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, 2013Kate Hadley Baker

Outline• What we think we know

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

• 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 Anisotropy is not your friend

• What we don’t know 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

Insights from petroleum systems

• Characterize and understand existing energy systems and their limitationsPorosity has to provide the massively connected

storage30-50 kbd average for the life of well is a big askAnisotropy is not your friend

• Understand risks and stressors associated with SEDHEATWater utilization competitionPotable/agricultural-use aquifer contamination, including

waste water disposal & primary production system leaks Induced SeismicityAir quality, noise, light, fugitive heat, truck traffic…

Previous “requests”

Insights from petroleum systems – Forever Challenges

• 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

Previous “requests”

Roles of Technology

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reduce costs and improve margins

expand what’s possible

Commercial Technology

• 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

Fracture porosity is always very small

Nelson, R.A. (1981) Geologic Analysis of Naturally Occurring Fractured Reservoirs (2nd ed., Butterworth-Heinemann)

Matrix porosity must provide “storage”

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).

Matrix porosity decreases with depth

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

Porosity (%)

Brittle-ductile transition exists for all rocksMatrix porosity decreases with depth

Paterson and Wong (2005) Experimental Rock Deformation — The Brittle Field ISBN: 978-3-540-24023-5

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

Matrix porosity decreases with depth

• Some reactions create or enhance porosityDolomitization of limestone(√) most commonly cited as significant

Cement inhibitors: • Chlorite coats(√) • Early HC charge(?)

SEM Photo from Taylor et al. (2010) Sandstone diagenesis and reservoir quality prediction: Models, myths, and reality AAPG Bull, 94, 1093–1132.

Photomicrograph from Ajdukiewicz et al. (2010) Prediction of deep reservoir quality using early diagenetic process models in the Jurassic Norphlet Formation, Gulf of MexicoAAPG Bull, 94, 1189–1227.

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.

Different time-evolution of fluid pressure and chemistry in fractures vs matrix porosity

Tectonic controls on fracturingRock strength/brittleness Structural curvature – f(t)Proximity to faultsStrain rate – f(t)Bed thickness

Fracture porosity may or may not increase with depth in the same way

Fig 3-19 from Nelson (2001) Geologic Analysis of Naturally Fractured Reservoirs, Gulf Professional Publishing

Fracture intensity cross-plot derived from core observations by Tilden and Harrison for two fractured reservoirs in Lost Soldier Field, WY.

Omnia Gallia in tres partes divisa est

• 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

Naturally fractured producing horizons can be divided into 3 types

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:

Fractures may enable – or be essential to – economic production rates

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

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.

• There is no historical precedent for a single well producing more than 100,000 bopd.

Fractures may enable – or be essential to – economic production rates

Openhole Records: Indicate or Identify

• Drilling Records holidays, kicks, losses, minor

changes in mud chemistry

• Openhole logs FMI, televiewer, caliper and

others evidence fracture prevalence and geometry, but not flow contribution

• Core

Fracture Identification and Flow Contribution Assessment Tools

• Having multiple sources of information is helpful Some tools may over-estimate fracturing; others under-estimate it

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Cased or Openhole Flow Assessment• Direct Measurement

Spinner surveysDistributed Temperature Surveys

• Tracer Test InterpretationWhere’s Pete Rose?

• Pressure Transient AnalysisWhere’s Derek Elsworth?

Existing Tools/Relative Flow Contribution Assessment

Pic of fractures or big flow zone on DTS or spinner

Flow periods for a well in a naturally fractured reservoir

Schematic Horner plot for a build-up test in a naturally fractured reservoir

Existing Tools/Relative Flow Contribution Assessment

Pressure Transient Analysis• Seeks to interpret system pressure-time response

in terms of models of fractured matrix systems of varying complexity

Figs 3 and 18 from: Cinco-Ley and Samaniego (1982) SPE 11026, Pressure Transient Analysis for Naturally Fractured Reservoirs

Permeability anisotropy is likely common

• Depositional – sediments are layered; many 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…

Flow anisotropy is not your friend

In situ “discovery” flow anisotropy arises from depositional, diagenetic and mechanical geometries

NASA Earth from Space Photo #: ISS025-E-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.