Normally the test will be stopped before the pump pressure reaches a
peak value that is called wellbore breakdown pressure to avoid
generating a large fracture. After the breakdown, continuous pumping
in can grow the fracture into the far-field region. There are numerous
operational issues to be addressed to achieve a successful test. Due to
2009 NATIONAL TECHNICAL CONFERENCE & EXHIBITION, many factors, the results are not always easy to interpret. Very good
NEW ORLEANS, LOUISIANA discussions and guidelines are available in the published literature for
operations personnel and engineers for performing LOT and
AADE 2009NTCE-06-02 interpretation.1,2
WILL A LEAK-OFF TEST TRULY DAMAGE THE
AUTHOR(S) & AFFILIATIONS: Pressure
HONG (MAX) WANG, HALLIBURTON
FRANK MENG, CONOCOPHILLIPS
MOHAMED Y. SOLIMAN, HALLIBURTON Leak-off
BRIAN F. TOWLER, UNIVERSITY OF WYOMING
ZHAOHUI SHAN, HALLIBURTON Pump Bleed Off Pump Bleed Off
Abstract Shutdown Shutdown
Leak-off tests (LOT) are performed to test the pressure containment of
the shoe after a cement job to help ensure the new hole has been
securely isolated from what has been cased off. A successful LOT can Fig. 1-A Typical Recording of LOT and XLOT.
also be used to calibrate the least principal stress, or many times the
minimum horizontal stress, for geo-mechanics modeling. This will A well designed and executed LOT can also be used to verify fracture
require initiating a fracture at the wellbore. Due to the near-wellbore gradient prediction, which is important to the drilling operation and
stress concentration, for the geo-mechanics calibration purpose, it is casing program design. Furthermore, many people have realized that
preferred to take the leak-off to the far-field stress region. To perform results from a simple LOT may misdirect the pressure calibration and
this extended LOT (XLOT) a relatively long fracture has to be created. prediction. This is due to the fact that a LOT is generally performed by
Though a LOT is needed for these reasons, some engineers tend to creating a very short fracture that lies in the very near-wellbore area.
refrain from performing this test in fear that the test may damage the Stress distribution is significantly different from the far-field. More
wellbore and consequently cause drilling problems. often than not the LOT results do not accurately represent the far-field
stress or the fracture gradient. Consequently, extended LOT or XLOT
This paper addresses this issue by investigating the effect of (sometimes termed ELOT) has been recommended to make sure the
wellbore damage on wellbore pressure containment. Various issues are fracture is extended into the area controlled by the far-field stress3,4.
discussed to help engineers determine when it may or may not be a This requires a much longer pump time and a much larger volume of
concern. This should give practicing engineers the necessary insight into fluid to be pumped to generate a much larger fracture into the far-field.
this complex rock mechanics issue. The discussions are supported with No doubt this method can provide much more accurate tests to learn
results from analytical and numerical simulations based on rock about the far-field stress at the casing point.
From the driller’s point of view, a LOT or XLOT generates a fracture
Introduction that may create a weakness in the wellbore, despite the fact that general
experience shows that this may not be the case.
Leak-off tests are implemented to quality-control a cementing job to
verify whether the zonal isolation around a casing shoe has met the
objective. This normally is a pressure test against the exposed new
formation below a casing shoe. This is achieved by pumping into the It is, therefore, necessary to address this concern by further
wellbore with a closed blowout preventer (BOP) to obtain the needed investigating this topic using a rigorous rock mechanics approach.
pressure at a low pump rate. Simultaneously the pumped volume
and/or time are recorded during the injection and fall-off. The leak-off
pressure is identified when the pressure starts to deviate away from its
trend-line (Fig. 1). Far-Field Stresses
Page 1 of 6, 0c18af6d-bbdb-42fc-b67d-8b74b96113e2.doc
When the formation is essentially horizontal, it is possible that principal
stresses at a certain depth in subterranean formations can be considered
as one vertical stress and two horizontal stresses. The vertical stress, Sv,
is generally considered as the weight of the overburden. The two
horizontal stresses due to rock deformation caused by the vertical stress
and the tectonic stresses are Sh and SH respectively. These stresses
sometimes are called far-field stresses, compared with the disturbed
stresses near a wellbore. The formation pressure is Po. (Fig. 2).
SV Sv – Vertical stress (overburden)
SH – Maximum horizontal principal stress
Sh Fig 3-Minor Principal Stress for a Vertical Wellbore when SH = Sh.
SH Sh – Minimum horizontal principal stress
The near-wellbore stress concentration may not always provide such a
large barrier for wellbore pressure. For example, Fig. 4 shows the
P – Pore pressure residual stress against fracture initiation around a highly deviated
Fig. 2-Subterranean Principal o
wellbore in an isotropic stress environment when the wellbore pressure
is at the fracture initiation level. Due to the high stress anisotropy, the
Near-Wellbore Stress Concentration and Wellbore wellbore pressure (10.90 ppge) required to initiate a fracture is lower
Pressure Containment than the far-field minimum horizontal stress (11.54 ppge). Therefore the
near-wellbore stress concentration will not have any direct contribution
When a borehole is created in the subterranean rock formations, the to the ultimate wellbore pressure containment in this case and the
stress distribution around the wellbore will be altered. If the wellbore pressure containment should be defined only by the far-field
compressive strength of the rock together with the wellbore pressure is stress, the minimum horizontal stress in this case.
large enough, the circular wellbore will be self-supporting. On the other
hand, the stress concentration may also contribute to the containment
of the wellbore pressure. Due to the low tensile strength of the
sedimentary rock, it is essentially the rock stress rather than strength Equivalent Stress around a Wellbore when the Wellbore Presure is at the
Fracture Initiation Pressure
that holds the wellbore pressure when a high hydrostatic pressure in
wellbore is reached. In terms of containing wellbore pressure, there are 4.50
two lines of stress barriers: near-wellbore stress and far-field stress. The 4.00
Equivalent Mud Weight, ppg
stronger of the two defines the ultimate wellbore pressure containment.
Fig. 3 shows the tangential stress around a vertical wellbore. The 2.00 Fracture Initiation, ppg 10.90
tangential stress defines the fracture initiation pressure in this case. The 1.50
tangential stress has the highest value at the wellbore but gradually 1.00
Sh, ppg 11.54
Deviation, deg 45
decreases to the far-field stress after a distance of a few times of the 0.50 SH Azimuth, deg 53
Wellbore Azimuth, deg 255
wellbore radius. It is not difficult to imagine that the wellbore pressure 0.00
0 20 40 60 80 100 120 140 160 180
has to overcome this near-wellbore stress concentration before lost Angles around the Wellbore Wall q (0~180 deg)
circulation would occur. In this example, the tangential stress at the
wellbore is larger than the far-field stresses, and therefore, it defines the
wellbore pressure containment. Fig. 4-Residual Stress against Fracture Initiation for a Wellbore
when SH = Sh and Deviation = 45o
For further discussion, two parameters should be defined: the near-
wellbore pressure and the far-field wellbore pressure containment.
These two parameters are defined by the near-wellbore stress
concentration and the far-field least principal stress respectively.
Wellbore Pressure Containment, Fracture Gradient,
Minimum Horizontal Stress and LOT
Among wellbore pressure containment, fracture gradient and minimum Wellbore Strengthening by Sealing or also Propping
horizontal stress, what directly concerns a driller is the wellbore Hydraulically Conductive Cracks
pressure containment. Wellbore pressure containment is often
described with a fracture gradient measured by LOT. Several Wellbore strengthening studies5-10 have found that sealing or also
approaches (sometimes empirical correlations) are used to correlate the propping induced hydraulically conductive fractures has a strengthening
vertical stress to the horizontal stress and to finally obtain a frequently effect on the wellbore, which means that the flawed wellbore can be
so-called minimum horizontal stress and the fracture gradient. Since fixed by either sealing the cracks or also further propping the cracks. In
LOT is only about the near-wellbore effect, it is clear that the driller is other words, by sealing and propping these cracks, the wellbore can
most likely referring to the near-wellbore effect and the geo-mechanist contain the same pressure as before it is cracked. Furthermore, the
the far-field. The driller’s fracture gradient could be much different analysis shows that the wellbore can even contain pressure higher than
from the geo-mechanist’s. This is also why directly using a LOT value before it is cracked. Figs. 5 and 6 show the tangential stress around a
to calibrate a fracture gradient makes the geo-mechanist uncomfortable. vertical wellbore after sealing or also propping the cracks. Here sealing
The ELOT value, which is truly for the far-field, is preferred. means that fracture pressure is isolated from the wellbore pressure so
that it can remain low for a stable fracture.
Wellbore Weakening Factors
Wellbore weakening is a relative term. In a previous paper5, ideal
wellbore pressure containment (WPC) was defined as a benchmark for Tangential Stress along the Wellbore Wall
comparison and discussion. Ideal WPC is defined as for a perfectly 20000
circular wellbore with impermeable wellbore wall at the reservoir Sh =3000 psi rw =4.25 inch
Tangential Stress, psi
15000 Pw =6000 psi Lf=6 inch
temperature. Wellbore weakening factors are mainly the following: 10000
Pf =2000 psi E=1,090,000 psi
Borehole shape (e.g., hydraulically conductive cracks) 0
Rock shrinkage (e.g., cooling or water outflow) -5000
Increased near-wellbore pore pressure (e.g., fluid invasion) -10000
Strength loss (e.g., rock matrix strength loss) 0 10 20 30 40 50 60 70 80 90
q (0~90 o )
W Frac, SH=Sh W/O Frac, SH=Sh W Frac, SH=1.5Sh W/O Frac, SH=1.5Sh
W Frac, SH=2Sh W/O Frac, SH=2Sh W Frac, SH=3Sh W/O Frac, SH=3Sh
The factor most pertinent to LOT is the borehole shape. Here the most
frequently studied borehole shape factor in fact is a circular wellbore
with hydraulically conductive cracks. Based on the nature of LOT, the Fig. 5-Wellbore Strengthening by Sealing Fractures.
study seems to be perfect for understanding whether LOT will damage
the wellbore. Tangential Stress along the Wellbore Wall
Wellbore Weakened by Hydraulically Conductive 25000
Sh =3000 psi Lf=6 inch
Pw =4000 psi E=1,090,000 psi
Tangential Stress, psi
Cracks and LOT 20000
Pf=2500 psi n=0.225
rw =4.25 inch
The weakening effect of hydraulically conductive cracks to a circular 10000
wellbore for pressure containment has been studied with numerical
analysis6. In that study, the fracture pressure was assumed to be the
same as the wellbore pressure to simulate a no-sealing fracture. 0 10 20 30 40 50 60 70 80 90
q (0~90 o )
In one example with SH = Sh=2000 psi, when the hydraulically SH=Sh, COD=0.04 inch
SH=1.5Sh, COD=0.04 inch
SH=Sh, COD=0.06 inch
SH=1.5Sh, COD=0.06 inch
SH=2Sh, COD=0.04 inch SH=2Sh, COD=0.06 inch
conductive micro-crack has a length of only 0.3 in., the fracture starts to SH=3Sh, COD=0.04 inch SH=3Sh, COD=0.06 inch
become unstable and ready to propagate. The simulated wellbore
diameter is only 8.5 in. and 0.3 in. is less than 10% of the wellbore Fig. 6-Wellbore Strengthening by Sealing and Propping Fractures.
radius. In this case, the wellbore pressure is only 3000 psi; however, its
ideal near wellbore pressure containment for this case is 4000 psi. The Discussions on LOT
crack indeed lowers the near-wellbore pressure containment by about
1000 psi in this case. Since the fractures created from LOT are very likely to be longer than
the fractures in the above discussed analysis, it is therefore believed that
In another example with SH =2•Sh=4000 psi, with the same wellbore LOT would damage a wellbore substantially in terms of near-wellbore
pressure of 3000 psi, when a hydraulically conductive micro-crack has a pressure containment if the created fracture remains hydraulically
length of only 0.1 inch, the fracture is unstable and ready to propagate. conductive after the test. A good example of this may be a test done
In other words, stress anisotropy makes it worse for near wellbore with clear fluids such as brine or sea water.
pressure containment when hydraulically conductive fractures exist.
Details of the study can be found in literature6,7.
Though creating fractures may damage a wellbore, the wellbore
strengthening theory also provides foundations for repairing the
wellbore for pressure containment. This can be achieved by sealing the Equivalent Stress around a Wellbore when the Wellbore Presure is at the
fractures or also propping the fractures. Wellbore strengthening with Fracture Initiation Pressure
particulate lost circulation materials (LCM) has been gradually accepted 16.00
since it was introduced in 1990s11-16. After understanding the 14.00
mechanism, it becomes clear that even a regular mud without LCM may
Equivalent Mud Weight, ppg
still have some strengthening effect though the effect may be small and 10.00
not very much noticeable. 8.00
Fracture Initiation, ppg 9.01
6.00 Sv, ppg 19.23
SH, ppg 17.31
Conventional drilling fluids may contain fine particles such as clay. This 4.00 Sh, ppg 11.54
Deviation, deg 0
clay may block the entrance of the fracture and stop further mud 2.00 SH Azimuth, deg 53
invasion. This can serve as a pressure seal. If mud invades into the 0.00
Wellbore Azimuth, deg 255
created fracture, and if the formation is permeable, mud cake may form 0 20 40 60 80 100 120 140 160 180
Angles around the Wellbore Wall q (0~180 deg)
inside the fracture. This also would create a pressure sealing and
propping effect or the wellbore-strengthening effect. This may mean
that the wellbore in this condition has a self-healing function. Fig. 7-Residual Stress against Fracture Initiation for a Vertical
Wellbore when SH > Sh.
The high peak of a test pressure or wellbore breakdown pressure after
the leak-off point is believed to be created at least partially due to the Fig. 8 shows a field example of LOT for a vertical well in a highly
testing fluid inaccessibility of the narrow fractures. In other words, the anisotropic stress environment. There were two tests performed with
wellbore breakdown pressure seen from a leak-off test may be from a brine for the same depth. The two tests generated two significantly
wellbore strengthening effect. Thus, it is not difficult to conclude that a differing leak-off pressure values. The first LOT value (15.87 ppge) is
higher wellbore breakdown pressure may be achieved with a properly much lower than the second one (18.15 ppge). Analysis of the tests
designed strengthening fluid. However, it should not raise the leak-off shows that the strong stress anisotropy created uneven stress
point since it is independent of wellbore fluid properties if fluid distribution around the wellbore, and this uneven stress distribution
pressure penetration is not considered. resulted in lower near-wellbore pressure containment than the far-field.
The first LOT indicates the fracture generation in the near-wellbore
Based on the wellbore strengthening theory5-10, it appears difficult, region and the retest indicates that the fracture reached the far-field
though not impossible, to repair the cracks in shale or other region. Details of the analysis can be found in literature18.
impermeable formations with inert particulate LCM. However, it is
possible to strengthen these formations with chemical methods
including cementing17. Also given enough time, pressure differential and
filtration area, shale may also be viewed as permeable and formation of
a mud cake inside a shale fracture may be possible.
Further Discussions on LOT – Lower Near-Wellbore
A LOT will not damage the far-field wellbore pressure containment.
This is because the far-field wellbore pressure containment is controlled
by the least principal stress, which will not vary substantially during the
relatively short period of drilling. A wellbore will not be weakened
further if the near-wellbore pressure containment is lower than its far-
field pressure containment. At least wellbore deviation and stress
anisotropy may affect the near wellbore pressure containment of a
wellbore enough so that the near-wellbore pressure containment is
actually lower than its far-field wellbore pressure containment.
The wellbore deviation effect on the fracture initiation pressure has
been demonstrated in Fig. 4. Similarly, in a stress anisotropic
environment, the stress against fracture initiation pressure is also not
uniformly distributed even around a vertical wellbore. When the stress Fig. 8-Leak-Off Test and Retest Done in a High Stress Anisotropy
contrast is high enough, this stress at some points around the wellbore Area.
will define a near-wellbore pressure containment that is lower than the
far-field wellbore pressure containment. Fig. 7 illustrates such an Summary
example. In this case, the fracture initiation pressure is only 9.01 ppge;
however, the minimum horizontal stress is 11.54 ppge.
Based on the above discussion, we may conclude that LOT should not 1. Postler, D.P. 1997. Pressure Integrity Test
lower the wellbore pressure containment if one of the following Interpretation. SPE/IADC paper 37589, presented at
the SPE/IADC Drilling Conference, Amsterdam, The
conditions is satisfied: Netherlands, 4-6 March.
2. Oort, E.V. and Vargo, R. 2007. Improving Formation
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far-field wellbore pressure containment; or paper 105193, presented at the SPE/IADC Drilling
2) The LOT test does not go beyond the wellbore breakdown Conference, Amsterdam, The Netherlands, 20-22
pressure and the same or a better sealing fluid used after the February.
test; or 3. Kunze, K.R. and Steilger, R.P. 1992. Accurate In-Situ
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isolation inside fractures). paper 24593, presented at the 67th Annual Technical
Conference and Exhibition of the Society of Petroleum
Engineers held in Washington, D.C., October 4-7.
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Williams, E.L. 2002. The Importance of Extended Leak-
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E = Young’s modulus, psi SPE/ISRM paper 78219, presented at the SPE/ISRM
Rock Mechanics Conference held in Irving, Texas, 20-
Lf = Fracture half length (one wing), inch 5. Wang, H., Towler, B.F. and Soliman, M.Y. 2007:
“Fractured Wellbore Stress Analysis – Can Sealing
Pf = Pressure inside Fracture, psi Micro-cracks Really Strengthen a Wellbore?” paper
SPE/IADC 104947 presented at SPE/IADC Drilling
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Drilling Depleted Formations. Paper SPE 102719
rw = Wellbore radius, inch presented at the SPE Rocky Mountain Oil & Gas
Technology Symposium, Denver, Colorado, U.S.A., 16–
SH = Total maximum horizontal stress, psi 18 April.
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= Poisson’s ratio presented at the IADC/SPE Drilling Conference,
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