturation fraction

Sg= gas saturation fraction

fs= steam quality

Cw= isobaric specific heat of water

ρs= density of dry steam

η=Mechanical efficiency

Page | 64

Ps= Suction pressure

Pd= Discharge pressure

Cq= Viscosity Correction factor for flow rate

Cu= Viscosity correction factor for efficiency

Page | 65

References

1. Heavy oil production enhancement by viscosity reduction by Patrick Shuler, SPE,

chemEOR, Inc.; yongchun Tang, Power Environmental Energy research

institute(PEERI); and Hongxin Tang ChemEOR, Inc.

2. Heavy oil viscosity and density prediction at normal and elevated temperatures by

Osamah Alomair, Mohammad A.J. Ali, Abdullhaq Alkoriem, and Mohamed Hamed

Kuwiat University, Kuwiat institute for scientific research.

3. How heavy gas solvents reduce heavy oil viscosity by Motonao Imai, SPE; Ichiro

Nishioka; Masanori Nakano, SPE; and Fuminori Kaneko, Japex

4. Viscosity predictions of Kuwaiti heavy crudes at elevated temperatures by Osamah

Alomair, Adel Elsharkawy and Hassan alkandri, Petroleum Engineering department,

college of Engineering and petroleum, Kuwait university.

5. Use of a noval surfactant for improving the transportability of heavy oils by Yousaf

Al-Roomi,Reena George, Ahmed Elgibaly

6. Pipe line Transportion of viscous crude as concentrated oil-in-water emulsion by

N.H Abdurahman ,Y.M Rosli, N.H Azhari , B.A Hayder.

7. Extra heavy oils in the world Energy supply by Ladislas Paszkiewiciz.

8. Screeing of Heavy oils Reservoir for Enchanced oil Recovery By thermal Method by

B.Verkoczy N.K.Jha Saskoil

9. Reservoir Engineering by Tarek Ahmed , Gulf professional Publishing

10. Properties of Petroleum Reservoir Fluids by Emil J. Burcik, Professor Emeritus of

Petroleum and Natural Gas Engineering, The Pennsylvania state university.

11. Enhanced oil recovery by Marcel Latel

These papers were taken from

12. www.sciencedirect.com

13. www.onepetro.com

14. http://www.pumpcalcs.com/calculators/view/81/

15. http://www.kudupump.com/en/products-and-services/product-performance

16. http://www.the-engineering-page.com/forms/pump/c_vis.html

17. http://www.engineeringtoolbox.com/centrifugal-pumps-viscosity-d_670.html