• At the end of this course you will be able to: Know the importance of reservoir engineering in the context of petroleum and natural gas extraction activities, Represent reservoir phase behavior through phase diagrams and estimate oil and gas properties, Understand the fundamentals of fluid flow in reservoirs and reservoir drive mechanisms, Apply the fundamentals of oil and gas well performance and understand their role in reservoir engineering analysis, Perform oil displacement computations and understand their application to secondary recovery calculations, PENG 331 RER Overview of Petroleum Engineering
Transcript
• At the end of this course you will be able to:
Know the importance of reservoir engineering in the context of petroleum and natural gas extraction activities,
Represent reservoir phase behavior through phase diagrams and estimate oil and gas properties,
Understand the fundamentals of fluid flow in reservoirs and reservoir drive mechanisms,
Apply the fundamentals of oil and gas well performance and understand their role in reservoir engineering analysis,
Perform oil displacement computations and understand their application to secondary recovery calculations,
PENG 331 REROverview of Petroleum Engineering
• At the end of this course you will be able to:
Estimate oil-in place and gas-in-place using reservoir volumetrics,
Estimate oil-in place and gas-in-place using Material balance,
Applied Reservoir Engineering Overview of Petroleum Engineering
Introduction • Question:• What is the principal goal of ANY science?
• Physics,• Political studies,• Chemistry,• Financial analysis,• etc., etc., etc.
Introduction• ANSWER:• Given current conditions, predict conditions at later time and how
do we get there, i.e. predict MOTION
• Physics (a body is subjected to several forces, how and where will it move?)
• Political studies (given current political and economic conditions, how the society will develop?)
• Chemistry (given components, P, T; what chemical reactions will occur?)
• Financial analysis (given current economic conditions, how the markets will behave?)
What is Engineering?• It is, essentially, applied physics (“useful” science).
• A few branches of engineering:• Mechanical (machines, engines, instruments)• Chemical (materials with predefined characteristics)• Electrical (computers, integrated circuits)• Civil (construction, transportation)• Nuclear (nuclear reactors, power plants)• Petroleum
Examples of application
• Mechanical (aircraft engines, robotics)• Chemical (liquid crystals, fiber optics, pharmaceuticals)• Electrical (processor chips, GPS, space exploration)• Civil (Tokyo’s Sky City, Boston’s Big Dig, Hong Kong
Airport)• Nuclear (MRI, 20% of US electricity)
• What about Petroleum Engineering ?
Petroleum Engineering …
• … can sometimes be compared to space exploration in its technical complexity (deepwater, HPHT wells)
• … has highest degree of uncertainty of all Engineering disciplines
• … uses all other Engineering disciplines
Reservoir Engineering… • Is a branch of Petroleum Engineering, i.e. of an
engineering discipline, therefore, of physics;
• As such, its principal goal is to describe and to predict motion;
• In Reservoir Engineering, we consider underground movement of “fluid” (liquid or gas). We want to predict how and where fluid will flow based on the knowledge of properties of reservoir and fluid.
Analogies• Similarly, in Reservoir Engineering we need to know
• Geometry of the system in which flow takes place;• Rock properties; and • Fluid properties,
• (as the latter two determine the resistance to flow – friction losses);
• We also need to have • Physical models that are able to adequately describe the flow;• Mathematics, both analytical and numerical methods
Fundamentals of Reservoir Fluid Behavior
OBJECTIVESUpon completion of this section, you will be able to:
Understand the importance of fluid phase behavior on reservoir engineering calculations.
Understand pure component phase behavior as a function of pressure, temperature, and type and sketch and carefully label phase diagrams, pressure temperature and pressure volume (with several isotherms above and below the critical temperature), for a pure substance.
Understand the behavior of binary and multicomponent mixtures and sketch and carefully label phase diagrams, pressure temperature and pressure volume (with several isotherms above and below the critical temperature), for a mixture.
Define the terms vapor pressure, critical point (critical temperature, critical pressure, critical volume), bubblepoint, dew point, cricondenbar, cricondentherm, and retrograde condensate.
List the five types of reservoir fluids.
Understanding Phase Behavior Naturally occurring hydrocarbon mixtures found in petroleum reservoirs are
mixtures of organic compounds and few non-hydrocarbons that may exist in
gaseous or liquid states.
State of reservoir fluids (gas, liquid, very rarely solid) is controlled not only
by pressure and temperature, but also by the composition of the in-situ fluid.
The reservoir engineer needs to understand the phase behavior of petroleum
reservoirs in order to understand the depletion performance of each reservoir
and determine the best course for future development and production.
Why study Phase Behavior? As oil and gas are produced from the reservoir, they are subjected to
a series of pressure, temperature, and compositional changes.
Such changes affect the volumetric and transport behavior of these
reservoir fluids and, consequently, the produced oil and gas volumes.
All reservoir performance equations (e.g., Darcy’s law, material
balances) require the knowledge of fluid properties. It is impossible
to correctly evaluate well productivity and reservoir performance if
fluid properties are not known.
Phase Behavior - Pure Substance
LiquidSolid
GasVapor-pressure line
Mel
ting-
poin
t lin
eC
T
TemperatureTc
pc
Pre
ssur
e
Phase Behavior - Pure Substance The figure above shows the typical P-T diagram of a pure component, with all
the relevant transitions (solid liquid, liquid vapor, solid vapor).
“vapor pressure line” is of special interest to us, since it defines the boundary
for liquid-vapor transitions. Liquid and vapors are the two phases that we most
commonly encounter in petroleum operations.
The vapor pressure curve represents the region of co-existence of L+V states in
EQUILIBRIUM for a pure substance.
The vapor pressure provides a measure of the ability of molecules to escape
from the surface of a solid or liquid; i.e., provides a measure of the volatility of
the substance.
LiquidSolid
GasVapor-pressure line
Mel
ting-
poin
t lin
e C
T
TemperatureTc
pc
Pre
ssur
e
Critical Point
Triple Point
Phase Behavior - Pure Substance
There is a minimum and maximum temperatures and pressures below and above which liquid and vapor cannot longer co-exist together in equilibrium. These are known as the triple and critical points.1. The Triple Point represents the lower bound of the L+V co-
existence region and the only condition at which all three phases of a pure substance (S+L+V) can co-exist in equilibrium.
2. The Critical Point is the condition where vapor and liquid are in equilibrium without any interface to differentiate them (i.e., liquid and vapor are no longer distinguishable in terms of their properties
Phase Behavior - Pure Substance
This figure gives us an idea of the relative location of the vapor pressure curve for
hydrocarbons
Phase Behavior - Pure Substance
400
500
600
700
800
900
1000
1100
1200
0 0.05 0.1 0.15 0.2 0.25
Pre
ssur
e, p
sia
Specific volume, cu ft/lb
Two-phase region 60°F
70°F
80°F
85°F90°F=Tc
95°F
100°F
110°F
130°F
160°F
C
Phase Behavior - Pure Substance
Dewpoint
300 oF
350 oF
400 oF
425 oF
450 oF454 oF
Critical pointB
ubbl
epoi
nt
400
300
200
0.1 0.2 0.3 0.4
Pre
ssur
e, p
sia
Volume, cu ft/lb
Phase Behavior - Mixtures
Phase Behavior - Mixtures
Hydrocarbon systems are never single-component.
They are found naturally occurring with a variety of components
and therefore they are multi-component mixtures.
Hydrocarbon systems are never single-component. They are
found naturally occurring with a variety of components and
therefore they are multi-component mixtures.
The figure above shows a typical p-v diagram for a mixture.
Petroleum reservoirs are broadly classified as oil or gas
reservoirs.
These classifications are further subdivided depending
on:
The composition of the reservoir hydrocarbon mixture
Initial reservoir pressure and temperature
Pressure and temperature of the surface production
Phase Behavior - Mixtures
Phase Behavior - Mixtures
Typical P – T for a multi component system
Pressure-Temperature Diagram Previous figure Shows a typical pressure-temperature diagram of a
multicomponent system with a specific overall composition.
These multicomponent pressure-temperature diagrams are essentially
used to:
Classify reservoirs
Classify the naturally occurring hydrocarbon systems
Describe the phase behavior of the reservoir fluid
Phase Behavior - Mixtures
To understand the significance of the pressure-temperature
diagrams, it is necessary to identify and define the following key
points on these diagrams:
1. Bubble-point curve: The bubble-point curve (line BC) is
defined as the line separating the liquid-phase region from the
two-phase region.
2. Dew-point curve: The dew-point curve (line AC) is defined as
the line separating the vapor-phase region from the two-phase
region.
Phase Behavior - Mixtures
3. Quality lines: The dashed lines within the phase diagram are called quality
lines. They describe the pressure and temperature conditions for equal
volumes of liquids. Note that the quality lines converge at the critical point
(point C).
4. Critical point: The critical point for a multicomponent mixture is referred to
as the state of pressure and temperature at which all intensive properties of
the gas and liquid phases are equal (point C). At the critical point, the
corresponding pressure and temperature are called the critical pressure pc and
critical temperature Tc of the mixture.
Phase Behavior - Mixtures
5. Cricondentherm (Tct): The Cricondentherm is defined as the
maximum temperature above which liquid cannot be formed
regardless of pressure (point E). The corresponding pressure is
termed the Cricondentherm pressure pct.
6. Cricondenbar (pcb): The Cricondenbar is the maximum
pressure above which no gas can be formed regardless of
temperature (point D). The corresponding temperature is called
the Cricondenbar temperature Tcb.
Phase Behavior - Mixtures
7. Phase envelope (two-phase region): The region enclosed by the
bubble-point curve and the dew-point curve (line BCA), wherein
gas and liquid coexist in equilibrium, is identified as the phase
envelope of the hydrocarbon system.
Phase Behavior - Mixtures
Reservoirs are conveniently classified on the basis of the location
of the point representing the initial reservoir pressure Pi and
temperature T with respect to the pressure-temperature diagram
of the reservoir fluid.
Phase Diagram of a Reservoir Fluid
Temperature, °F-200 -150 -100 -50 0 50
14001300120011001000
900800700600500400300200100
0
Pre
ssur
e, p
sia
Criticalpoint10
0% L
iquid
1
102
520
50
A Typical Reservoir Fluid Phase Envelope
A typical reservoir fluid phase envelope has a very distinctly defined dew
point and bubble point lines, both of which meeting at the critical point.
For mixtures, critical pressure and temperatures are no longer the
maximum possible pressure and temperature found within liquid and
vapor co-existence region.
These points are known as the cricondenbar and cricondentherm,
respectively.
The size of the L+V region is a function of mixture complexity and
composition.
The Five Reservoir Fluids
Black Oil
Criticalpoint
Pre
ssur
e, p
sia
Bubblepoint line
Separator
Pressure pathin reservoir Dewpoint line
9080
907060
5040
10
30
20
% Liquid
Temperature, °F
Pre
ssur
e
Temperature
Separator
% Liquid
Bubble
point
line
Dewpoint line
Dewpoint line
Volatile oil
Pressure pathin reservoir
3
2
1
5
10
30
20
40
5060
708090
Criticalpoint
3
3020
15
10
40
Separator
% Liquid
Pressure pathin reservoir
1
2Retrograde gas
Criticalpoint
Bubb
lepoin
t line
Dewpo
int lin
e
50
Pre
ssur
e
Temperature
Pre
ssur
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Wet gas
Criticalpoint
Bubb
lepo
int
line
Separator
152530
Dew
poin
t lin
e
Pre
ssur
eTemperature
% Liquid
2
1
Pressure pathin reservoir
Dry gas
Separator
Dew
poin
t lin
e1
50Retrograde Gas Wet Gas Dry Gas
Black Oil Volatile Oil
25
The Five Reservoir Fluids
The Five Reservoir Fluids One of the most meaningful classification of reservoir fluids is based on
the location of the initial reservoir temperature (Tr) with respect to the
pressure-temperature phase diagram (phase envelope) of the reservoir
fluid.
It is important to compare the location of Tr with respect to the location
of the fluid’s critical point. On the basis of this, a reservoir is classified
as an oil reservoir is the reservoir temperature is less than the critical
temperature Tc and as a gas reservoir if the reservoir temperature is
greater than the critical temperature of the hydrocarbon fluid.
Oil reservoirs: If the reservoir temperature T is less than the
critical temperature Tc of the reservoir fluid, the reservoir is
classified as an oil reservoir.
Depending upon initial reservoir pressure pi, oil reservoirs can be
subclassified into the following categories:
1. Undersaturated oil reservoir
2. Saturated oil
The Five Reservoir Fluids
1. Undersaturated oil reservoir: If the initial reservoir pressure pi is greater than the bubble-point
pressure pb of the reservoir fluid, the reservoir is labeled an
undersaturated oil reservoir.
2. Saturated oil:
When the initial reservoir pressure is equal or below to the bubble-
point pressure of the reservoir fluid the reservoir is called a saturated
oil reservoir.
The Five Reservoir Fluids
Oil reservoirs can be further classified as:
1. Black Oil Reservoirs
2. Volatile Oil Reservoirs (also referred to as near-critical crude
oil)
The Five Reservoir Fluids
Phase Diagram of a Typical Black Oil
Black Oil
Criticalpoint
Pre
ssur
e, p
sia
Bubble-point Line
Separator
Pressure pathin reservoir
Dewpoint line
9080
7060 50
40
10
30
20
% Liquid
Temperature, °F
Phase Diagram of a Typical Black Oil
Black oils are the most common type of oil reserves and are typically composed of a large quantity of heavy hydrocarbons (C7+ fraction). Phase envelopes are wide, covering a wide temperature range in the P-T plane. In these reservoirs, the critical point is found far to the right of the prevailing reservoir temperature.
Oil reservoirs are also classified as undersaturated if the initial reservoir pressure (pi) is greater than the bubble point pressure (pb) of the reservoir fluid. Saturated oil reservoirs are those whose initial reservoir pressure (pi) is equal to the fluid’s bubble point. In gas-cap reservoirs, reservoir pressure is well below fluid’s bubble point pressure. In such situation, the oil leg is said to be saturated with gas.
Phase Diagram of a Typical Volatile Oil
Pre
ssur
e
Temperature, °F
Separator
% Liquid
Bubble
point
line
Dewpoint line
Dewpoint line
Volatile oil
Pressure pathin reservoir
3
2
1
5
10
30
20
40
50
60
708090
Criticalpoint
Phase Diagram of a Typical Volatile Oil
Volatile Oils contain fewer heavy hydrocarbons components and more intermediate components (C2 through C7) and the temperature coverage of their phase envelope is smaller than black oil’s.
These types of oil are known as near-critical because their critical point lies in close proximity to reservoir temperature and typically have high bubble point pressures.
This type of oil is volatile due to this proximity to critical conditions, i.e., the reservoir depletion path (line 1-2-3) is able to cross a great number of isovolumetric lines upon a small reduction of reservoir pressure.
This type of oils may vaporize up to 50 % of the in-site fluid at reservoir conditions at only few hundred psi below bubble point conditions, and are thus categorized as high-shrinkage oils.
Gas reservoirs: If the reservoir temperature is greater than the
critical temperature of the hydrocarbon fluid, the reservoir is
considered a gas reservoir
Gas reservoirs can be further classified as:
1. Retrograde Gas Reservoirs (also referred to as near-critical
gas)
2. Wet Gas Reservoirs
3. Dry Gas Reservoir
The Five Reservoir Fluids
Phase Diagram of a Typical Retrograde Gas
3
30
20
15
10
40
Separator
% Liquid
Pressure pathin reservoir
1
2Retrograde gas
Critical point
Bubble
point
line
Dewpo
int lin
e
50
Pre
ssur
e
Temperature
Retrograde gases or gas condensates are gas reservoirs because reservoir temperature is higher than fluid’s critical temperature. They are also known as near-critical gas reservoirs because of the close proximity of the critical point to reservoir temperature. This type of gas reservoirs are able to form retrograde condensate upon pressure depletion, and hence their name.
Retrograde condensation is an important feature that dominates the production characteristics of these reservoirs. Typical production schemes include pressure maintenance and/or gas cycling operations that can reduce or eliminate the occurrence of the retrograde condensation phenomenon.
Phase Diagram of a Typical Retrograde Gas
Pre
ssur
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Wet gas
Criticalpoint
Bubb
lepo
int
line
Separator
152530
Dew
poin
t lin
e
Phase Diagram of a Typical Wet Gas
Wet gases are primarily composed of light molecular weight hydrocarbons and
exhibit very narrow phase envelopes.
Phase envelopes of wet gases are entirely located at temperatures below reservoir
temperature.
It is clear from the figure above that reservoir temperature > cricondentherm
temperature.
The reservoir pressure path is free of liquids (no retrograde condensation) but
surface separator conditions lie within the phase envelope, causing some liquid
dropout at the surface facilities.
Phase Diagram of a Typical Wet Gas
Pre
ssur
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Dry gas
Separator
Dew
poin
t lin
e
1
50 25
Phase Diagram of a Typical Dry Gas
Dry gases are primarily composed of methane and does
not produce hydrocarbon liquids even at surface
conditions.
Dry gas envelopes are smaller than those of wet gases
and the reservoir gas remains single phase in the
reservoir and on the surface.
Phase Diagram of a Typical Dry Gas
1. The gas that comes out of the solution from black oils usually a
dry gas because the large and heavy molecules in the oil attract the
intermediate sized molecules to stay in the oil phase. However, the
gas that comes out of solution from volatile oil is typically a
retrograde gas.
Volatile oils don’t contain the large molecules that enable black
oils to hold most of the intermediate components in the oil phase.
Differences Between Black-Oils and Volatile Oils
1. Dry gas – gas at surface is same as gas in reservoir.
2. Wet gas – recombined surface gas and condensate represents
gas in reservoir.
3. Retrograde gas – recombined surface gas and condensate
represents the gas in the reservoir, but not the total reservoir
fluid(retrograde condensate stays in reservoir)
Differences Between the Three Gases
Field Identification of Reservoir Fluids
Gasres bbl Oil
Sep
arat
or
Stocktank
scfSTB
GOR =
STB
scf
scf
res bbl
As previously discussed, reservoir fluids are classified based on the location of initial reservoir conditions with respect to the phase envelope of the fluid.
This identification is a key factor in many decisions related to field development plan and reservoir management. In addition, field data available from production information can also serve to some extent as indicators of fluid type. Some of the production observations that can be used for this identification include:1. Initial production gas-to-oil ratio (GOR) or gas-to-liquids (GLR). 2. Stock Tank Oil density (API gravity).3. Color of stock tank oil.
Field Identification of Reservoir Fluids
Components of Naturally Occurring Petroleum Fluids
Component Composition, mole percent
Hydrogen sulfide 4.91 Carbon dioxide 11.01 Nitrogen 0.51 Methane 57.70 Ethane 7.22 Propane 4.45 i-Butane 0.96 n-Butane 1.95 i-Pentane 0.78 n-Pentane 0.71 Hexanes 1.45 Heptanes plus 8.35 100.00 Properties of heptanes plus Specific Gravity 0.807 Molecular Weight 142 lb/lb mole
Petroleum fluids are typically composed of a great number of
components belonging to different chemical species. Most of the light
and intermediate components can be clearly identified as individual
entities (C1 through C6), but most of the heavy molecules are typically
lumped and grouped as a “plus fraction” (C7+). In some instances, this
plus fraction can be further characterized for compositional studies.
The C7+ fraction has been found to be a good indicator of fluid
type, as it correlates very well to observed field production data.
Components of Naturally Occurring Petroleum Fluids
Field Identification
Black Oil
Volatile Oil
Retrograde Gas
Wet Gas
Dry Gas
Initial Producing Gas/Liquid Ratio, scf/STB
<1750 1750 to 3200
> 3200 > 15,000* 100,000*
Initial Stock-Tank Liquid Gravity, API
< 45 > 40 > 40 Up to 70 No Liquid
Color of Stock-Tank Liquid
Dark Colored Lightly Colored
Water White
No Liquid
*For Engineering Purposes
This table summarizes McCain’s guidelines for fluid type
identification. McCain also included some additional guidance in
terms of API and color to further verify the selection of fluid type.
In this table, the 1,750 scf/STB break between black oils and volatile
oils is not sharp - could be 250 scf/STB. In general, initial stock-
tank oil gravity and color are not as important to the identification of
fluid type -- except in the black oil - volatile oil overlap
