Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
Abstract
Figures
Introduction
Geological setting
Petrophysical data
Reservoir geophysics
Stimulation
Conclusions
Acknowledgements
References
|
Introduction
For the geophysicist,
mapping major structures and looking for closure becomes less imperative in
tight gas and shale gas plays, where in-situ permeabilities are typically
sufficiently low that there is no mobile gas. Geophysics can, however,
provide significant uplift in reservoir characterization studies of shale
gas. The heterogeneity in shale composition subtly alters its seismic
response. Experience and modeling results suggest that stack data is
minimally sensitive to the heterogeneity, and to provide maximum uplift
pre-stack simultaneous AVO inversion for elastic parameters (Vp/Vs ratio,
Poisson’s ratio and/or Lame parameters Lambda-Rho and Mu-Rho) is necessary.
Geophysicists can also help identify subtle structural trends using seismic
attributes sensitive to discontinuities and reflector geometry.
Integrated workflows for
shale gas reservoirs have received increased attention following the step
changes achieved in operational efficiency over the last decade. Du et al.
(2009) presented such a workflow for the Barnett Shale play in Texas;
however, a crucial link missing in their workflow was analysis and inversion
of pre-stack seismic data. In Western Canada an increasing number of major
leaseholders exploring and exploiting the Horn River Basin and Montney
Formation are utilizing pre-stack amplitude variation with offset (AVO)
inversion data to assist in well placement and field development planning.
It is known from well log
analysis that the ratio of compressional to shear sonic velocities (Vp/Vs) is
a good indicator of sand-shale or quartz-clay ratios in shales and/or tight
siltstones (Figure 1). Qualitatively and
empirically, an increased sand-shale ratio correlates to increased porosity,
lower breakdown pressures for stimulation, and enhanced relative production
(Miller et al., 2007). AVO inversion of 3D seismic data allows for the
creation of Vp/Vs volumes and maps of the reservoir interval that can be
utilized for exploration and field development, which reflect the reservoir
quality based broadly on the sand-shale ratio. Inversion data and other
attributes derived from pre- or post-stack seismic data require corroboration
from independent sources to confirm its utility. Data that can provide such
calibration for these seismic based properties includes log data,
micro-imaging data, production log data, production data, and micro-seismic
monitoring data.
Geological Setting
The Triassic Montney
Formation of the Western Canadian Sedimentary Basin (WCSB) is a marine
clastic rock deposited in a continental margin basin. The Formation comprises
fine-grained (silt to shale) rocks with morphologically controlled
interbedded sandstones. Carbonate content varies and can be locally abundant
in similar proportions to quartz content. The Upper Montney comprises stacked
sections of distal shoreface to shelf siltstones up to 150 m thick with
laminae of pyrite bearing organic material (Hayes, 2009). Broadly, grainsize
decreases to the west and north from western Alberta into eastern British
Columbia.
Petrophysical and Geological Data
A total of 8 wells with
density and sonic logs that penetrate the Lower Doig and Upper Montney
formations were utilized in this study. The zone of interest in this area
averages around 40 to 50 metres in thickness. Analysis of these wells through
the zone of interest (Figure 2) illustrates
the varying rock quality and thickness. The porosity-height values for the
combined interval from the Lower Doig to the Base Upper Montney and for the
Upper Montney only are included in Figure 2;
note that only for Well A does the Lower Doig make a substantial contribution
to the porosity-height.
The petrophysical model
utilized to convert standard log suites (i.e., triple-combo data) to the
mineral models illustrated in Figure 2 is
calibrated with advanced log data (such as natural gamma-ray spectroscopy and
elemental capture spectroscopy) and core data. Core data is critical to
calibrate petrophysical data and to provide quantitative measures of
mechanical properties, which are needed to model hydraulic fracture
propagation. Image log data can be utilized to provide estimates of natural
fracture density and aperture, properties that can be difficult to measure in
extracted core due to the changes in confining pressure associated with
recovery.
Reservoir Geophysics and Seismic Inversion
Using the ISIS simultaneous
inversion algorithm four angle stacks (0-12°, 12-18°, 18-25°, and 25-30°)
were inverted for acoustic impedance, Vp/Vs ratio, and density. The angle
ranges for the four angle stacks were selected to optimize the fold in each
angle stack over the zone of interest. Results of the inversion for acoustic
impedance and Vp/Vs ratio are illustrated in Figure
3, where they are compared to well log data from that location. These
results confirm that the inversion is capable of predicting these properties.
To test the hypotheses that the Vp/Vs ratio is a good indicator of reservoir
quality, horizon or stratal slices extracted through the Vp/Vs ratio volume
are compared to porosity-height maps (Figure 4).
Stimulation and Monitoring
Micro-seismic data are
available in the study area from a horizontal well with an ~1100 metre
lateral section in the north of the study area (Figure
4). The well was stimulated in five stages using a Packers Plus
open-hole completion and monitored in a vertical well close to the centre and
slightly to the north of the lateral section. The micro-seismic data recorded
for stages 1 and 2 varies markedly from that recorded for stages 4 and 5 (Figure 5). No data were recorded for stage 3 as no
fracture could be initiated, which is assumed to be a result of either a
failure with the completion mechanism (although there was no conclusive
evidence of this) or of changes in reservoir properties that increased the
break-down pressure of the formation.
Figure 5 illustrates that relatively
few micro-seismic events are recorded from stages 1 and 2 relative to stages
4 and 5, and additionally the distribution of the points is also markedly
different. The concentration of micro-seismic events measured during pumping
stages 1 and 2 to the north of the lateral suggest an asymmetric fracture
propagation that has failed to create a complex, interconnected swarm of
induced fractures from which to produce. The events from stage 2 also
concentrate in the same area as stage 1, which indicates that new reservoir
is not being stimulated during stage 2. In contrast, a greater number of
events, which on average have a larger amplitude, were measured during stages
4 and 5. The alignment of events from stages 4 and 5 is also much closer to
the expected orientation based on knowledge of regional stresses.
The stimulation stages were
designed to be approximately equivalent in terms of total fluids and proppant
pumped, the assumption being that induced fracture networks should be very
similar for each stage. Although it is certainly possible that stimulation
design and implementation practice, and not reservoir related properties,
could explain the observations regarding the micro-seismic event patterns
discussed above, we consider that changes in formation properties underpin the
variable micro-seismic response. The increased Vp/Vs ratio indicated by the
AVO results around the stage 3 frac port suggests that a higher breakdown
pressure would be expected due to increased clay mineral content, and this
may explain the failure to initiate a fracture for this stage. Stages 4 and 5
are located in a more extensive area of lower Vp/Vs ratio (Figure 5), which explains, at least in part, the
improved stimulation results.
The stimulation detailed in
this case study utilized gelled frac oil, which is perceived by some
reservoir engineers to result in less damage to the formation as laboratory
tests on core suggest the recovered permeability is greater for oil based
fluids. Theory and field results, however, indicate that the differential is
short-lived and although the flow back of stimulation fluids may occur
slightly more rapidly, the overall producibility of the reservoir is not
improved by more expensive oil based fluids relative to slickwater or foam.
The stimulation plan for this well called for each stage to pump ~50T of
proppant; however, stages 4 and 5 ultimately pumped greater volumes due to
the failure to place any proppant into the formation during stage 3.
Conclusions
Geophysics and specifically
AVO inversion can bring significant uplift to tight gas and shale gas
reservoir characterization studies. Variations in Vp/Vs ratio can be used to
investigate and understand heterogeneity in reservoirs related to facies
variations and changes in grain size and mineralogy. The AVO results
presented here are correlated to both petrophysical modeling results from a
number of wells and micro-seismic monitoring data from a single well. The
continuation of the workflow presented here is to integrate production data
and decline curve analysis with volumetrics predicted from reservoir models
based on log data at well locations and AVO inversion data between the wells.
Acknowledgements
We thank Patty Evans at
WesternGeco Canada for releasing the seismic data utilized in this study,
Maggie Malapad at Schlumberger Canada for assistance with petrophysical
modeling, Mike Jones and Richard Parker at Schlumberger Canada for assistance
with micro-seismic data handling, and a generous client for releasing the
micro-seismic data.
References
Du, C., X. Zhang, B.
Melton, D. Fullilove, B. Suliman, S. Gowelly, D. Grant, and J. Le Calvez,
2009, A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and
Simulation: SPE paper #122934, Web accessed 19 July 2010, http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-122934-MS&societyCode=SPE
Hayes, B.J., 2009,
Evolution of Tight Gas Sandstone Plays and Production, Western Canada
Sedimentary Basin: Search and Discovery article #10182, Web accessed 19 July
2010, http://www.searchanddiscovery.net/documents/2009/10182hayes/index.htm?q=%2Btext%3A10182+-isMeetingAbstract%3Amtgabsyes
Miller, C., R. Lewis, and K.
Bartenhagen, 2007, Design and Execution of Horizontal Wells in Gas Shales
Using Borehole Images and Geochemical Data: AAPG Southwest Section
Convention, April 21-24, Wichita Falls, Texas, Search and Discovery abstract
#90065, Web accessed 19 July 2010, http://www.searchanddiscovery.com/abstracts/html/2007/southwest/abstracts/short/miller.htm
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