A fracture is defined as a single crack initiated from the wellbore by hydraulic fracturing. It should be noted that fractures are different from
“fissures,” which are the formation of natural fractures. Hydraulically induced fractures are usually vertical, but can be horizontal if the forma- tion is less than about 3,000 ft deep. Vertical fractures are characterized by the following properties:
• Fracture half-length xf, in ft
• Dimensionless radius reD, where reD=re/xf
• Fracture height hf, which is often assumed equal to the formation thick- ness, in ft
• Fracture permeability kf, in md
• Fracture width wf, in ft
• Fracture conductivity FC, where FC=kf wf
The analysis of fractured-well tests deals with the identification of well and reservoir variables that would have an impact on future well perfor- mance. However, fractured wells are substantially more complicated.
The well-penetrating fracture has unknown geometric features, that is, xf, wf, and hf, and unknown conductivity properties.
s r
r
wa w
= − ⎛
⎝⎜
⎞
⎠⎟ = − ⎛⎝⎜ ⎞
⎠⎟ = −
ln ln .
. .
40 997
0 354 4 752
r r
r ft
wa e
eD mp
= = =
( )
. .
1147 9
28 40 997
r A
e = = × = ft
π π
4 1398 10
1147 9 . 6
.
k= ⎛ −
⎝⎜ ⎞
⎠⎟
=
( . ) ( . ) ( . ) ( . )
ln ( ) .
141 2 0 0225 0 00071 743 76
70 28 1
2 0 0679 mmd
Many authors have proposed three transient flow models to consider when analyzing transient pressure data from vertically fractured wells;
these are as follows:
• Infinite-conductivity vertical fractures
• Finite-conductivity vertical fractures
• Uniform-flux fractures
Description of these three types of fractures are as follows:
Infinite-Conductivity Vertical Fractures
These fractures are created by conventional hydraulic fracturing and characterized by a very high conductivity, which, for all practical pur- poses, can be considered infinite. In this case, the fracture acts similarly to a large-diameter pipe with infinite permeabilityand, therefore, there is essentially no pressure drop from the tip of the fracture to the well- bore, that is, no pressure loss in the fracture. This model assumes that the flow into the wellbore is only through the fracture and exhibits three flow periods:
• Fracture linear flow period
• Formation linear flow period
• Infinite-acting pseudo-radial flow period
Several specialized plots are used to identify the start and end of each flow period. For example, an early time log-log plot of Δp versus Δt will exhibit a straight line of half-unit slope. These flow periods associated with infinite conductivity fractures and the diagnostic specialized plots will be discussed later in this section.
Finite-Conductivity Vertical Fractures
These are very long fractures created by massive hydraulic fracture (MHF). These types of fractures need large quantities of propping agent to maintain them open, and, as a result, the fracture permeability, kf, is lower than that of the infinite-conductivity fractures. These finite-con- ductivity vertical fractures are characterized by measurable pressure drops in the fracture and, therefore, exhibit unique pressure responses during testing of hydraulically fractured wells. The transient pressure behavior for this system can include the following four sequence flow periods (to be discussed later):
• Initially, linear flow within the fracture
• Next, bilinear flow
• Then, linear flow in the formation
• And eventually, infinite acting pseudo-radial flow Uniform-Flux Fractures
A uniform flux fracture is one in which the reservoir fluid-flow rate from the formation into the fracture is uniform along the entire fracture length. This model is similar to the infinite-conductivity vertical fracture in several aspects. The difference between these two systems occurs at the boundary of the fracture. The system is characterized by a variable pressure along the fracture and exhibits essentially two flow periods:
• Linear flow
• Infinite-acting pseudo-radial flow
Except for highly propped and conductive fractures, it is thought that the uniform-influx fracture theory better represents reality than the infi- nite-conductivity fracture; however; the difference between the two is rather small.
The fracture has a much greater permeability than the formation it penetrates; hence, it influences the pressure response of a well test sig- nificantly. The general solution for the pressure behavior in a reservoir is expressed in terms of dimensionless variables. The following dimen- sionless groups are used when analyzing pressure transient data in a hydraulically fractured well:
• Conductivity group:
• Fracture group:
where xf=fracture half-length, ft wf=fracture width, ft
kf=fracture permeability, md
k =pre-frac formation permeability, md FC=fracture conductivity, md-ft
FCD=dimensionless fracture conductivity
r r
eD x
e f
=
F k
k w
x F
CD k x
f f
f C
f
= =
Pratikno, Rushing, and Blasingame (2003) developed a new set of type curves specifically for finite-conductivity vertically fractured wells centered in bounded circular reservoirs. The authors used analytical solutions to develop these type curves and to establish a relation for the decline vari- ables.
Recall that the general dimensionless pressure equation for a bounded reservoir during pseudosteady-state flow is given by Equation 6-137:
with the dimensionless time based on the wellbore radius, tD, or drainage area, tDA, as given by Equations 6-87 and 6-87a:
The authors adopted the last form and suggested that, for a well pro- ducing under pseudosteady-state at a constant rate with a finite-conduc- tivity fracture in a circular reservoir, the dimensionless pressure drop can be expressed as follows:
pD=2πtDA+bDpss or
bDpss=pD−2πtDA
where the term bDpss is the dimensionless pseudosteady-state constant that is independent of time; however, bDpssis a function of
• the dimensionless radius, reD, and
• the dimensionless fracture conductivity, FCD
The authors note that, during pseudosteady flow, the equation describ- ing the flow during this period yields constant values for given values of reDand FCDthat are closely given by the following relationship:
b r
r
a a u a u a u a u
Dpss eD
eD
= − + + + + + +
ln( ) . . +
0 049298 0 43464
2 1
1 2 3
2 4
3 5
4
bb u1 + b u2 2 + b u3 3 + b u4 4
t kt
c A t r
DA A
t
A
= = ⎛⎝⎜ w⎞
⎠⎟
0 0002637. 2 φμ
t kt
D c r
t w
= 0 0002637
2
. φμ
p t A
r C s
D DA
w A
= + ⎛
⎝⎜
⎞
⎠⎟
⎡
⎣⎢ ⎤
⎦⎥ + ⎛
⎝⎜
⎞
⎠⎟
⎡
⎣⎢ ⎤
⎦⎥ +
2 1
2
1 2
2 2458
π ln 2 ln .
with u =ln(FCD)
where a1=0.93626800 b1= −0.38553900 a2= −1.0048900 b2= −0.06988650 a3=0.31973300 b3= −0.04846530 a4= −0.0423532 b4= −0.00813558 a5=0.00221799
Based on the above equations, Pratikno et al. (2003) used Palacio and Blasingame’s previously defined functions (i.e., ta, (qDd)i, and (qDd)id) and the parameters reD and FCDto generate a set of decline curves for a sequence of 13 values for FCDwith a sampling of reD=2, 3, 4, 5, 10, 20, 30, 40, 50, 100, 200, 300, 400, 500, and 1,000. Type curves for FCD of 0.1, 1, 10, 100, and 1,000 are shown in Figures 16-28 through 16-32.
The authors recommend the following type-curve matching procedure, which is similar to the methodology used in applying Palacio and Blasingame’s type curve:
10−4 10−2 qDd, qDdi and qDdid
10−1
reD= 1000 Fractured Well a
bounded circular reservolr
reD= 2 qDdid
qDd qDdi
100 101 102
10−4 10−3 10−2
Fetkovich-McCray Type Curve for a Vertical Well with a Finite Conductivity Vertical Fracture (FcD= 0.1)
10−1 Model legend:
Legend: qDd ' qDdi,and qDdid versus tDb ' bar (qDd) Rate Curves
(qDdi) Rate Integral Curves
(qDdid) Rate Integral Curves Derivative Curves Fetkovich-McCray Type Curve-Fractured Well Centered In a Bounded Circular Reservoir (Finite Conductivity: FcD=0.1)
103 102
101 100
10−3 10−2 10−1 100
tDd, bar =NpDd /qDd
101 102 103
10−2 10−1 100 Depletion "Stems"
(Boundary-Dominated Flow Region-Volumetric Reservoir Behavior)
101 102
3
Transient "Stems"
(Transient Flow Region−
Analytical Solutions: FCD =1)
1040 20 50 30 100 400 300 300
200
Figure 16-28. Fetkovich-McCray decline type curve–rate versus material balance time format for a well with a finite conductivity vertical fracture (FcD=0.1). (Permission to copy by the SPE, 2003.)
Model legend: Fetkovich-McCray Type Curve-Fractured Well Centered in a Bounded Circular Reservoir (Finite Conductivity: FcD=1) qDb' qDb and qDb/id versus tDb'bar (qDb) Rate Curves a (qDb)/Rate Integral Curves
(qDb)/Rate Integral Curves Derivative Curves
Depletion "Stems"
(Boundary-Dominated Flow) Region-Volumetric Reservoir Behavior Transient "Stems"
(Transient Flow Region- Analytical Solutions: FeD=1)
qDb
qDb
F cD = 2
F cD = 1000 qDb/d
Fractured Well for a bounded circular
reservoir
Fetkovich-McCray Type Curve for a Vertical Well with a Finite Conductivity Vertical Fracture (FcD= 1)
10−4 10−3 10−2 10−1 100 101 102 103
10−2 10−1
400 100
300300 200 50 40 20 10
30 4
1 2 3
100 101 102
qDd, qDd/i ,and qDd/d
10−4 10−3 10−2 10−1 100 101 102 10310−2
10−1 100 101 102
tDd' bar =NpDd /qDd Legend:
Fetkovich-McCray Type Curve for a Vertical Well with a Finite Conductivity Vertical Fracture (FcD=10)
104 103 102
Transient "Stems"
(Transient Flow Region- Analytical Solutions: FcD = 10)
102
101
100
qDd, qDdi, and qDdid
tDd, bar = NpDd/qDd
Fractured Well in a Bounded Circular Reservoir
10−2 10−1
102
101
100
10−1
10−2
10−4 10−3 10−2 10−1 100 101 102 103
101 100 101
(qDdid) Rate Intergral-Derivative Curves Model legend:
Legend:
Fetkovich-McCray Type Cure-Fractured Well Centered in a Bounded Circular Reservoir (Finite Conductivity: Fc D = 10)
102
Depletion "Stems"
(Boundary-Dominated Flow Region−Volumetric Reservoir Behavior)
103
qDd' qDi and qDdid verus tDb,bar (qDd) Rate Curves (qDdi) Rate Intergral Curves
qDd
qDdi
qDdid reD =1000
reD=2
500
50
40 30
20 2 3
4 5 10
400 300 200 100
Figure 16-29. Fetkovich-McCray decline type curve–rate versus material balance time format for a well with a finite conductivity vertical fracture (FcD=1). (Permission to copy by the SPE, 2003.)
Figure 16-30. Fetkovich-McCray decline type curve–rate versus material balance time format for a well with a finite conductivity vertical fracture (FcD=10). (Permission to copy by the SPE, 2003.)
10−1
10−2 102
101
100
500
400 300
200 100
50 40
30 20 10
qDd, qDdi, and qDdid
10−4 10−3 10−2 10−1 100 101 102 103
tDd, bar=NpDd /qDd
10−1
10−2 102
101
100
Depletion "Stems"
(Boundary-Dominated Flow Region−Volumetric Reservoir Behavior) Model Legend: Fetkovich-McCray Type Curve-Fractured
Well Centered In a Bounded Circular Reservoir (Finite Conductivity: FcD=100)
Fractured Well in a Bounded Circular
Reservoir qDdid
reD =1000 qDd
qDdi
Transient "Stems"
(Transient Flow Region− Analytial Solution: FcD=100)
Legend: qDd' qDdi and qDdid versus tDd' bar (qDd) Rate Curves (qDdi) Rate Integral Curves (qDdid) Rate Integral-Derivative Curves
tcD= 2
Fetkovich-McCray Type Curve for a Vertical Well with a Finite Conductivity Vertical Fracture (FcD= 1000) 10−4 10−3
10−1
10−2
10−4 10−3 10−2 10−1 100 101 102 103
10−2 10−1 100 102
101
100
500 400
300 200 100
50 40 30 20
10 3
4 5
10−1
10−2 102
101
100
101 102 103
qDd, qDdi, and qDdid
tDd, bar=NpDd /qDd
Transient "Stems"
(Transient Flow Region−
Analytical Solution: FcD=1000)
Model Legend: Fetkovich-McCray Type Curve-Fractured Well Centered In a Bounded Circular Reservoir (Finite Conductivity: Fc D=1000)
Legend:qDd' qDdi and qDdid versus tDd' bar (qDd) Rate Curves (qDdi) Rate Integral Curves (qDdid) Rate Integral-Derivative Curves
qDd qDdi
Depletion "Stems"
(Boundary-Dominated Flow Region−Volumetric Reservoir Behavior)
Fractured Well in a Bounded Circular
Reservoir qDdid
reD =1000
tcD= 2
Figure 16-31. Fetkovich-McCray decline type curve–rate versus material balance time format for a well with a finite conductivity vertical fracture (FcD=100). (Permission to copy by the SPE, 2003.)
Figure 16-32. Fetkovich-McCray decline type curve–rate versus material balance time format for a well with a finite conductivity vertical fracture (FcD=1000). (Permis- sion to copy by the SPE, 2003.)
Step 1. Calculate the dimensionless fracture conductivity, FCD, and the fracture half-length, xf.
Step 2. Assemble the available well data in terms of bottom-hole pressure and the flow rate, qt(in STB/day for oil or Mscf/day for gas) as a function of time. Calculate the material balance pseudotime, ta, for each given data pointby using the following equations:
• For oil:
• For gas:
where m– (pi ) and m– (p) are the normalized pseudo-pressures, as defined by Equations 16-84 and 16-85:
Notice that the GOIP must be calculated iteratively, as illustrated previ- ously by Palacio and Blasingame (1993).
Step 3. Using the well-production data tabulated and plotted in Step 2, compute the following three complementary plotting functions:
• Pressure drop normalized rate, qDd
• Pressure drop normalized rate integral function, (qDd)i
• Pressure drop normalized rate integral–derivative function, (qDd)id For gas:
( )
( ) ( )
q t
q
m p m p dt
Dd i a
g
i wf
ta
= a
−
⎛
⎝⎜
⎞
∫ ⎠⎟
1
0
q q
m p m p
Dd
g
i wf
= ( )− ( )
m p Z
p
p Z dp
gi i
i g
P
( )= ⎡
⎣⎢
⎢
⎤
⎦⎥
∫ ⎥ μ
0 μ
m p Z
p
p Z dp
i
gi i
i g
Pi
( )= ⎡
⎣⎢
⎢
⎤
⎦⎥
∫ ⎥ μ
0 μ
t c
q
Z G
p m p m p
a
g g i t
i i
= ( ) i −
[ ( ) ( )]
μ 2
t N
a qP
t
=
• For oil:
Step 4. Plot the three gas or oil functions, qDd, (qDd)i, and (qDd)id, versus ta on a tracing paper so that it can be laid over the type curve with the appropriate value of FCD.
Step 5. Establish a match point for each of the three functions (qDd, (qDd)i, and (qDd)id). Once a match is obtained, record the time and rate match points as well as the dimensionless radius value, reD: a) Rate-axis match point Any (q/Δp)MP– (qDd)MPpair
b) Time-axis match point Any (t–
)MP– (tDd)MPpair c) Transient flow stem Select the (q/Δp), (q/Δp)i
and (q/Δp)idfunctions that best match the transient data stem and record reD.
Step 6. Solve for bDpssby using the values of FCDand reD: u =ln(FCD)
Step 7. Using the results of the match point, estimate the following reservoir properties:
b r
r
a a u a u a u a u
Dpss eD
eD
= − + + + + + +
ln( ) . . +
0 049298 0 43464
2 1
1 2 3
2 4
3 5
4
bb u1 + b u2 2 + b u3 3 + b u4 4 (q ) ( )
t d dt t
q
p p dt
Dd id
a a a
o
i wf
ta
= − a
−
⎛
⎝⎜
⎞
⎠⎟
⎡
⎣⎢ ⎤
⎦⎥
1 1 ∫
0
(q ) t
q
p p dt
Dd i a
o
i wf
ta
= a
−
⎛
⎝⎜
⎞
∫ ⎠⎟
1
0
q q
p p
Dd
o
i wf
= −
( ) ( )
( ) ( )
q t
d dt t
q
m p m p dt
Dd id
a a a
g
i wf
ta
= − a
−
⎛
⎝⎜
⎞
⎠⎟
⎡
⎣⎢
⎢
⎤
⎦⎥
∫ ⎥
1 1
0
• For gas:
• For oil:
where G =gas-in-place, Mscf N =oil-in-place, STB
Bgi=gas formation volume factor at pi, bbl/Mscf A=drainage area, ft2
re=drainage radius, ft Swi=connate-water saturation
Step 8. Calculate the fracture half-length, xf, and compare with Step 1:
x r
f r
e eD
=
r A
e = π
A N B
h S
oi wi
= −
5 615 1 .
( )
φ
k B
h
q p
q b
o
oi goi o MP
Dd MP
= ⎡ Dpss
⎣⎢ ⎤
⎦⎥ 141 2. ( / )
( )
μ Δ
N c
t t
q p
t q
a Dd mp
o i
Dd mp
= ⎡
⎣⎢ ⎤
⎦⎥ ⎡
⎣⎢ ⎤
⎦⎥
1 ( /Δ )
r A
e = π
A G B
h S
gi wi
= −
5 615 1 .
( )
φ
k B
h
q m p
q b
g
gi gi g MP
Dd MP
= ⎡ Dpss
⎣⎢
⎢
⎤
⎦⎥
⎥ 141 2. ( / ( )
( )
μ Δ
G c
t t
q m p
ti q
a Dd mp
g
Dd mp
= ⎡
⎣⎢ ⎤
⎦⎥ ⎡
⎣⎢
⎢
⎤
⎦⎥
⎥
1 ( /Δ ( )
Example 16-11
A Texas field vertical gas well has been hydraulically fractured and is undergoing depletion. A summary of the reservoir and fluid properties is as follows:
rw=0.333 ft h =170 ft φ =0.088 T=300oF γg=0.70
Bgi=0.5498 bbl/Mscf μgi=0.0361 cp
cti=5.1032 10−5psi−1 pi=9330 psia pwf=710 psia Swi=0.131 FCD=5.0
Fetkovich-McCray Type Curve for a Vertical Well with a Finite Conductivity Vertical Fracture (FcD = 5) [Example 1-Low Permeability/High Pressure Gas Reservoir (Texas)]
10−4 10−3 10−2 10−1
10−1
10−2
100
101 102
100
500 300 400200
100 30
40 50 20 10 2
3 4
5
10−1
10−2 101 102
100 101
Results Legend: Example Legend: Data Functions
Transient "Stems"
(Transient Flow Region−
Analytical Solution: FcD=5)
Depletion "Stems"
(Boundary-Dominated Flow Region−Volumetric Reservoir Behavior)
Model Legend: Fetkovich-McCray Type Curve-Fractured Well Centered In a Bounded Circular Reservoir (Finite Conductivity: FcD=5)
102 103
10−4 10−3
Fractured Well in a Bounded Circular Reservoir
10−2 10−1
Material Balance Pseudotime Function, days [G=1.0 BSCF (forced)]
100 101 102 103
qDd, qDdi, and qDdid
(qDg/,\Pp) Data (qDg/,\Pg) Data (qDg/,\Pp)id Data
qDd
qDdi
qDdid
fcD= 2
reD =1000
Figure 16-33. Match of production data for Example 1 on the Fetkovich-McCray decline type curve (pseudo-pressure drop normalized rate versus material balance time format) for a well with a finite conductivity vertical fracture (FcD=5). (Permission to copy the SPE, 2003.)
Figure 16-33 shows the type-curve match for FCD=5, with the matching points:
(qDd)mp=1.0 [(qg/Δm(p–
)]mp=0.89 Mscf/psi (tDd)mp=1.0
(ta)mp=58 days (reD)mp=2.0
Perform type-curve analysis on this gas well.
Solution
Step 1. Solve for bDpssby using the values of FCDand reD:
Step 2. Using the results of the match point, estimate the following reservoir properties:
k B
h
q m p
q b
g
gi gi g MP
Dd MP
= ⎡ Dpss
⎣⎢
⎢
⎤
⎦⎥
⎥ 141 2. ( / ( )
( )
μ Δ
G MMscf
= mp
×
⎡
⎣⎢
⎤
⎦⎥
⎡
⎣⎢
⎤
⎦⎥= ×
−
1 5 1032 10
58 1 0
0 89
1 1 012 10
5
6
. .
.
. .
G c
t t
q m p
ti q
a Dd mp
g
Dd mp
= ⎡
⎣⎢ ⎤
⎦⎥ ⎡
⎣⎢
⎢
⎤
⎦⎥
⎥
1 ( /Δ ( )
b a a u a u a u a u
Dpss = − + + +b u + + +
+ +
ln( ) . .
2 0 049298 0 43464
22 1
1 2 3
2 4
3 5
4
1 bb u2 b u b u
2 3
3 4
4 1 0022
+ + = .
b r
r
a a u a u a u a u
Dpss eD
eD
= − + + + + + +
ln( ) . . +
0 049298 0 43464
2 1
1 2 3
2 4
3 5
4
bb u1 + b u2 2 + b u3 3 + b u4 4 u =ln(FCD)=ln( ) .5 1 60944
Step 3. Calculate the fracture half-length, xf, and compare with Step 1:
PROBLEMS
1. A gas well has the following production history:
Date Time, months qt, MMscf/month
1/1/2000 0 1017
2/1/2000 1 978
3/1/2000 2 941
4/1/2000 3 905
5/1/2000 4 874
6/1/2000 5 839
7/1/2000 6 809
8/1/2000 7 778
9/1/2000 8 747
10/1/2000 9 722
11/1/2000 10 691
12/1/2000 11 667
1/1/2001 12 641
x r
r ft
f e eD
= =277= 2 138
r A
e = = = ft
π π
2401195 277
A= × ft
− =
5 615 1 012 10 0 5498
170 0 088 1 0 131 240 195
6
. ( . )( . ) 2
( )( . )( . ) , ==5 51. †acres
A G B
h S
gi wi
= −
5 615 1 .
( )
φ
kg = ⎡ md
⎣⎢
⎤
⎦⎥ =
141 2 0 5498 0 0361 170
0 89
1 0 1 00222 0 015 . ( . )( . ) .
. . . †
a) Use the first six months of the production history data to determine the coefficient of the decline-curve equation.
b) Predict flow rates and cumulative gas production from August 1, 2000 through January 1, 2001.
c) Assuming that the economic limit is 20 MMscf/month, estimate the time to reach the economic limit and the corresponding cumulative gas production.
2. The volumetric calculations on a gas well show that the ultimate recoverable reserves, Gpa, are 18 MMMscf of gas. By analogy with other wells in the area, the following data are assigned to the well:
• Exponential decline
• Allowable (restricted) production rate =425 MMscf/month
• Economic limit =20 MMscf/month
• Nominal decline rate =0.034 month−1
Calculate the yearly production performance of the well.
3. The following data are available on a gas well’s production:
pi=4100 psia ϕ =0.10 pwf=400 psi Swi=0.30
T=600°R γg=0.65
h =40 ft
Calculate the GOIP and the drainage area.
Time, days qt, MMscf/day
0.7874 5.146
6.324 2.108
12.71 1.6306
25.358 1.2958
50.778 1.054
101.556 0.8742
248 0.6634
496 0.49042
992 0.30566
1240 0.24924
1860 0.15996
3100 0.07874
6200 0.02232
REFERENCES
1. Agarwal, R. G., Gardner, D. C., Kleinsteiber, S. W., and Fussell, D. D.,
“Analyzing Well Production Data Using Combined Type Curve and Decline Curve Analysis Concepts,” SPE 49222, SPE Annual Technical Conference and Exhibition, New Orleans, LA, September 1998.
2. Agarwal, R. G., Al-Hussainy, R., and Ramey, H. J. (1970). An Investiga- tion of Wellbore Storage and Skin Effect t in Unsteady Liquid Flow. SPE J.September 1970, pp. 279–290.
3. Anash, J., Blasingame, T. A., and Knowles, R. S., “A Semi-Analytic (p/z) Rate–Time Relation for the Analysis and Prediction of Gas Well Perfor- mance” (see reference 3), SPE Reservoir Eval. & Eng.3(6), December 2000.
4. Anash, J., Blasingame, T. A., and Knowles, R. S., “A Semi-Analytic (p/z) Rate–Time Relation for the Analysis and Prediction of Gas Well Perfor- mance,” SPE 35268, SPE Mid-Continent Gas Symposium, Amarillo, TX, April 1996.
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A fundamental property of a reservoir rock is porosity. However, to be an effective reservoir rock, another fundamental property is permeability.
Both porosity and permeability are geometric properties of a rock, and both are the result of the rock’s lithologic (composition) character. The physical composition and textural properties (geometric properties such as the sizes and shapes of the constituent grains, the process of their packing) of a rock are what is important when discussing reservoir rocks, and not so much the age of the rock. In an excellent paper by Shanley et al. (2004), the authors presented a comprehensive overview of low- permeability gas reservoirs and the underlying petrophysical concepts, and offered additional insights based on their research work. They reiter- ated the well-known fact that in low-permeability reservoirs, the impact of partial brine saturation and overburden stress on reservoir performance is significant. In low-permeability gas reservoirs, it is not unusual for the effective permeability to gas to be one to three orders of magnitude less than routine permeability. Similarly, effective permeability to brine is such that for many low-permeability reservoirs, water is essentially immobile even at high water saturations. The relative permeability behavior of tight gas reservoirs is characterized by redefining the traditional concepts of critical water saturation Swc (the water saturation at which water ceases to flow), critical gas saturation Sgc(the gas saturation at which gas begins to flow), and irreducible water saturation Swirr (the water saturation at which a further increase in capillary pressure produces no additional decrease in water saturation). Figure 17-1 is a schematic illustration of the
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