2016 Spring Workshop
Petrophysics of the Spraberry-Wolfcamp play in the
The Denver Well Logging Society invites you to attend our
2016 Spring workshop being held Thursday, April 21st, 2016 at the Colorado School of Mines.
Note the registration deadline has
been extended until Thursday, April 7th.
In continuation of the DWLS' workshop tradition, this
workshop, Petrophysics of the Spraberry-Wolfcamp play in
the Midland basin, will
be held from 7:30 am to 5:00 pm on Thursday, April 21st
at the Colorado School of Mines.
Join us for an all-day workshop focusing on new the Spraberry-Wolfcamp
play in the Midland basin.
Thursday, April 21st, 2016
7:30 AM - 5 PM
Student Center (1600 Maple St)
Colorado School of Mines
Reservations for non-DWLS members is $225, and can be made by clicking here:
DWLS members in good standing as of
and students are eligible for a discount -
you should have
received a special email or flyer with this discount
information. If you are unemployed, you
may contact us about a discounted rate.
To pay by check contact Lisa Gregor at
or call 303-770-4235.
Payment must be received no later than Thursday, March 31st 2016; after
that date, we will release your space reservation. Reservations
must be made in advance, walk-ins will not
If paying by check, make it out to the DWLS, and mail it to
(checks must be received by March 31st):
Digital Formation, Inc.
Attn: DWLS Spring Workshop
999 18th Street, Suite 2410
Denver, CO 80202
Cancellations with a full refund can be made up until the
March 31st deadline by contacting Lisa. After
that date, no refunds will be made, however, you may send
someone else as your replacement (please notify us beforehand).
Early Permian basinal mudrocks in the Southern Midland basin – foundation for the Wolfberry Play
Robert W. Baumgardner, Texas Bureau of Economic Geology
The Wolfberry play combines favorable geology with innovative
completion practices to form one of the largest unconventional
oil plays in the United States. Abundant organic carbon, brittle
calcareous mudrock, and thin permeable beds form the geologic
basis for the play. The Wolfberry concept grew out of
preexisting plays in low-permeability sandstones (Spraberry
Formation) and detrital carbonates (Wolfcamp interval) and
developed in the early 2000’s through the application of modern
hydraulic-fracture stimulation technology and refinement of
geologic understanding of the reservoir-source-rock system.
Lower Permian (Wolfcampian and Leonardian) stratigraphy in
the Midland Basin records deposition in an intracratonic,
deep-water basin surrounded by shallow-water carbonate
platforms. On the basin floor turbidite/debrite depositional
systems alternate with hemipelagic depositional systems in
laterally persistent layers. Along the platform margins, slope
depositional systems comprise carbonate-dominated clinoforms. By
flooding or exposing the wide flanking platforms, sea-level
fluctuation controlled sediment input into the basin. During
inferred sea-level lowstands, platforms were exposed, and
siliciclastic sediment was transported directly into the basin.
During sea-level highstands, flooded platforms became carbonate
factories and sediment input to the basin shifted toward
platform-derived carbonate. Hemipelagic sediment was deposited
throughout the sea-level cycle, contributing organic matter as
well as silt- and clay-sized siliciclastics and bioclasts.
Siliciclastic intervals include the lower Wolfcamp interval,
the Dean Formation, and the lower and upper intervals of the
Spraberry Formation. These inferred lowstand intervals comprise
submarine fans that extend over 150 mi north-south and cover the
basin floor. Spraberry and Dean sandstone turbidites are
composed of sediment derived from source areas in the north.
Hence, permeable sandstones thin southward, grading into
low-permeability turbidite lobes and sheets. The lower Wolfcamp
interval thins north and west away from source areas to the
south and east.
Calcareous intervals include the upper Wolfcamp interval,
lower and middle Leonard intervals, and middle interval of the
Spraberry Formation. These inferred highstand intervals are
composed of hemipelagic deposits (siliceous and calcareous
mudrocks) and detrital carbonate mass-flow deposits. Basinal
calcareous intervals are typically thicker, coarser grained, and
more permeable near the platforms that supplied the carbonate
detritus. In basin-center areas calcareous intervals are mudrock
dominated but include numerous thin, permeable interbeds.
Wolfberry basinal deposits are oil rich, but most lithofacies
are relatively impermeable. Mudrocks are organic rich (up to
6.8% TOC), thermally mature (%Roe=0.7-1.1), and oil prone.
Sandstones and carbonates are mostly thin and of poor reservoir
quality. The Wolfberry reservoir-source-rock system, however, is
more than 2,000 feet thick, and by means of massive,
multi-stage, hydraulic-fracture stimulation treatments, large
volumes of marginal reservoirs are accessed and produced.
Wolfcamp Midland: can the trajectory continue?
Reed Olmstead, IHS Energy
The Midland Basin Wolfcamp continues to attract investment
and interest despite market conditions. The play has seen
activity from 225 operators, though less than 60 are currently
active. With attractive economics, a large inventory of
drilling possibilities, and a growing production base, the
Wolfcamp Midland is poised to be a strong contributor to
domestic supply. In this presentation, we will discuss the
operators currently active in the play, recent operational and
development trends, and our production outlook.
Petrophysical analysis of the Wolfcamp Shale Interval
Michael Holmes (Digital Formation)
A petrophysical model is presented that quantifies “free
shale porosity” defined as porosity separate from total organic
carbon porosity, and containing mobile hydrocarbons.
Volumes of likely net accessible hydrocarbons within the small
volumes of free shale porosity can be quantified. Examples
are presented showing the varying development of free shale
porosity from well to well, and within the different
stratigraphic layers of the Wolfcamp shales.
Comprehensive Integrated Petrophysical Analysis That Enhances Performance of a Wolfberry Play
Tim McGinley (Laredo Petroleum)
Optimal petrophysical evaluations of shale plays require
advanced logging programs with appropriate core studies.
3D seismic, micro-seismic, DFIT, and frac job analysis provide
additional insight into what impacts reservoir performance. A
probabilistic evaluation model, tied to extensive core analysis,
identifies critical rock properties that will optimize
production. Dipole Sonic mechanical properties computations,
with frac job response integration, provide quality stress
gradient and brittleness estimates. Image logs identify many
geologic features and promote high quality depth control of core
samples. With this technology added to the tool box,
comprehensive analyses are utilized to create a strong
Organic Mudstone Petrophysics: A Novel
Workflow To Estimate Storage Capacity
Kent Newsham (Oxy)
The emergence of shale and oil plays in North America has
caused the industry to re-examine the methods which we use to
quantify the resource and recoverable reserves in place.
We recognize that unconventional gas and oil reservoirs are
geologically and petrophysically heterogeneous at a variety of
scales. Organic mudstone systems exhibit storage and flow
characteristics which are uniquely tied to nano-scale pore
throat and pore size distribution and possess common organic and
clay content. Appraisal of these system is also challenged
by the complex fluid compositions and distribution.
We present a novel workflow and methods for systematically
modeling reservoirs with complex mineral and fluid composition.
One of the primary objectives is for consistent and improved
accuracy of reservoir storage capacity estimates. The workflow
provides direct core to log calibration of static properties
throughout the workflow. It also allows for calibration to
dynamic properties such as pore pressure and fluid phase
properties via PVT tests using industry standard correlations
such as Standing and Vasquez and Beggs.
The log calibration process utilized is a “hybrid”
simultaneous inversion approach in which direct measurements of
total clay content, total organic carbon (TOC) and pyrite from
core or cuttings are used as inputs to constrain the inversion
process. Other inputs are conventional log data, whose
response is affected by the presence of fluids (hydrocarbons and
water) and various minerals, and organic material. Results
from the inversion calculations, including volumes of other rock
constituents, are compared against physical measurements from
core and/or cuttings. Numerous examples will be presented.
Core-Log Integration Techniques for the Development of a Petrophysical Model for the Wolfcamp, Midland Basin
Randy Miller (Core Laboratories)
The Wolfcamp section in the Midland Basin is a major target
for oil production from horizontal wells. The prospective
section is over 1000 feet thick and is typically subdivided into
four intervals designated as the A, B, C and D, all of which
have been the target of horizontals. The Wolfcamp is
stratigraphically very heterogeneous being comprised of organic
mudstones thinly to thickly interbedded with tight carbonate
debrites and turbidites, and in some cases siliciclastics. Core
analysis data reveal that the majority of the liquid
hydrocarbons reside in the organic mudstones (source rocks). In
addition, the wells commonly produce water in excess of load
Petrophysics in the Wolfcamp is very challenging due to 1)
thin bed effects, 2) variations in matrix density, 3)
identifying the source(s) or water production, and 4)
determining moveable oil. In order to address these challenges
Core Lab has analyzed 100 Wolfcamp cored pilot wells in the
Midland Basin and integrated the data with open-hole well logs.
These integration techniques will be presented along with the
results. The remaining challenges will also be discussed.
An Integrated Digital Rock Physics Method for Wolfcamp Formation Core Characterization
Anyela Morcote (InGrain)
The Wolfcamp formation has variability in mineral
composition, organic matter, porosity and permeability that will
largely influence oil production. Using a comprehensive workflow
especially design for shale characterization, it is possible to
quantify these rock properties. A petrophysical model is
derived in this study, which is the result of integrating whole
core dual-energy X-ray CT scanning, core spectral gamma ray, SEM
analysis, and 3D FIB-SEM imaging and analysis.
Whole core dual energy X-ray CT imaging is carried out with a
voxel resolution of about 0.3 millimeter. From the
imaging, continuous high-resolution logs of bulk density (RHOB)
and photoelectric factor (PEF) are calculated. Plug samples
depths are selected based on RHOB and PEF which are indicator of
porosity and/or organic matter, and mineralogy respectively.
Plugs are X-ray CT imaged at a resolution of 40 microns/voxel
and subsamples are imaged with a scanning electron microscope
(SEM). The SEM high resolution images are digitally analyzed to
quantify the amount of organic matter, porosity, porosity
associated with organics, and high density minerals present in
the samples. Subsequent sampling is performed to obtain 3D
FIB-SEM (focused ion beam combined with scanning electron
microscopy) volumes at a resolution of about 10-15 nanometers.
Their segmentation and analysis allows us to quantify organic
matter, total porosity, connected porosity, and porosity
associated with organic matter. Also absolute permeability is
calculated using a Lattice-Boltzmann method.
Thus, integrating results and analysis of three imaging
methods performed on a slabbed core from the Texas Bureau of
Economic Geology (BEG) in Austin, TX, we arrive at upscaled,
continuous vertical measurements of mineralogy, organic matter,
total porosity, organic porosity, inter-granular porosity, and
permeability. This leads to a suggested landing that will
target greater porosity associated with organic material, not
just higher total porosity. This strategy for selecting
landing zones may improve hydrocarbon recovery and reduce
associated water production.
Understanding how XRF and FTIR data can be used to model petrophysical properties in cutting samples – examples from lateral wells in the Wolfcamp Formation
Milly Wright (Chemostrat)
For decades now elemental data have been used for regional
stratigraphic correlations and to elucidate depositional
settings in shale plays. However, with increased pad drilling
and the need for rapid completions on multilateral wells, the
regional stratigraphic application of elemental data have
diminished. The changing nature of the industry has led to
increased need for accurate well-bore placements and
understanding of rock properties from cuttings along lateral
wells in order to make more cost effective completions and post
drill decisions. Elemental data, acquired through XRF analytical
techniques and mineralogical data acquired via FTIR
(Fourier-transform infra-red) technology can be shown to provide
robust and perhaps more importantly in the currently climate,
cost effective and rapid means to model paleo-environment,
mineralogical and TOC utilizing cutting samples.
Using a set of mineralogical parameters it is possible to
assign samples (from core and cuttings) to mineral facies. In
core these mineral facies can be tied to certain rock properties
(such as brittleness, porosity, DTC & DTS) that can be directly
measured. Working within a particular target zone, it is then
possible to use facies characterization, which is readily
achieved using FTIR analyses, to both tie rock properties
measured in the core to cutting samples from the lateral, and to
model the rock properties associated with a given facies in the
lateral well bore.
By combining XRF and FTIR analyses in this way it is possible
to provide detailed insights into landing zone characterization.
This is especially insightful where expanded log suites are not
run, maximizing the amount of information that can be gathered
from cutting samples from laterals penetrations before the well