FFEC surveys provide a rapid method to characterize fluid-transmitting fractures in deep boreholes. The method involves circulating a baseline fluid and monitoring changes to electrical conductivity profiles over time as higher salinity fluid enters fractures. Multiple pumping rates can help determine properties of individual fractures like transmissivity. However, the method assumes ideal conditions like infinite-acting radial flow that may not apply in deep boreholes. Alternative methods involving tracer injection or circulation are also discussed.

1. Considerations for Performing Flowing Fluid
Electrical Conductivity (FFEC) Surveys within the
DBFT Characterization Borehole
PD Thorne
FA Spane
May 24, 2017 1
PNNL: Pacific Northwest National Laboratory
SFWST Working Group Meeting: Deep Borehole Field Test Session; Las Vegas, Nevada, May 23 – 25, 2017
PNNL-SA-126342

2. Presentation Outline
May 24, 2017 2
Background
FFEC Testing
Implementation
Profile Analysis
FFEC Test Limitations
Testing Alternatives
Conclusion

3. Background
May 24, 2017 3
Previous deep characterization borehole investigations have indicated
that typically only a small % of encountered fractures are hydraulically
conductive (e.g., ≤ 3%; Laxemar/Forsmark, Sweden)
A rapid reconnaissance-level open borehole test methods, e.g., dynamic
flowmeter/fluid logging, FFEC, helps identify fracture zones that are fluid
transmitting
Application of conventional flowmeter/fluid logging characterization
surveys have limitations within lower-permeability test sections (i.e., ≤
10-5 m2/sec) and/or to deep borehole test conditions
FFEC test profile characterizations are well-suited for characterizing
lower-permeability test sections not achievable using standard
flowmeter/fluid logging surveys

4. Background
May 24, 2017 4
FFEC method developed from a
collaborative effort in the late 1980’s
between Nagra and the U.S. DOE
for the purpose of rapidly
determining the permeability/depth
profile over large open borehole
sections (i.e., ~1,000 m) in deep
boreholes drilled in support of Swiss
nuclear repository characterization
studies
Leuggern borehole in N. Switzerland
was the 1st deep borehole
application
Has been applied world-wide at
numerous other deep borehole sites
(from Tsang et al. 1990)

5. FFEC Test Method
May 24, 2017 5
FFEC Implementation Steps:
Circulate (inject/pump) a contrasting salinity
baseline fluid in borehole (e.g., 60 to 300 µS/cm)
prior to test initiation)
Establish ambient baseline conditions by wireline
FEC/temperature/pressure survey
Initiate test by pumping at low extraction rate
(e.g., 2 to 6 L/min), and repetitively survey the
evolving FFEC depth profiles over time
The location of hydraulically conductive fractures
is denoted by the FFEC profile peaks/skewness
that develops due to the inflow of higher salinity
fracture zone fluid over time
At the Leuggern borehole, 9 separate fracture
zones were delineated
(from Tsang et al., 1990)

6. FFEC Analysis
May 24, 2017 6
FFEC Analysis Steps:
Determine fracture zone inflow, qi, and
salinity concentration, Ci, from the profile
areas delineated by logging runs (i.e., Profile 2
– Profile 1, etc.)
Ai = qi Ci Δt
Ai can be resolved either numerically (e.g.
BORE II) or analytically (e.g., mass balance,
moment analysis, etc.)
qi and Ci can be distinguished by comparing
FFEC profile results that developed during
later (steady-state) stages of the test with
early time FFEC profile development
a) Early time FFEC profile
b) Late-time (steady-state) profile development
(from Doughty and Tsang, 2005)

7. FFEC Test Implementation: Multi-Rate Test
May 24, 2017 7
FFEC Implementation Steps:
To help discern hydraulic head conditions, hi,
within individual fracture zones, conduct FFEC
characterization as a multi-rate test
The different pumping rates used during the
multi-rate test, will create different composite
wellbore head drawdowns, ΔhD, which may cause
different inflow or outflow relationships
dependent on the hi conditions of the individual
fractures.
Example a): the FFEC pumping step conducted
at a higher Q, and the composite head
drawdown is lower than heads in all 3 fractures:
hD < h1, h2 and h3
FFEC profiles evolve for all 3 fracture zone depths
a) First step of multi-rate test conducted
at a high pumping rate, Q1
a) Second step of multi-rate test
conducted at a lower pumping rate
Q1 > Q2
(from Doughty et al., 2017)

8. FFEC Test Implementation: Multi-Rate Test
May 24, 2017 8
FFEC Implementation Steps:
Example b): the FFEC pumping step conducted
at a lower Q, and the composite head drawdown
is lower than heads for the top 2 zones, but
greater than lowest fracture zone:
hD < h2 and h3; hD > h1
FFEC profiles continue to evolve for only the top 2
fracture zone depths
By comparing the FFEC profile analysis results
obtained from sequential multi-step pumping
rates, estimates for qi, Ci, and hi can be resolved
for each fracture zone
Qi and hi can then be used to calculate fracture
zone transmissivity, Ti, using an appropriate
analytical relationship
a) First step of multi-rate test conducted
at a high pumping rate, Q1
a) Second step of multi-rate test
conducted at a lower pumping rate
Q1 > Q2
(from Doughty et al., 2017)

9. Analytical Relationships Used for Fracture
Zone Ti Calculation
May 24, 2017 9
Radial Flow – Porous Media Equivalent
Transient: Cooper – Jacob (1946):
Ti = 2.3 qi /(4πΔhi/Δlog t)
Steady-State: Thiem (1906):
Ti = 2.3 qi/(2πΔhi/Δlog r)
Flow Normalization Method:
Ti = Ttot (qi /Qtot)
Fracture Zone – Linear Flow
Ti = (qi
2 t) /(π Si Li
2 Δhi
2)
Discrete Fracture:
Ki = (2bi)2 γw/12µw
qi /Δhi = C (2 bi)3
(Radial Flow)
C = [2 π/ln (rout/rwb)](γw /12 µw)
(Linear Flow)
C = (Wi/Li) (γw /12 µw)
Note: The transient and steady-state radial flow
analysis solutions require the establishment of
infinite-acting radial flow (IRF) conditions

10. FFEC Test Limitations
May 24, 2017 10
FFEC Analytical Assumptions/Limitations:
Water comes only from fracture zone inflow (i.e., no wellbore storage contribution)
Pressure measurements made during FFEC testing are not impacted by changing
fluid-column density
Radial flow analytical solutions used are dependent on establishment of IRF
conditions (i.e., no wellbore storage or boundary effect impacts)
There are no well skin effects due to drilling that may alter borehole fracture zone
permeability degradation (damage) or enhancement

11. FFEC Test Limitations: Wellbore Storage Effects
May 24, 2017 11
• Analysis assumes pumped water comes only from fracture zone inflow (i.e., no wellbore
storage contribution)
• Wellbore storage contributes a significant portion of water pumped during FFEC pumping,
for composite fracture zone transmissivities between: ∑Ti = 10-5 to 10-9 m2/sec
• Effects of wellbore storage can be reduced by decreasing the rc; e.g., decreasing rc from
0.114 m to 0.045 m would decrease the time influence of wellbore storage by a factor of ~6

12. FFEC Test Limitations: Non-Uniform Fluid-
Column Density Conditions
May 24, 2017 12
• Drawdown/pressure measurement
made during FFEC testing are not
adversely impacted by changing
fluid-column density effects
• Inflow of higher salinity fracture zone
fluid can significantly change fluid-
column density, and therefore, fluid-
column head relationships
• Periodically monitoring the pressure
at the base of each inflowing fracture
zone during FFEC profiling can
account for density variations
occurring within the overlying fluid
column

13. FFEC Test Limitations: IRF Test Requirements
May 24, 2017 13
• Radial flow analytical solutions used
are dependent on establishment of
IRF conditions (i.e., no wellbore
storage or boundary effect impacts)
• tD /CD = (2Ti t)/rc
2
• IRF ≥ 150 (tD /CD)
• Ti = 10-5 m2/sec; t > 1,620 min
• Ti = 10-6 m2/sec; t > 16,200 min
• Time for establishing IRF can be
reduced by decreasing rc
• e.g., using an internal packer-
tubing string

14. FFEC Test Limitations: Well Skin Effects
May 24, 2017 14
• FFEC logging assumes that there
are no well skin effects due to drilling
that may alter borehole fracture zone
permeability degradation (damage)
or enhancement
• Positive (k-reduction) well skin
increases the time for establishment
of IRF conditions
• Negative (k-enhancement) well skin
decreases the time for establishment
of IRF conditions
• No way to reduce this effect, and can
only be detected through use of
packer tests of selected fracture
zone intervals

15. Test Alternatives: Tracer-Injection Flow Log
May 24, 2017 15
• Test conducted previously over a 150 m low-permeability section at a depth of ~4 km in Germany
• Inject freshwater as a tracer and monitor the freshwater tracer boundary via downhole wireline
conductivity/resistivity sensor
• Effective characterization for 1 to 2 day tests for test intervals of 1,000 m or less is limited to
fracture zones having Ti ≥ 10-6 m2/sec; significantly impacted by fluid-column density effects

16. Test Alternatives: Tracer-Dilution Circulation
Method
May 24, 2017 16
• Implemented similarly as FFEC by injecting tracer solution
(e.g., contrasting salinity fluid) at the base of the test
interval and pumping fluid from near the top of the well
fluid-column at a higher rate, i.e.,
• Qout > Qinj
• Once stability tracer concentration (e.g., salinity) is
established in the well pumping fluid, wireline logging is
performed to establish the tracer-depth profile in the well,
with standard wireline probe sensors
• Like FFEC surveys, multi-rate tests are performed to
resolve issues of non-uniform head conditions within
fractures with Qout adjusted to cause different drawdown
head conditions within the well
• While this test has normally been conducted in shallow well
depth settings, 3 similar deep tracer-dilution circulation
tests were performed in the Nagra Leuggern borehole in
the late 1980’s for a fracture zone at a depth of ~1,675 m
(from Brainerd and Robbins, 2004)

17. FFEC Test Summary
May 24, 2017 17
Quick method to characterize transmissivity of conductive fractures
Requires contrasting EC of fluid in borehole and fractures
Low fluid extraction rates (1-10 L/min) by pump or air-lift
Multiple runs of EC/temp probe over borehole section of interest
Multiple flow rates to discern hydraulic head conditions within individual fractures
Fracture T calculated assuming infinite-acting radial flow conditions