American Oil and Gas Reporter - September 2017 - 76

SpecialReport: Horizontal Wellbore Construction
well to determine these parameters and
use for comparative analysis.
Post-treatment simulation was performed on the well with commercial fracture simulation software. The objective
was to calibrate the rock properties by
history matching the model's treatment
pressure profile to the actual treatment
pressure. Following history matching, the
calibrated model was used to simulate
different pounds per foot of proppant.
During the analysis, all other completion
variables were held constant (number of
clusters per stage, number of perforations
per stage, entry hole diameter, stage spacing, stage depth, proppant size and more).
The fracture treatment schedule was adjusted to run various proppant concentration
scenarios from 1,000 to 4,000 pounds/foot.
The fracture geometry obtained from the
model then was synchronized with the
RTA results to ensure the estimates of
the fracture properties were reasonable.
Afterward, the capital expenditure associated for each proppant/foot design
was obtained to run economic analysis
on various designs. Next, hybrid, numerical
and analytical models were used to obtain
a forecast for each scenario based on
varying half-lengths assuming infinite
fracture conductivity. Finally, economic
analysis was performed to find the optimum economical well spacing for the
area at various natural gas pricing levels.
Table 1 shows the well's detailed completion design, which was unique because
of the large percentage of high-strength

ceramic proppant pumped on this well
because of high closure pressure. The
first step in RTA analysis is calculating
sand face or flowing bottom-hole pressure.
The next step is to identify the flow
regime associated with the well using
various diagnostic plots. At the time of
the study, it appeared that the well either
had reached a transitional period or boundary-dominated flow.
The next step in the workflow was obtaining basic completion and reservoir
properties to perform history matching.
A gas hybrid model was used to history
match synthetic pressure to the calculated
flowing BHP. An assumed pressure-dependent permeability of 2E-4 1/psi was
used for the analysis. Figure 3 shows
synthetic pressure (dark brown line), flowing bottom hole pressure (light brown
line), reservoir pressure (blue line), and
gas rate (red line) from history matching.
Hybrid Model

A hybrid model is basically a numerical
model with some modifications to reduce
computation time, making it almost as
fast as an analytical model. The main
modifications between numerical and hybrid models are using pseudo-pressure
formulation and accounting for a single
phase (gas). The hybrid model generated
a base forecast by varying half-length
based on the several assumed parameters.
They included:
* An initial reservoir pressure of
11,655 psi;

FIGURE 2

* 132 feet of pay zone thickness;
* A 7,000-foot lateral length;
* 200-foot stage spacing;
* 105 fracture clusters (60 percent
cluster efficiency);
* FCD of 142;
* Permeability of 198 nanodarcies;
* 7 percent porosity; and
* 12 percent water saturation.
The completions design on the study
well utilized 2,500 pounds/foot of proppant, yielding a 550-foot fracture halflength from the fracture simulator, PTA
and RTA analyses. The remaining scenarios with the same treatment design as
the base case with respect to sand size,
type and percentage, were generated based
on various potential proppant/foot designs
considered operationally feasible (recognizing potential risks associated with
screening out at higher proppant concentration designs of 3,500 and 4,000
pounds/foot since these designs had not
been tested in the database).
Table 2 shows the resulting half-lengths
from the fracture simulations as well as
the total capital expenditure associated
with each of the seven modeled scenarios.
Note that the capital expenditures are subject to change according to commodity
pricing and market fluctuations.
The next steps in the workflow were
determining the drainage area with a limited number of wells based on each scenario, and forecasting a 30-year basecase estimated ultimate recovery for each
scenario. The analysis used a constant
drainage area of 1,029 acres for an average
TABLE 1

Flow-After-Flow Test Results

Completion Design
100

9,900
9,800

80

60

9,600
9,500

40

9,400
9,300

20

9,200
0

50

100

150

200

250

300
350
Time (hours)

76 THE AMERICAN OIL & GAS REPORTER

400

450

500

550

600

0

Gas Flow Rate (MMcf/d)

Pressure (psia)

9,700

Metric

Westmoreland
Co. Well

Unit
ft

PTP LL

5,840

Stage spacing

200

ft

Water/ft

56

bbl/ft

Proppant/ft

2,551

lb/ft

% 100 mesh

31

%

% 40/80 ceramic prop

40

%

% 30/50 ceramic prop

19

%

% 30/60 HSP

9.34

%

Entrance hole diameter

0.42

in.

Shots/stage

40

shots/stage

Cluster spacing

40

ft



American Oil and Gas Reporter - September 2017

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