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GAS FIELD ENGINEERING
Gas Reserves Estimation
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CONTENTS
8.1 Introduction
8.2 Reserves and Reservoir Performance Predictions
8.3 Volumetric Estimates
8.4 Material Balance Estimates
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Lesson Learning Outcome
At the end of the session, students should be able to:
Calculate Gas Reserves by Volumetric method
Calculate Gas Reserves by Material Balance method
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Introduction Reserve Estimation Methods: more than one available.
Different methods applicable at different stages of development.
Data requirement different for each method, with some common
Predominant methods:
1.Volumetric method
2.Material Balance Method
3.Decline Curve Analysis
4.Reservoir Simulation
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Introduction
1.Volumetric method
Early stage of reservoir development
Geology, Geophysics, Reservoir rock and fluid properties required
Recovery Factor(RF) assigned arbitrarily
No time dependency, No production data required
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Introduction
2.Material Balance Method
Later stage of development (after 20% of initial oil/gas is produced, or 10% of initial reservoir pressure has declined)
Geological data, Reservoir rock and fluid properties, production data required
RF is calculated
Time dependant
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Introduction
3.Decline Curve Analysis
Later stage of development, when production rate undergoes natural decline
Mostly production data required
RF is calculated
Time dependant
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Introduction
4.Reservoir Simulation
Can be applied at any stage but more useful and reliable for matured reservoirs
Geological data, Rock and Fluid properties, Production data required
More useful as reservoir management tool
Uncertainties associated with each method
More than one method should be used when applicable
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Introduction Natural gas reservoirs are reservoirs in which the contained
hydrocarbon fluids exist wholly as a vapor phase at pressure values equal to or less than the initial value.
Unlike saturated crude oils and condensates, natural gases do not undergo phase changes upon reduction in reservoir pressure.
Performance predictions are therefore relatively simple.
Natural gas is commonly termed wet (or raw) gas.
Cumulative gas produced (Gp) means separator gas plus vapor equivalent of the natural gas liquid (NGL) removed in the separator.
Gas formation volume factor (Bg) and gas deviation factor (Z) refer to the properties of a sample of separator gas and liquid.
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Introduction
Natural gas reserves are classified according to nature of their occurrence.
Non-associated gas is free gas not in contact with crude oil in the reservoir.
Associated gas is free gas in contact with crude oil in the reservoir.
Dissolved gas is gas in solution with crude oil in the reservoir.
This chapter address methods of estimating non-associated gas reserves.
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Gas in Place by Volumetric Equation
To make reasonable recovery predictions, estimates of the initial gas in place in each reservoir must be made.
Volumetric equation is a useful tool for calculating the gas in place at any time.
Reservoir rock volume is usually obtained by planimetering the isopacheous maps of productive reservoir rock.
Gas initially in place (GIIP) is the product of three factors: reservoir pore volume, initial gas saturation, gas formation volume factor that converts reservoir volumes to volumes at standard, or base, conditions 60oF, and 14.7 psia.
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Gas in Place by Volumetric Equation
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(11.1)
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Gas in Place by Volumetric Equation
If Bgi is in cu ft/scf,
Also:
Standard cubic feet of gas in place is given by:
Volumetric equation is particularly applicable when a field is comparatively new, before gas have been produced to cause an
appreciable drop in reservoir pressure.
If good data are available, volumetric will probably be reliable.
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(11.2)
(11.3)
(11.4)
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Gas in Place by Volumetric Equation
Omission of Z factor may affect reserve calculations up to 30% errors
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From gas laws,
bb
b
ZpT
TZpBg
At standard conditions of 14.7 psia and 60F,
p
TZ
p
TZBg 0283.0
]60460[
))(7.14(
(11.5)
(11.6)
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Material Balance Equation
Assumptions
1. A reservoir may be treated as a constant-volume tank.
2. Pressure equilibrium exists through out the reservoir.
3. Laboratory PVT data apply to the reservoir gas at the average
pressures used.
4. Reliable production and injection data, and reservoir
pressure measurements are available.
5. Change in volume of the interstitial water with pressure,
change in porosity with pressure, and the evolution of gas
dissolved in the interstitial water with decrease in pressure are
negligible.
The material balance is an expression of the law of
conservation of mass.
.
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Derivation
Conservation of mass may be applied to a gas reservoir to
yield mass and mole balances (m , n):
mp = mi m (11.7) Cumulative gas produced = initial gas in place - remaining gas (mass unit)
And np = ni - n (11.8) Cumulative gas produced = Initial gas in place - remaining gas (mole unit)
where:
mp, np= cumulative gas produced in mass and mole units
mi, ni = initial gas in place at initial pressure pi
m, n = gas remaining in reservoir at some subsequent pressure,
p
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Derivation
Using constant volume tank concept,
Let
-Vi barrels the original(initial) hydrocarbon reservoir volume at
the initial pressure pi.
-V barrels: remaining gas volume in the reservoir
-Gp scf produced gas at the surface,
-Wp stock tank barrels, produced water at the surface
-We stock tank barrels, encroached water into the reservoir,
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Derivation
-Since the reservoir being considered constant, the following
equation results:
Vi = V + We WpBw (11.9)
V = Vi - We + WpBw
(11.10)
-Vi , V, We and Wp Bw are in reservoir barrels
- Bw : water formation volume factor in reservoir barrels per
stock-tank barrel.
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Derivation
Gp = cumulative gas produced from pi to p, scf
R = universal gas constant, 10.732 cu ft-psi/lb
mole-oR. 19
From the Real Gas Law:
Thus,
and
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Derivation
Substituting in Eqn. 11.8 gives: np = ni n (11.8)
Or,
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(11.11)
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Derivation
Therefore, expressing Vi in terms of GIIP and substituting gas formation volume factors Bgi and Bg at pressures pi and p, Eqn 11.11 becomes:
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(11.12)
Gp = Cumulative gas produced.
GIIP = Gas Initially In Place
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Derivation
For reservoirs with no water influx and no water production: Eqn 11.11 and 11.12 become, respectively:
and
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(11.13)
(11.14)
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APPLICATION
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APPLICATION
Material balance equation applied to estimate
initial gas in place, determine existence and estimate
effectiveness of any natural water drive, assist in
predicting performance and reserves.
It may also verify possible extensions to a partially
developed reservoir where gas in place calculated by
material balance equation is much larger than a
volumetric equation estimate and water influx is thought
to be small.
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Reserves and Reservoir Performance Predictions
Energy required for gas production is usually derived either from gas expansion or a combination of gas expansion and water influx.
Volumetric estimation, and decline curve are methods which may be used to estimate gas reserves in place.
But in actual practice, estimation requires predicting abandonment pressure. This is the pressure at which further production will no longer be profitable.
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Reserves and Reservoir Performance Predictions
Abandonment pressure is determined by economic conditions
- future market value of gas
- cost of operating and maintaining wells
- cost of compressing
- transporting gas to consumers.
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Volumetric Estimates Volumetric equation is useful in estimating gas in place at any
stage of depletion.
During the development period, it is convenient to calculate gas in place per acre-foot of bulk reservoir rock.
Multiplication by estimate of bulk reservoir volume then gives gas in place for the lease, when reservoir volume is defined and performance data are available, volumetric calculations provide valuable checks on estimates obtained from material balance methods:
GIIP (scf/acre-ft)
Bulk reservoir volume = (Ah) acre-ft
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(11.16)
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Volumetric Estimates For Volumetric reservoirs,
Where
RG = gas reserves to abandonment pressure, scf/acre-ft
Eg = recovery factor, fraction of initial gas in place to be
recovered
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(11.18)
(11.17)
The recoverable reserves can be calculated by
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Volumetric Estimates
Some gas pipeline companies use an abandonment pressure of 100 psi/1000ft of depth.
If the abandonment pressure is known, recovery factor can be calculated.
Eg
Eg = recovery factor, fraction of initial gas in place to be
recovered
For water drive reservoir:
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Example 11.2
A proposed gas well is being evaluated. Well spacing is 640 acres and it appears that the entire 640 acres attributed to this well will be productive. Geological estimates indicate 30 ft of net effective pay, 15% porosity, and 30% interstitial water saturation. The initial pressure is 3000 psia and reservoir temperature is 150o F. The abandonment pressure is estimated to be 500 psia. The gas gravity is expected to be 0.60. Base temperature and pressure are 60oF, and 14.65 psia respectively. An estimate of the gas reserve is required.
Solution
The first step calculation of Bgi which requires pseudo-critical
T and P, pseudo-reduced T.
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Referring to Fig. Zi is found to be 0.83.
Using Eq. 11.5
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bb
b
ZpT
TZpBg (11.5)
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Second step is to calculate the recovery factor, Eg. Abandonment
pressure being 500 psia, pseudo-reduced pressure = 500/668 =
0.75. Using this value together with the pseudo-reduced
temperature. Za is found to be 0.94. Hence from Eq. 11.19:
From Eqn 11.19
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(11.19) ai
iag
Zp
ZpE 1
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Third step is use Eq. 11.18 to calculate reserve in scf/acre-ft
Final step is to multiply the above figure by the net acre-feet;
hence estimated reserve:
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(11.18)
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In some cases the porosity, connate water, and/or effective reservoir volumes are not known with reasonable precision, and volumetric method may be used to calculate the initial gas in place.
However, this method applies only to reservoir as a whole.
Accurate pressure-production data are essential for reliable material balance calculations.
Most likely source of error is estimating average reservoir pressure, especially during the early history period.
Material Balance Estimates
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Eqns 11.12 and 11.14 may be written as:
Material Balance Estimates
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(11.21)
(11.22)
Eqn 11.21 or 11.22 can be used to calculate the initial gas
in place.
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Material Balance Estimates If there is no water encroachment, only information required is
production data, pressure data, gas specific gravity for obtaining Z factors, and reservoir temperature.
However, early in the producing life of a reservoir the denominator of right-hand side of material balance equation is very small, numerator is relatively large.
A small change in the denominator will result in a large discrepancy in the calculated value of initial gas in place.
Therefore, material balance equation should not be relied upon early in the producing life of the reservoir.
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Example 11.3
(a) Calculate the initial gas in place in a closed gas reservoir if, after producing 500 MMscf, the reservoir pressure had declined to 2900 psia from an initial pressure of 3000 psia. Reservoir temperature is 175oF., and the gas gravity is 0.60.
(b) If the reservoir pressure measurement were incorrect and should have been 2800 psia instead of 2900 psia, what would have been the true value of initial gas in place?
Solution
(a) Using a gas gravity of 0.60 and referring to the Z-factor correlation charts (Figs. 2.4 and 2.5), Z at 3000 psia is computed to be 0.88 and Z at 2900 psia is determined to be 0.87.
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Note: Eq. 11.23 is in bbl/scf, Eq. 11.6 is in cu ft/ scf; The factor
which differentiates the two equations is 5.615 cu ft/bbl
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(11.23)
Next step is to calculate the two values of Bg;
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Equation 11.22 is next used to compute initial gas in place:
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(11.22)
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(b) If the pressure measurements were incorrect and the true
average pressure is 2800 psia, then the material balance
equation will be solved using the true pressure. Z-factor at 2800 psia is determined to be 0.87:
Next, initial gas in place is calculated by the material balance
equation:
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Q & A
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Thank You
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