Page 78 - A Practical Companion to Reservoir Stimulation

PRACTICAL COMPANION TO RESERVOIR STIMULATION

EXAMPLE E-12
Often, fracture treatment evaluation is based on the well
Permeability and Optimum Fracture Half-Length
posttreatment performance. However, the production rate
must be compared with what an optimum treatment should
Using the data in Table E-6 for an oil well, graph the optimum deliver for that particular reservoir. Thus, “folds” of increase
fracture half-length vs. reservoir permeability. The perme- is not a meaningful comparison for similar treatments but for
ability values are k = 0.01, 0.1 and 1 md. What are the FcD, similar treatments in reservoirs of equal permeability.
1-yr NPV and production rate (for a year) at the optimum Figures E-10 and E-11 are intended to drive the point
lengths? home. The first is a graph of the 1-yr NPV for the optimum
Solution (Ref. Sections 8-3 and 8-4) fracture half-lengths for the three permeabilities. The 1 -yr
A parametric study was done using the NPV concept for NPVs are $2 10,000, $520,000 and $850,000, respectively.
The@ figures would favor further the higher permeability
fracture design. This is an interesting study because it touches reservoirs if better proppants and fluids were used. Thus, it
on routine issues affecting fracture treatments. Important should be remembered always that while hydraulic fractur-
operational variables here are the injection rate (2QBPM) and ing caiz improve well performance significantly, it cannot
the retained proppant-pack permeability (30% after stress supplant nature. Reservoir permeability remains a significant
effects are accounted for; damage is caused by polymer variable for well production.
residue). Figure E-8 is a graph of the optimum fracture half- This is illustrated further in Fig. E- 1 1. Here, the production
length vs. reservoir permeability. If the reservoir permea- rate for the three permeabilities is plotted vs. time for the first
bility is 0.01 md, then the optimum fracture half-length is year. As can be seen easily, the 1-md permeability reservoir
1400 ft. If the permeability is larger, 0.1 and 1 md, then the consistently outperforms the lower permeability reservoirs in
optimum fracture half-length decreases to 1300 ft and 900 ft, spite of the fact that the latter would require significantly
respectively. larger treatments. Furthermore, this plot illustrates the error in
This is well known in hydraulic fracture design; the tighter
the reservoir, the longer the fracture should be. using the posttreatment rate as the sole measure of success for
the fracture treatment (often without the knowledge of the
There are additional findings that are significant. Fig. E-9 reservoir permeability).
is a graph of the dimensionless fracture conductivity vs. The expected performance of a 100-ft fracture half-length
permeability at the optimum fracture half-length. The dimen- in the 1-md reservoir is plotted as a dashed line. It is obvious
sionless conductivity ranges from 14 for the 0.01-md per- again that a far less than optimum treatment in a higher
meability to 1.5 for the 0.1 -md permeability and 0.2 for the permeability reservoir can easily outperform an optimum job
I-md permeability. This is a major conclusion. While a
conductivity equal to 14 is quite good (and its increase may not in a lower permeability reservoir. This should be expected.
However, it should be noted that in one year, an optimum job
result in appreciable well performance improvement), a con- in the 1 -md reservoir would produce more than 100,000 STB,
ductivity equal to 0.2 could be improved considerably. Thus, whereas the smaller job would produce only 80,000 STB.
while in very tight reservoirs the proppant type and especially Thus, this last comparison shows the necessity to optimize the
the residual damage of the fracturing fluid should receive treatments. Furthermore, intelligent posttreatment evaluation
cursory attention; in the case of higher permeability reservoirs, requires the knowledge of an important reservoir variable
they become critical. It is very important to use higher perme- such as the permeability.
ability proppants and to employ the best, least damaging
fracturing fluids in high-permeability reservoirs.

E-18