Integrated 3D Reservoir Model of the Devonian Bakken Formation,
Williston Basin: Elm Coulee Field, Richland, Montana
Adrian Almanza
Department of Geology & Geological Engineering
Abstract
The Bakken Formation of Williston Basin is a world-class oil resource play named the largest
continuous oil in the lower 48 states by the United States Geological Survey (USGS) in 2008.
The Bakken Formation is quite extensive, but does not have uniform properties throughout
its aerial extent. Identifying “sweet spot” areas with favorable porosity, permeability, and
fractures, are essential to commercial petroleum recovery. The Elm Coulee Field is a giant
oil field in Eastern Montana that exhibits some of these critical reservoir properties.
Modeling of these reservoir properties will provide a greater understanding to aid in
exploration and development of the Bakken Formation.
The Bakken Formation in the Elm Coulee Field consists of three members: an upper shale, a
middle silty dolostone, and a lower shale. The Elm Coulee Oil Field is a stratigraphic trap
with a pinch out in the southwest and a digenetic facies change in the northeast. The
primary reservoir is the silty dolostone of the Middle Bakken Member.
The purpose of this research is twofold: (1) to complete an examination of the reservoir
properties of the Bakken petroleum system in Elm Coulee Field and (2) to construct a three
dimensional geologic model that will show the distribution of the different facies within the
Bakken Formation and their associated reservoir properties. This study uses digital logs,
core data, thin sections, XRD analysis, DSTs, production data and Petrel to characterize the
Elm Coulee Field. Four cores are used to calibrate physical properties to digital well logs,
and are used in conjunction with core descriptions to construct detailed facies maps. XRD,
Qemscan and thin sections are used to determine mineral effects on logs and pore throat
geometries.
Elm Coulee is a low porosity, low permeability oil field. The primary recoveries are only 510%, which indicate that the field is a prime candidate for secondary recovery. Since a
water injection approach is not ideal due to the poor quality of the reservoir, a carbon
dioxide (CO2) flood method may be preferred. This study’s second and primary focus is to
build a reservoir model with core calibrated data. A collaborative effort to bring this study
to reservoir simulation is the final phase of this study in which the reservoir model will be
used to test against production data.
This study’s will build two geomodels: case A and case B. Case A, which will be used in a
production history match scenario, is a two phase system that utilizes water and oil in the
simulation. Case B, which will be used in a secondary recovery scenario, is a three-phase
system oil, water and gas (CO2). The results of this study aim to guide the future of
secondary development in low porosity, low permeably reservoirs of the Williston Basin.
Current research has used DSTs to identify multiple permeability build up curves that may
be associated with different types of reservoirs. The fast initial build up curves such as the
Parsons and Sorenson wells are associated matrix dominated reservoir and slow initial build
up with a quick final build to steady state conditions indicate that there reservoir may be
fracture dominated (ie. Bahl 12-1). The two reservoir types seen in DSTs have given us an
indication that there may be sweet spots in Elm Coulee Field. These sweet spots would
coincide with an optimal intersection of fracture and matrix dominated reservoirs.
Figure 1. Elm Coulee DST Horner Plots
The next step was to identify areas that had matrix and fracture porosity. First to identify
matrix porosity, neutron and density logs were averaged to formulate an average porosity,
this result showed a good correlation to the measured core porosity. Logs were then
averaged across the field in the Middle Bakken Reservoir zone to create a matrix porosity
map.
Figure 2. Average porosity Middle Bakken reservoir facies
The second step to identifying sweet spots was to locate the potential fracture porosity
trends in the study area. Production data was utilized to achieve this objective. By using the
fist year initial cumulative rates, it was possible to identify areas in the field that showed an
anomalous high rate in initial production. These areas are believed to have an increased
contribution to production due to fracture porosity.
Figure 3. First year initial production
The regional fracture pattern seen throughout the Williston basin trends northeastsouthwest, this concept was applied to the mapping program and to the initial production
map to simulate a more natural fracture orientation.
Figure 4. First year initial production with regional trend
The final step to the sweet spot identification was to plot total cumulative production with
both the matrix porosity and potential fracture porosity trends; the results show that the
best production tend to align with the intersection of fracture trends and high matrix
porosity. These results are being built into a petrel project creating a 3D geologic model that
anticipates on capturing a more correct reservoir characterization of the Elm Coulee filed
Figure 5. Total cumulative production with fracture trends and matrix porosity