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Presentation Online Course Reservoir Modelling

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```Online Course
RESERVOIR MODELLING
USING MBAL SOFTWARE
Instr. Eng. Moataz M. Altarhoni
E-mail: [email protected]
Telegram Channel:
http:t.me/telepetrosoftware
Course Objectives
By the End of this Course, participants would have:
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•
•
•
•
•
•
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Analysis the data; reservoir pressure, production profiles.
Learn Pressure Normalization Technique.
Gained the Knowledge on concept of Material Balance.
Data requirements for conducting Material Balance study.
reservoir performance.
Analysis the reservoir drive mechanisms and the most prominent at
various date.
You will learn how to Match the PVT Laboratory with Empirical
Correlations.
Evaluate the Original Oil in place of the field.
History Matching Technique (Analytically &amp; Graphically).
Introduction to Reservoir Engineering
•
•
Classification of Reservoirs.
•
Reservoir Fluid Properties.
•
Reservoir Rock Properties.
•
Methods of Original Oil in Place.
•
How much oil and gas is originally in place?
•
What are the drive mechanisms for the reservoir?
•
What will the recovery factor be by primary depletion?
•
Does there existing of water influx? How much volumes?
•
Evaluate the Strength and the Characterization of Aquifer?
Classification of Reservoirs
•
Petroleum reservoirs are broadly classified as oil or gas reservoirs;
•
Classify of reservoir depends on ‘’Phase diagram’’
•
Classified based on the Location of the
point representing the initial reservoir
pressure (pi) and Temperature (Ti).
•
Oil reservoirs: When the reservoir
temperature T is less than the critical
temperature Tc of the reservoir fluid.
•
Gas reservoirs: When the reservoir
temperature T is greater than the critical
temperature Tc of the hydrocarbon fluid.
Classification of Reservoirs
•
Oil Reservoirs Can be sub-classified depends on Initial reservoir pressure.
•
A) Undersaturated oil reservoir:
(When the Pi &gt; Pb)
•
B) Saturated oil reservoir:
(When the Pi = Pb)
•
C) Gas-cap reservoir:
(When the Pi &lt; Pb)
Reservoir Fluid Properties
•
Crude Oil Gravity
defined as the ratio of the density of the oil to that of water.
𝑂𝑖𝑙 𝐷𝑒𝑛𝑠𝑖𝑡𝑦
𝑆. 𝐺 =
𝑤𝑎𝑡𝑒𝑟 𝐷𝑒𝑛𝑠𝑖𝑡𝑦
The density of the water is approximately 62.4 lb/ft3
47 API◦
141.5
𝐴𝑃𝐼 =
− 131.5
𝑆. 𝐺
Lighter
10 API◦
Heavier
gravity scale
Reservoir Fluid Properties
•
Bubble Point Pressure
defined as the highest pressure at which a bubble of gas
is first liberated from the oil.
This important property can be measured
experimentally for a crude oil system by conducting
a constant-composition expansion test (CCE).
Reservoir Fluid Properties
•
Gas Solubility, Rs
defined as the number of standard cubic feet of gas which
will dissolve in one stock-tank barrel of crude oil at certain
pressure and temperature.
Also, Called ‘Gas Oil Ratio’ GOR
The Unit of GOR, SCF/STB
Reservoir Fluid Properties
•
Oil Formation Volume Factor
defined as the ratio of the volume of oil (plus the gas in
solution) at the prevailing reservoir temperature and
pressure to the volume of oil at standard conditions.
• Bo is always greater than or equal to unity.
• Expressed Mathematically;
Reservoir Rock Properties
•
Porosity
The porosity of a rock is a measure of the storage capacity
(pore volume) that is capable of holding fluids. Quantitatively,
the porosity is the ratio of the pore volume to the total volume
(bulk volume).
•
Absolute Porosity
Defined as the ratio of the total pore space in the
rock to that of the bulk volume.
•
Effective Porosity
the percentage of interconnected pore space with
respect to the bulk volume.
Reservoir Rock Properties
•
Permeability
Permeability is a property of the porous medium that measures
the capacity and ability of the formation to transmit fluids.
Terms
•
Hydrocarbon in Place
is the total quantity of the hydrocarbon (oil and gas) in the
reservoir at normal conditions.
- STOIP, OOIP, N: Original Oil In Place (sm3) (stb)
- OGIP, Gf Original Gas In Place (sm3) (Scf)
•
Cumulative Production
is a accumulated production at a given day
- Np cumulative oil production sm3 or stb
- Gp cumulative gas production sm3 or scf
- Wp cumulative water production sm3 or stb
Terms
•
Recovery factor
Used Symbol; ER
𝑐𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
ER =
𝑂𝑂𝐼𝑃 𝑜𝑟 𝑂𝐺𝐼𝑃
•
=
𝑁𝑝
𝑁
=
𝐺𝑝
𝐺
Ultimate Recovery Factor
Used Symbol; ER
𝑈𝑙𝑡𝑖𝑚𝑎𝑡𝑒 𝑅𝑒𝑐𝑜𝑣𝑒𝑟𝑦
ER,max =
𝑂𝑂𝐼𝑃 𝑜𝑟 𝑂𝐺𝐼𝑃
=
𝑁𝑝,𝑚𝑎𝑥
𝑁
=
𝐺𝑝,𝑚𝑎𝑥
𝐺
Terms
•
Difference between Reserves and Resources?
- Reserves or recoverable reserves are the volume of hydrocarbons that can
be profitably extracted from a reservoir using existing technology.
- Resources are reserves plus all other hydrocarbons that may eventually
become producible; this includes known oil and gas deposits present that
cannot be technologically or economically recovered (OOIP and OGIP) as well
as other undiscovered potential reserves.
Reserves Estimation
• Estimating hydrocarbon reserves is a complex process that involves integrating
geological and engineering data.
• Depending on the amount and quality of data available, one or
more of the following methods may be used to estimate reserves:
- Volumetric.
- Material balance.
- Decline Curve Analysis.
- Analogy.
Reserves Estimation
Method
Volumetric
Material balance
Decline Curve Analysis
Analogy
Application
OOIP, OGIP, recoverable reserves.
Use early in life of field.
production history available),
recoverable reserves
(assumes OOIP and OGIP known).
Use in a mature field with abundant
geological, petrophysical, and
engineering data.
Recoverable reserves. Use after a
moderate amount of production data
is available.
OOIP, OGIP, recoverable reserves.
Use early in exploration and initial
field development.
Accuracy
Dependent on quality of reservoir
description. Reserves estimates often
high because this method does not
consider problems of reservoir
heterogeneity.
Highly dependent on quality of
reservoir description and amount of
production data available. Reserve
estimates variable.
Dependent on amount of production
history available. Reserve estimates
tend to be realistic.
Highly dependent on similarity of
reservoir characteristics. Reserve
estimates are often very general.
Volumetric Method (Static method)
• sources of data from core samples, wireline logs, and geological maps
Volume Parameter Equations and Equalities
Rock Volume
VR = A * h
Pore Volume
VP = VR * φ = A * h * φ
Hydrocarbon Pore Volume
VHCP = VP * (SHC ) = A * h * φ *
(SHC)
Where SHC = the hydrocarbon
saturation of interest (either
So or Sg).
A
h
Volumetric Method
• Stock-tank oil initially in place (STOIIP)
- Bulk Volume = (V) Net Rock Volume (Bulk volume), res bbl
- Pore Volume = 𝑉 ∗ ∅ res bbl
- Hydrocarbon pore volume (HCPV) = 𝑉 ∗ ∅ ∗ (1 − 𝑆𝑤𝑖) res bbl
7758 ∗ 𝐴 ∗ ℎ ∗ ∅ ∗ (1 − 𝑆𝑤𝑖)
𝑂𝑂𝐼𝑃 𝑆𝑇𝐵 =
𝐵𝑜𝑖
Volumetric Method
• Recovery Factor
• Oil Reserve
𝑅𝐹 =
𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑂𝑖𝑙 𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
𝑋100
𝑆𝑇𝑂𝐼𝐼𝑃
= 𝑅𝐹 ∗ 𝑆𝑇𝑂𝐼𝐼𝑃
Primary Drive Mechanisms
• The over all performance of oil reservoirs is largely determined by
- the nature of the energy, i.e., driving mechanism, available for moving the
oil to the wellbore.
• Basically, six driving mechanisms that provide the natural
energy necessary for oil recovery:
- Rock and liquid expansion drive.
- Depletion drive.
- Gas cap drive.
- Water drive
- Gravity drainage drive
- Combination drive
Rock and Liquid Expansion
• When an oil reservoir initially exists at a pressure higher than its
bubble point “Undersaturated oil reservoir”.
• As the reservoir pressure decrease; due to production
- Expansion of individual rock grains.
- the Fluids expand.
Expansion of Rock
Oil
• Recovery factor is up to 5 %.
Rock grain
Matrix
Solution Gas Drive (Dissolved Gas)
• Source of Energy is “Gas liberation” from oil.
• As the reservoir pressure decrease, the solution
gas expand.
• The bubble expand and force oil out.
• Low recovery 5 - 30 %.
Gas Cap Drive
• When an oil reservoir initially exists at a pressure
below than its bubble point “Gas Cap Reservoir”.
• Source of Energy comes from:
- Expansion of the gas-cap.
- Expansion of the solution gas.
• Oil Recovery ranged between 20 to 40 %
Water Drive
• Many reservoirs are bounded on a portion or all
directions water bearing rocks “aquifers”.
• The reservoir pressure decline is usually very gradual.
• The size of the aquifer effects on the reservoir
performance.
• The oil Recovery is affected by the degree of
activity of the water.
• Oil Recovery ranges from 35% – 75%.
Analysis the Data
- Q1: What is maximum rate of oil has produced? When?
- Q2: What is possible interpretation of water production?
- Q3: What is the degree of reservoir pressure decline?
- Q4: If there is no some pressure measurements of reservoir
pressure data, How can predicted?
Analysis the Data
• Reservoir Pressure data.
Drive Mechanisms
Rock &amp; Fluid Expansion
Solution Gas Drive
Trend
The reservoir pressure declines rapidly and continuously.
Declines rapidly and continuously
Gas Cap Drive
Pressure falls slowly and continuously. Pressure tends to be maintained
at a higher level than in a depletion drive reservoir. The degree of
pressure maintenance depends upon the volume of gas in the gas cap
compared to the oil volume.
Water Drive
The decline in the reservoir pressure is usually very gradual. The reason
for the small decline in reservoir pressure is that oil and gas withdrawals
from the reservoir are replaced almost volume for volume by water
encroaching in to the oil zone.
Analysis the Data
• Water Production
Drive Mechanisms
Rock &amp; Fluid Expansion
Solution Gas Drive
Gas Cap Drive
Water Drive
Trend
The absence of a water drive means there will be little or no water
production with the oil during the entire producing life of the reservoir.
None.
Absent or negligible water production.
Early excess water production occurs in structurally low wells. This is
characteristic of a water drive reservoir, and provided the water is
encroaching in a uniform manner, nothing can or should be done to
restrict this encroachment, as the water will probably provide the most
efﬁcient displacing mechanism possible. If the reservoir has one or more
lenses of very high permeability, then the water may be moving through
this more permeable zone. In this case, it may be economically feasible to
performer medial operations to shut off this permeable zone producing
water.
Material Balance Equation
• It is very useful and are incredibly simple tools for gaining an
understanding of the reservoir processes .
• Powerful method to estimate OOIP and OGIP.
• Estimate Aquifer Influx.
• Data requirement;
- Required accurate pressure measurements.
- PVT representative .
- Production/ injection from or into the reservoir.
Material Balance Equation
• Given the reservoir pore volume under reservoir Conditions
- Initial reservoir pressure (Pi)
- Initial reservoir Temperature (Ti).
• The tank represents the total pore volume of the reservoir.
Material Balance Equation
• Fit all hydrocarbon of the reservoir into the tank.
- Zero-dimensional representation
• The Size of the potential gas cap is measured relative to the size of the
oil volume.
𝒂𝒕 𝒊𝒏𝒊𝒕𝒊𝒂𝒍 𝑪𝒐𝒏𝒅𝒊𝒕𝒊𝒐𝒏
P = Pi
𝐺𝑎𝑠 𝑉𝑜𝑙𝑢𝑚𝑒
𝒎=
𝑂𝑖𝑙 𝑉𝑜𝑙𝑢𝑚𝑒
𝑮𝒇𝑩𝒈𝒊
𝑵𝑩𝒐𝒊
𝐺𝑓𝐵𝑔𝑖 = 𝑚 ∗ 𝑁𝐵𝑜𝑖
Material Balance Equation
• Expansion of the reservoir fluids due to decease in reservoir pressure.
- P &lt; Pi.
• At the lower pressure, the gas cap expands, the aquifer expands and
the oil volume changes.
P &lt; Pi
P = Pi
𝑮𝒇𝑩𝒈𝒊
𝑮𝒇𝑩𝒈
𝑵𝑩𝒐 + 𝑵 𝑹𝒔𝒊 − 𝑹𝒔 𝑩𝒈
𝑵𝑩𝒐𝒊
𝑾𝒆
Material Balance Equation
• [Expanded volume] - [Initial Volume] = [Produced Volume]
𝑵𝒑 𝑹𝒑 − 𝑹𝒔 𝑩𝒈
𝑵𝑩𝒐
𝑾𝒑𝑩𝒘
𝑮𝒇𝑩𝒈𝒊
= 𝒎 ∗ 𝑵𝑩𝒐𝒊
𝑵𝑩𝒐𝒊
𝑮𝒇𝑩𝒈
𝑵𝑩𝒐 + 𝑵 𝑹𝒔𝒊 − 𝑹𝒔 𝑩𝒈
𝑾𝒆
Initial Condition
Expanded Volume
Reservoir Content
Material Balance Equation
• Initial volume at Pi:
𝑁𝐵𝑜𝑖 + 𝐺𝑓𝐵𝑔𝑖 = 𝑁𝐵𝑜𝑖 + 𝑚𝑁𝐵𝑜𝑖
• Expanded volume at p:
𝐵𝑔
𝑚𝑁𝐵𝑜𝑖
+ 𝑁𝐵𝑜 + 𝑁𝐵𝑔 ∗ 𝑅𝑠𝑖 − 𝑅𝑠 + 𝑊𝑒
𝐵𝑔𝑖
• Produced volume at p:
𝑁𝑝𝐵𝑜 + 𝑁𝑝 𝑅𝑝 − 𝑅𝑠 𝐵𝑔 + 𝑊𝑝𝐵𝑤
Material Balance Equation
• [Expanded volume] - [Initial Volume] = [Produced Volume]
𝐵𝑔
𝑚𝑁𝐵𝑜𝑖
+ 𝑁𝐵𝑜 + 𝑁𝐵𝑔 ∗ 𝑅𝑠𝑖 − 𝑅𝑠 + 𝑊𝑒 − 𝑁𝐵𝑜𝑖 + 𝑚𝑁𝐵𝑜𝑖
𝐵𝑔𝑖
= 𝑁𝑝𝐵𝑜 + 𝑁𝑝 𝑅𝑝 − 𝑅𝑠 𝐵𝑔 + 𝑊𝑝𝐵𝑤
𝑁𝑝 𝐵𝑜 + 𝑅𝑝 − 𝑅𝑠 𝐵𝑔 − 𝑊𝑒 − 𝑊𝑝𝐵𝑤
𝑁=
𝐵𝑔
𝑆𝑤𝑖𝐶𝑤 + 𝐶𝑓
𝐵𝑜 − 𝐵𝑜𝑖 + 𝑅𝑠𝑖 − 𝑅𝑠 𝐵𝑔 + 𝑚𝐵𝑜𝑖
− 1 + 1 + 𝑚 𝐵𝑜𝑖
∆𝑃
𝐵𝑔𝑖
1 − 𝑆𝑤𝑖
Material Balance Equation
• Assumption and Limitation.
- The Reservoir is assumed to be as a (Tank).
- The Reservoir is assumed to homogenous (thus, they have
uniform reservoir properties).
- The Reservoir Temperature and pressure are uniformly distributed.
Material Balance Evaluation
The MBALTM material balance tool will use for the evaluation.
• Reservoir type definition. The MBALTM tool allows the definition of
reservoir type in terms of fluid content. That is, the reservoir can be
defined as oil, gas or retrograde condensate. In the first step, the
fluid type for each reservoir will defined by the integration of
available engineering and petrophysical information.
• Data Preparation/Consistency Checks. Preparation of data and
consistency
checks
are
performing
on
the
PVT,
production/injection history, average reservoir pressure, and
reservoir and aquifer data.
Material Balance Evaluation
• PVT Data. Validation and QC is very important process must
run for confirming have a valid PVT Study reports and
suggesting the suitability of the data for the evaluation.
• Production/Injection Data. Available a long period of
production history for the reservoirs. Annually or Monthly
historical cumulative production and injection data, and
reformat with the correct units before importing into MBALTM.
Material Balance Evaluation
pressure measurements. For each reservoir, validity checks should
make on the average reservoir pressure data by plotting these on
Excel spreadsheet. Invalid pressure points will exclude.
• Reservoir and Aquifer Data. Reservoir data such as temperature,
initial pressure, porosity and connate water saturation are obtaining
from existing records. Aquifer properties are estimate based on
known reservoir properties and evidence from geological maps.
Because of the higher level of uncertainty attached to the aquifer
parameters, these are more adjust during the history match phase.
Analysis the Drive Mechanisms
▪ Depletion Drive: is the oil recovery mechanism wherein the production of
the oil from its reservoir rock is achieved by the expansion of the original oil
volume with all its original dissolved gas.
▪ Segregation Drive: Segregation drive (gas-cap drive) is the mechanism
wherein the displacement of oil from the formation is accomplished by the
expansion of the original free gas cap.
▪ Water Drive: Water drive is the mechanism wherein the displacement of the
oil is accomplished by the net encroachment of water into the oil zone.
▪ Expansion Drive: the principle source of energy is a result of the rock and
fluid expansion
Analysis the Drive Mechanisms for Field
Energy Plot
1
0.9
0.8
WDI
0.7
EDI
Drive Index
0.6
0.5
DDI
0.4
0.3
0.2
Example; Drive Mechanisms using Excel
0.1
0
Time
Analysis the Drive Mechanisms
• Determine the relative magnitude of each of the driving
mechanisms and its contribution to the production
𝑆𝑤𝑖𝐶𝑤 + 𝐶𝑓
𝑁𝐵𝑜𝑖
1
+
𝑚
[
]∆𝑃
𝑁(𝐵𝑡 − 𝐵𝑡𝑖) 𝑁𝑚𝐵𝑡𝑖(𝐵𝑔 − 𝐵𝑔𝑖)/𝐵𝑔𝑖 𝑊𝑒 − 𝑊𝑝𝐵𝑤
1
−
𝑆𝑤𝑖
+
+
+
=1
𝐴
𝐴
𝐴
𝐴
Depletion Drive
Index (DDI)
Gas Cap Drive
Index (GDI)
𝐴 = 𝑁𝑝[𝐵𝑡 + 𝑅𝑝 − 𝑅𝑠 𝐵𝑔]
Water Drive
Index (WDI)
Expansion Drive
Index (EDI)
DDI+GDI+WDI+EDI = 1
Terms
•
Model: the set of input and output data for a particular application.
•
Reservoir modeling
is, therefore, the process of incorporating data
evaluations and interpretations into a numerical simulator and using the
results for reservoir engineering and reservoir management purposes
Input Data
(USER)
Processing
MBAL
Output Data
(Software)
Introduction to MBAL Software
• MBAL: is in a package made up of various tools
designed to help the engineer to gain a better
understanding of reservoir behavior and perform
prediction run.
• MBAL developed by Petroleum Experts.
• MBAL has redefined the use of Material Balance in
modern reservoir engineering.
Data requirements for conducting Material Balance study.
• Average Reservoir Pressure Measurements.
• Representative PVT Data.
• Production History including All fluids (Injection if available).
• Reservoir Data (Logs or Core)
• Rock &amp; Water Compressibility.
PVT Correlations
• Ideally, laboratory measured PVT data should be utilized.
• Many times, laboratory data is not available and correlations must be
• It is difficult to say which correlation should be used when.
• The best correlation is the one that matches your data.
• The main properties which are determined from empirical correlations
are the bubble point, gas solubility, volume, density, compressibility,
and viscosity.
PVT Correlations
• Data required to correlate the PVT.
- Reservoir Temperature.
- Initial Reservoir Pressure.
- Gas Oil Ratio.
- Oil Gravity.
- Gas Gravity.
Example: Standing’s Correlation
Oil Properties
Gas Solubility, Rs
Bubble point pressure, Pb
Equation
1.2045
𝑃
𝑥
𝑹𝒔 = 𝛾𝑔
+ 1.4 10
18.2
𝑥 = 0.0125𝐴𝑃𝐼 − 0.00091(𝑇 − 450)
𝑷𝒃 = 18.2
𝑅𝑠
𝛾𝑔
0.83
10
𝑎
− 1.4
𝑎 = 0.00091 𝑇 − 460 − 0.0125 𝐴𝑃𝐼
Oil Formation Volume Factor, Bo
𝑩𝒐 = 0.9759 + 0.000120
𝑅𝑠
𝛾𝑔
𝛾𝑜
1.2
0.5
+ 1.25 𝑇 − 460
Rock Compressibility Correlations
• Formation compressibility range from
-
(3 X 10-6) to (25 X 10-6 psi-1)
• Correlations used to estimate Rock compressibility depends on
Porosity.
- Hall’s Correlation (1953);
𝑪𝒇 =
𝟏. 𝟕𝟖𝟐
∗ 𝟏𝟎−𝟔
.𝟒𝟑𝟖
∅
- Newman Correlation (1973); • For Consolidated Sandstone
𝒂
𝑪𝒇 =
𝟏 + 𝒄𝒃∅
a = 97.32x10^-6
b = 0.699993
C = 79.8181
• For Limestone
a = 0.8535
b = 1.075
C = 2.202x10^6
Straight-line solution method to MBE
• The significance of the straight-line approach is that the
sequence of plotting is important and if the plotted data
deviates from this straight line there is some reason for it.
•
This significant observation will provide the
engineer with valuable information that can be
used in determining the following unknowns:
• Initial oil in place (N)
• Size of the gas cap (m)
• Water influx (We)
• Driving mechanisms.
Straight-line solution method to MBE
𝑁𝑝 𝐵𝑜 + 𝑅𝑝 − 𝑅𝑠 𝐵𝑔 − 𝑊𝑒 − 𝑊𝑝𝐵𝑤
𝑁=
𝐵𝑔
𝑆𝑤𝑖𝐶𝑤 + 𝐶𝑓
𝐵𝑜 − 𝐵𝑜𝑖 + 𝑅𝑠𝑖 − 𝑅𝑠 𝐵𝑔 + 𝑚𝐵𝑜𝑖
− 1 + 1 + 𝑚 𝐵𝑜𝑖
∆𝑃
𝐵𝑔𝑖
1 − 𝑆𝑤𝑖
• 𝐹 = 𝑁𝑝 𝐵𝑜 + 𝑅𝑝 − 𝑅𝑠 𝐵𝑔 + 𝑊𝑝𝐵𝑤
• 𝐸𝑜 = 𝐵𝑜 − 𝐵𝑜𝑖 + 𝑅𝑠𝑖 − 𝑅𝑠 𝐵𝑔
• 𝐸𝑔 = 𝐵𝑜𝑖
𝐵𝑔
𝐵𝑔𝑖
−1
𝑆𝑤𝑖𝐶𝑤+𝐶𝑓
)∆𝑃
1−𝑆𝑤𝑖
• 𝐸𝑓, 𝑤 = 𝐵𝑜𝑖(
𝐹 − 𝑊𝑒
𝑁=
𝐸𝑜 + 𝑚𝐸𝑔 + 𝐸𝑓, 𝑤
Straight-line solution method to MBE
• Case (1):
- In this Case, we assume the following:
&gt; Undersaturated oil reservoir (P &gt; Pb) i.e., No Gas Cap (m=0)
&gt; No water influx invaded into the reservoir during the
production life (We = 0).
&gt; No Expansion of rock and water when pressure drop.
GMBE:
In Case:
F = N {Eo + mEg + Ef,w} + We
F = N Eo
Y = Slope * X
Straight-line solution method to MBE
• Case (2):
- In this Case, we assume the following:
&gt; Undersaturated oil reservoir (P &gt; Pb) i.e., No Gas Cap (m=0)
&gt; No water influx invaded into the reservoir during the
production life (We = 0).
&gt; Include the Expansion of rock and water when pressure
drop.
GMBE:
In Case:
F = N {Eo + mEg + Ef,w} + We
F = N {Eo + Ef,w)
Y = Slope * X
Interpretation Technique (1)
• In Case (2): the Plot F vs. (Eo+Ef,w)
- If the Plot is linear, that indicate that the field is producing
under volumetric performance, i.e., no water influx, and
strictly by pressure depletion and fluid expansion.
- If the Plot is nonlinear, that indicate the reservoir should
be characterized as a water-drive reservoir.
Interpretation Technique (2)
•
Different Values of OOIP (N) Between Case 1 &amp; 2, Explain!
• In Case of Ignore Any Drive
Mechanism (Rock and fluid
Estimation in OOIP (N)
Classification of the reservoir
• When a new field is discovered, one of the first tasks of the reservoir engineer
is to determine if the reservoir can be classified as a volumetric reservoir, i.e.,
We = 0.
• The Plot of F/(Eo+Ef,w) plotted versus
cumulative production Np or Time.
Interpretation Technique (3)
• In Case (2): the Plot F/(Eo+Ef,w) vs. Np or Time
- If (A) Horizontal Line, the reservoir classified
as (Volumetric) i.e., No water influx
- If (B OR C) raise the line, the reservoir has
been energized by water influx
If (B): the outer boundary has been felt
and the aquifer is depleting in union with
the reservoir it self.
If (C): might by strong water drive field, in
which the aquifer is displacing an infinite
acting behaviour.
Interpretation Technique (4)
• Campbell Plot:
- Used to identify the relative strength of aquifer.
- Plotting F/Et on the Y axis versus F on the Xaxis will yield a plot with one of the
characteristic curve shapes as shown below.
- It should be noted that we assume
the reservoir to be a volumetric
reservoir, which is not producing
under water drive so as to detect
whether we have a producing aquifer
with water drive or a depletion drive.
Therefore we let We=0.
History Matching
• It is a process of modifying the input data into a reservoir model until a
reasonable comparison is obtained between the observed data and the
simulated.
• This step is necessary before any prediction of reservoir performance.
• Two methods will utilize in carrying out the history match namely:
- Analytical method.
- Graphical method.
Note: The quality of the history match is directly
proportional to the amount and accuracy of the available
data.
Analytical Method
• In the analytical method, non-linear regression will use to estimate
unknown reservoir and aquifer parameters during the history
match.
• The method is graphically interactive and is based on fitting a model
to the trend of pressure vs cumulative production of the predominant
reservoir fluid as changes are made to the input parameters.
• A match obtain through the analytical method alone does not
guarantee that the right model will use especially where there is
some aquifer.
Graphical Method
• Verification of the right model will achieve through the graphical method.
Hence, the results of the analytical approach will visualize with the
corresponding straight-line method like the Havlena-Odeh and, Campbell,
etc.
• The analytical model will have considered adequate if the graphical method
produces a good match which guarantees that the hydrocarbon volumes
and aquifer strength applied are correct.
MBAL Simulation
• After obtaining a history match, the validity of the match will establish by
running a simulation with the final material balance model. The results obtain
from the simulation should compare with the historical input data of pressure,
cumulative oil, and finally injection.
Water Influx
• Nearly all hydrocarbon reservoirs are surrounded by water-bearing rocks
called aquifers.
• These aquifers may be substantially larger than the oil or gas reservoirs they
adjoin as to appear infinite in size, or they may be so small in size as to be
negligible in their effect on reservoir performance.
• As reservoir fluids are produced and reservoir pressure declines, a pressure
differential develops from the surrounding aquifer into the reservoir
• Following the basic law of fluid flow in porous media, the aquifer reacts by
encroaching across the original hydrocarbon-water contact. In some cases,
water encroachment occurs due to hydrodynamic conditions and recharge of
the formation by surface waters at an outcrop.
Aquifer Negligible Cases
• In many cases, the pore volume of the aquifer is not significantly larger than
the pore volume of the reservoir itself. Thus, the expansion of the water in
the aquifer is negligible relative to the overall energy system, and the
reservoir behaves volumetrically. In this case, the effects of water influx can
be ignored.
• In other cases, the aquifer permeability may be sufficiently low such that a
very large pressure differential is required before an appreciable amount of
water can encroach into the reservoir. In this instance, the effects of water
influx can be ignored as well.
Aquifer Configuration
• Infinite Aquifer
- Usually, most of reservoirs are hydraulically linked with an aquifer.
- Often its volume much bigger than the trapped hydrocarbon.
- Some reservoirs are submitted
through an aquifer extending up
to surface.
- the effect of the pressure
changes
at
the
oil/aquifer
boundary can never be felt at the
outer boundary.
Aquifer Configuration
• Bottom water Drive
- Aquifer is in contact with the entire hydrocarbon area.
- Water invasion occurring vertically is governed by the
reservoir vertical permeability .
Aquifer Configuration
• Edge Water Drive
- Aquifer surrounded the hydrocarbon reservoir.
- Horizontal Permeability is governing the water movement.
• Linear Water Drive
Outer boundary Conditions
• The aquifer can be classified as infinite or finite (bounded).
• Geologically all formations are finite, but may act as infinite if the
changes in the pressure at the oil-water contact are not “felt” at the
aquifer boundary.
Infinite system indicates that the effect of the pressure changes at the
oil/aquifer boundary can never be felt at the outer boundary. This
boundary is for all intents and purposes at a constant pressure equal to
initial reservoir pressure.
Finite system indicates that the aquifer outer limit is affected by the
influx into the oil zone and that the pressure at this outer limit
changes with time
Predicting of water influx using Models
• Pot Aquifer Model
- Aquifer Volume reacts instantly with to a pressure drop at OWC.
- Aquifer expands into the oil zone of an amount function of the water
volume and total compressibility (Aquifer plus rock).
- Can be only used for small aquifers!
- Noting this model is independent of time!
ra = radius of the aquifer, ft
re = radius of the reservoir, ft
h = thickness of the aquifer, ft
φ=porosity of the aquifer
θ=encroachment angle
cw = aquifer water compressibility, psi−1
cf = aquifer rock compressibility, psi−1
Wi = initial volume of water in the aquifer, bbl
𝑾𝒆 = 𝑪𝒘 + 𝑪𝒇 ∗ 𝑾𝒊 ∗ 𝒇 ∗ (𝑷𝒊 − 𝑷)
𝜋 𝑟𝑎2 − 𝑟𝑒 2 ℎ∅
𝑊𝑖 =
5.615
𝑓=
𝑒𝑛𝑐𝑟𝑜𝑎𝑐ℎ𝑚𝑒𝑛𝑡 𝑎𝑛𝑔𝑙𝑒
360
Discuss &amp; Conclusion
THANK YOU!
PETROSOFTWARE