Role of “in situ” k and hydraulically induced fractures in

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Role of “in situ” permeability and hydraulically
induced fractures in controlling fluid flow into
wells – insights from petroleum systems
SEDHEAT Penrose Conference
Session 1
October 19, 2013
Kate Hadley Baker
Outline
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What we think we know
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Recent models of how preexisting natural fractures affect or
interact with fluid injection intended to induce hydraulic
fractures or open existing ones to extract heat
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Anisotropy is not your friend
What we don’t know
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Matrix porosity must provide “storage”
Matrix porosity decreases with depth; fracture porosity may or may
not decrease with depth in the same way
Naturally fractured producing horizons can be divided into 3 types
Existing tools/methods to identify fractures and assess their
relative flow contribution
Flow anisotropy/heterogeneity is probably the norm
Actual DFN at site x.
Flow velocities and movement directions in the recharging brine
reservoir beyond the well-field extent
 … and what else
Summary from petroleum systems and thoughts on previous requests
Previous “requests”
Insights from petroleum systems
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Characterize and understand existing energy
systems and their limitations
 Porosity has to provide the massively connected
storage
 30-50 kbd average for the life of well is a big ask
 Anisotropy is not your friend
Understand risks and stressors associated with
SEDHEAT
 Water utilization competition
 Potable/agricultural-use aquifer contamination, including
waste water disposal & primary production system leaks
 Induced Seismicity
 Air quality, noise, light, fugitive heat, truck traffic…
Previous “requests”
Insights from petroleum systems –
Forever Challenges
• Cost Reduction
•
• Costs are front-end loaded –
cheaper HT drilling would be a real
boon
• Less expensive, greener water
treatment/disposal options
Subsurface Imaging/Characterization
 Data improvement
• Potable aquifer characterization for
baseline studies
• In situ stress regimes to understand fracture orientation
• Can any of these be prospectively useful, or must each be done site-specifically?
 Science improvement
• Subsurface imaging
• Pre-drill brine salinity prediction
• What geologic conditions preserve/create hi k,Φ at great depth in sedimentary
rocks?
• Pathway preservation in the presence of circulating fluids
• Engineered stimulation networks
• “Recovery factor” – total thermal extraction / heat transfer rate
Matrix porosity must provide “storage”
Fracture porosity is always very small
Nelson, R.A. (1981) Geologic Analysis of Naturally Occurring Fractured Reservoirs (2nd ed., Butterworth-Heinemann)
Matrix porosity decreases with depth
Significant matrix porosity can persist at depths to 7
km. There is not much data below this.
Red lines indicate P10,
P50, and P90 for offshore
GOM sandstone data
points shown. Green lines
are P10 and P50 trends for
worldwide sandstone data
(Ehrenberg and Nadeau,
2005). Blue line is average
trend of onshore Texas
lower Tertiary sandstones
(Loucks et al., 1984).
Porosity (%)
Figure 6. from Ehrenberg et al (2008) A
megascale view of reservoir quality in producing
sandstones from the offshore Gulf of Mexico
AAPG Bull, p145-164
Matrix porosity decreases with depth
Brittle-ductile transition exists for all rocks
Paterson and Wong (2005) Experimental Rock Deformation — The Brittle Field ISBN: 978-3-540-24023-5
Matrix porosity decreases with depth
Brittle-ductile transition depends on lithology
•
e.g. All carbonates are not created equal
Matrix porosity decreases with depth
Chemical reactions play a significant role
•
Most reduce porosity by cementation or pressure solution
SEM Photo from Maast et al (2011) Diagenetic controls on reservoir quality in Middle to
Upper Jurassic sandstones in the South Viking Graben, North Sea AAPG Bull, 95, 1937–
1958.
Photomicrograph from Ajdukiewicz et al. (2010) Prediction of
deep reservoir quality using early diagenetic process models
in the Jurassic Norphlet Formation, Gulf of Mexico
AAPG Bull, 94, 1189–1227.
SEM Photo from Taylor et al. (2010) Sandstone
diagenesis and reservoir quality prediction: Models,
myths, and reality AAPG Bull, 94, 1093–1132.
Cement inhibitors:
• Chlorite coats(√)
• Early HC charge(?)
• Some reactions create or enhance porosity
Dolomitization of limestone(√) most commonly cited as significant
Fracture porosity may or may not increase with depth in the same way
Different time-evolution of fluid pressure and
chemistry in fractures vs matrix porosity
Tectonic controls on fracturing
 Rock strength/brittleness
 Structural curvature – f(t)
 Proximity to faults
 Strain rate – f(t)
 Bed thickness
Fracture intensity cross-plot derived from
core observations by Tilden and Harrison
for two fractured reservoirs in Lost Soldier
Field, WY.
Fig 3-19 from Nelson (2001) Geologic Analysis of Naturally
Fractured Reservoirs, Gulf Professional Publishing
Naturally fractured producing horizons can be divided into 3 types
Omnia Gallia in tres partes divisa est
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Fractures provide both storage and the conduit to
the well.
Fractures enable economic production rates by
augmenting matrix flow rates (dual porosity
system)
Fractures, while present, are insignificant to
system performance because the matrix porosity
and permeability is sufficiently large
Fractures may enable – or be essential to – economic production rates
30-50 kbd is a big ask
• In 2009, 5 of BP's 15 most prolific wells were located in
Azerbaijan. Of the oil wells in that lot, 5 were at ACG.
 Assuming half of the produced fluid is oil, then the overall average
fluid rate for the various field areas in ACG the year before field
production peaked, with pressure support in place, was:
Area
# Oilwells
Oil b/d
Avg rate, kbd
West Azeri
14
275,200
39.3
East Azeri
9
139,400
31.0
Central Azeri
13
185,800
28.6
DW Gunashli
9
116,000
25.8
Chirag
13
105,300
16.2
Fractures may enable – or be essential to – economic production rates
30-50 kbd is a big ask
•
The highest flow rate for a single well in the Gulf of
Mexico as of 2010 was 46,467 bopd based on the
daily average of the peak month of production.
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There is no historical precedent for a single well
producing more than 100,000 bopd.
Fracture Identification and Flow Contribution Assessment Tools
• Drilling Records
 holidays, kicks, losses, minor
changes in mud chemistry
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Openhole logs
 FMI, televiewer, caliper and
others evidence fracture
prevalence and geometry,
but not flow contribution
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Core
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Having multiple sources of information is helpful
 Some tools may over-estimate fracturing; others under-estimate it
Michael Gross, T.C. Lukas, and Peter Schwans (2009),
AAPG Search and Discovery Article #20080
Openhole Records: Indicate or Identify
Existing Tools/Relative Flow Contribution Assessment
Cased or Openhole Flow Assessment
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Direct Measurement
 Spinner surveys
 Distributed Temperature Surveys
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Tracer Test Interpretation
 Where’s Pete Rose?
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Pressure Transient Analysis
 Where’s Derek Elsworth?
Pic of fractures
or big flow
zone on DTS
or spinner
Existing Tools/Relative Flow Contribution Assessment
Pressure Transient Analysis
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Seeks to interpret system pressure-time response
in terms of models of fractured matrix systems of
varying complexity
Schematic Horner plot for a build-up
test in a naturally fractured reservoir
Flow periods for a well in a naturally
fractured reservoir
Figs 3 and 18 from: Cinco-Ley and Samaniego (1982) SPE 11026, Pressure Transient Analysis for Naturally Fractured Reservoirs
Flow anisotropy is not your friend
Permeability anisotropy is likely common
In situ “discovery” flow anisotropy arises from
depositional, diagenetic and mechanical geometries
• Depositional – sediments are layered; many
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are channelized
Diagenetic
Fractures – orientation controlled by stress
orientation history; open fracture direction
controlled by present-day stress orientation
Faulting, folding, and other structural
features, e.g. unconformities, dikes…
NASA Earth from Space Photo #: ISS025E-5504 Sep. 2010, KAZAKHSTAN
Stearns & Friedman (1972) Fig. 14 model of
fractures associated with folding. In both, σ2 is
inferred normal to bedding and σmax and σmin are
bedding-parallel.
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