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Click here to download the Meyer 2008
User’s Guide appendices, including more information about Net Present Value
theory
Normally, economic analysis, as it pertains to hydraulic fracture
design, involves comparing the cost of treatments with their expected
revenues to maximize the potential return on investment. This typically
includes several steps. First, production potential is evaluated as a
function of fracture penetration and conductivity. These fracture
characteristics have a dramatic impact on the cash flow income of a well.
After generating the relationships between production and fracture
characteristics, the next step is to consider the costs associated with
each of the fracture geometries under evaluation. The final step is to
combine the productivity data with the cost information to determine the
maximum economic return. This basic methodology is consistent with the
approach used in MFrac, MProd and MNpv.
Prior to performing a productivity analysis, it is necessary to have an
idea of plausible fracture designs (or geometries) to explore. Since
reservoir properties usually control fracture geometry, it makes sense to
use a fracturing simulator to develop a set of characteristics for the
model to evaluate. MFrac provides a convenient manner to obtain this data
by generating automatic designs. When the NPV option is on in MFrac, a
maximum fracture length and proppant concentration are specified. Pumping
schedules, as well as fracture geometry and proppant transport solutions
are automatically created for ten subdivisions of this length. The
information created from this procedure can then be imported directly into
MProd to perform a group of production simulations.
Although it is convenient to use MFrac to determine the fracture
characteristics and treatment parameters for evaluation in MProd, fracture
length, conductivity and material quantity information can be directly
input in MProd to perform a production or economic analysis.
With fracture data entered in MProd and all of the remaining reservoir
parameters described, production simulations can be performed to predict
the relationship between cumulative production, fracture contact area
(e.g., frac length) and fracture deliverability (e.g., conductivity). These
results will normally show that for reasonable conductivity, the greater
the fracture length, the more substantial the productivity improvement. To
determine whether or not the benefit of creating additional reservoir
contact area is worth the cost, the economic value of each treatment must
be considered.
The economic value of a stimulation treatment is typically assessed by
using one of three methods. The first of these methods is predicting the
time it takes for the cumulative post-frac revenue to reach the level of
the initial investment. This is the time required to pay for the treatment
with revenues from the well. This criterion is usually referred to as
“payout.” Particularly for low permeability wells, where investments are
large and payout time is long, this method does not take into account the
time value of money (e.g., Currency Escalation Rate or achievable interest
rate) and can, therefore, lead to false conclusions. Even if the value of
money remained constant over the producing time of a well, the payout or
net revenue of each treatment design under consideration would not always
be an acceptable method to determine an optimum design. For example,
comparing a smaller treatment and associated fracture penetration with a
larger job may show that the smaller treatment pays out sooner because of
early time production effects. Evaluating the long-term production decline
of the two scenarios, however, may reveal that the larger treatment and
contact area, once it achieves stabilized flow, declines less rapidly and,
therefore, results in a higher ultimate recovery.
To include the time value of money in the economic evaluation of
fracture treatments, the preferred methods of either Net Present Value
(NPV) or Discounted Return On Investment (DROI) are used. The primary
difference between the two approaches is that DROI is sensitive to the rate
of change in NPV and, therefore, can be thought of as an indicator of
capital efficiency. In other words, the incremental DROI decreases when the
cost associated with an increase in production increases at a greater rate
than the NPV. When capital is strictly limited, DROI indicates the more
conservative optimization criteria. A decreasing DROI suggests that your
limited capital may receive a higher rate of return if invested in another
manner (i.e., one with a higher DROI).
 The Discounted Return
on Investment (DROI) takes into account the time value of money invested
and can be used as a indicator of the capital investment efficiency. The
DROI is simply the ratio of the Discounted Well Revenue divided by the
total cost of a treatment. For a fracture design this is:
DROI = DWR / CF
The decision on which optimization criteria to use rests with your
company’s business philosophy and financial position. DROI is the approach
used by many operators to evaluate new prospects. Typically, this involves
considering the total cost of drilling and completing a well. When
estimating the value of a hydraulic fracture treatment you can identify a
design which may result in the highest NPV; however, this does not mean
that you have identified a design which makes the most financial sense
relative to other investments. For that we recommend the use of DROI with
“realistic” estimates of the future hydrocarbon revenue per unit volume and
currency escalation trends.
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