American Oil and Gas Reporter - September 2016 - 51

SpecialReport: Reservoir Optimization & Modeling

Study Optimizes Niobrara Development
By Ningning Li,
Mike Mayerhofer,
Art Childers,
Robert Weitzel,
Richard White,
Ely Lolon
and Howard Melcher
DENVER-Black Hills Exploration &
Production has adopted an iterative
approach to optimizing drilling and
completion in the Niobrara formation in
Colorado's Piceance Basin. The key
objectives include identifying the most
favorable target in the 1,200-foot thick
formation to land horizontal wells, determining the proper orientation of horizontal wellbores within the target zone,
and designing an effective completion
program to optimize fracture geometries
and conductivities, given the Niobrara's
massive thickness and complex rock properties.
Black Hills initially tested the Niobrara
on its Piceance Basin leasehold by pumping multistage completions in two existing
vertical wells. The first vertical test well
had six frac stages and produced dry gas
consisting of 90 percent methane and 10
percent ethane.
The production and logging information
from that first vertical test were used to
select landing points for two short (4,300foot lateral) horizontals for additional
testing: one located on the eastern edge
of Black Hills' acreage targeting a lowstress and very "fracturable" zone ±500
feet from the top of the Niobrara at a
total vertical depth of 7,540 feet, and the
other in the southwestern area of the
acreage targeting the same zone at 6,330
feet TVD.
Both wells were easy to fracture with
no screen-outs or injectivity challenges,
and produced dry gas of similar composition to the first vertical test well. They
averaged 9,300 barrels of slickwater and
175,000 pounds of proppant per stage at
a 70 barrel a minute pump rate and a
maximum proppant concentration of 1.0
pounds added per gallon (ppa).
The second vertical test well is located
updip from the first vertical well and targeted the same intervals, although it had
a shallower TVD and lower thermal maturity. The three-stage completion produced oil and rich gas composed of 80
percent methane along with ethane,

propane and butane. The oil production
was unexpected, and production logs
were run in the well after completing the
two short horizontal wells.
To improve the chance of producing
oil based on the results of the second
vertical well, Black Hills changed the
landing points of future wells to a lower
thermal maturity area (as indicated by
vitrinite reflectance data from cutting
samples) within the Rangely Bench.
Located ±900 feet from the top of the
Niobrara, the Rangely is the upper part
of the lowermost Niobrara bench. The
highly laminated Rangely consists of calcareous shales with increasing quartz
content moving upward through the zone.
It overlies organic-rich marls that are
some of the richest source rocks in the
Piceance Basin.
Two long (8,000-foot lateral) horizontals were landed in the Rangely and
drilled parallel to each other from the
same pad at TVDs of 5,940 feet and
6,140 feet, respectively, with approximately 5,800 feet of horizontal separation.
As with the two short horizontal wells,
the completions on these wells were
pumped to design without any challenges.
The first long horizontal was completed
with 2.02 million pounds of 100-mesh,
4.78 million pounds of 40/70-mesh, and
2.76 million pounds of 30/50-mesh white
sand, and 477,750 barrels of slickwater
at a maximum proppant concentration of
1.0 ppa. The second long horizontal was
completed with 1.99 million pounds of
100-mesh and 7.55 million pounds of
30/50-mesh sand, and 537,917 barrels of
slickwater with a maximum proppant
concentration of 1.0 ppa.
Six-Well Integrated Study
Production from both the long and

short horizontal wells encouraged the operator to turn the Niobrara into a horizontal
resource play. To optimize its development
program, Black Hills decided to conduct
an integrated study of six new horizontal
wells on two pads, all with 8,000- to
10,000-foot laterals targeting the Rangely
Bench.
A hydraulic fracture model was built
to estimate fracture geometry and conductivity in the six new long-lateral wells.
The first step was constructing a mechanical earth model (MEM) using all
available data.
Overburden was calculated by integrating formation density data to surface.
The maximum horizontal stress azimuth
was calculated from a combination of
image logs and dipole-sonic data. Minimum (σ2) and maximum (σ3) horizontal
stress magnitudes were estimated from
wireline data and calibrated using data
from drilling, wireline logging, smallvolume fracture initiation and fall-off
tests, and completion operations.
The MEM indicated a preferred fracture
orientation in the northeast direction, and
a lack of "barriers" to hydraulic fracture
height growth. Borehole images showed
two discrete fracture sets: occasional clusters of open natural fractures about 15
degrees incident to the σ3 direction that
tended to be small and contained to
specific lithologic units, and a second set
of ancient mineralized fractures nearly
perpendicular to the open natural fractures
(Figure 1).
With maximum horizontal stress estimated to be 350 psi higher than minimum
horizontal stress, the natural fractures
were expected to add complexity during
completion operations, while the mineralized set was expected to remain closed.
The six wells were drilled in the south-

FIGURE 1
Rose Strike Plots of Drilling-Induced,
Natural Open and Mineralized Fractures

SEPTEMBER 2016 51



Table of Contents for the Digital Edition of American Oil and Gas Reporter - September 2016

Contents
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American Oil and Gas Reporter - September 2016 - Cover2
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