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Particulate Based Loss-Prevention Material?The Secrets of Fracture Sealing
Revealed!
Article in SPE Drilling & Completion · December 2009
DOI: 10.2118/112595-MS
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IADC/SPE 112595
Particulate-Based Loss-Prevention Material - The Secrets of Fracture
Sealing Revealed!
N. Kaageson-Loe, SPE, M. W. Sanders, SPE, F. Growcock, SPE, M-I SWACO; K. Taugbøl, SPE, P. Horsrud, SPE,
A.V. Singelstad, T.H. Omland, SPE, StatoilHydro ASA
Copyright 2008, IADC/SPE Drilling Conference
This paper was prepared for presentation at the 2008 IADC/SPE Drilling Conference held in Orlando, Florida, U.S.A., 4–6 March 2008.
This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not
been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily
reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any
part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is
restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.
Abstract
Owing to the narrow drilling margin that exists between the pore pressure and fracture pressure gradients, drilling in
depleted reservoir, HPHT and deep water environments is universally recognized as being technically challenging.
A number of field techniques are available for mitigating against many of the drilling problems encountered. Included
amongst these are specialized fluid engineering that involve use of chemical- and particulate-based treatments for minimizing
or preventing losses. In many instances these techniques can be used to strengthen or stabilize the wellbore when drilling on
or near the fracture gradient thereby potentially eliminating the need for intermediate casing strings.
This paper discusses particulate-based treatment design for sealing fractures. Substantial experience gained from
innovative laboratory testing has highlighted the mechanisms and many factors that determine the effectiveness of the
fracture seal. The particle size distribution relative to the fracture aperture, particle morphology, volumetric concentration,
fluid rheology and fluid-loss-control influence whether the seal is established within the fracture or at the fracture mouth.
Understanding this distinction is important with respect to selecting the optimum treatment and its application for given field
conditions. Parameters critical for optimizing the treatment have been identified and are discussed in the context of
laboratory and field experience.
Introduction
The loss of large volumes of whole mud to the formation (lost circulation) has historically been a root cause of well
control problems and high mud costs. Many drilling hazards such as hole collapse, stuck pipe, and even blowouts have been
the result of lost circulation. Lost circulation can occur naturally in formations which are cavernous, vugular, fractured, or
unconsolidated or it can be the result of induced pressure. Proper pre-drill planning should allow for the identification of risk
zones, optimization of drilling practice and the establishment of both preventative and remedial treatments. Here the term
‘preventative treatment’ also refers to the philosophy of wellbore strengthening. Induced fracturing is of particular concern
when drilling into depleted zones. In these cases reservoir production has reduced the pore pressure leading to a
commensurate reduction in fracture pressure.
Earlier laboratory-based investigations, such as the “Joint Industry Project (JIP) on Fracture Studies” demonstrated the
benefits of specific types and morphologies of Loss-Prevention-Material (LPM).1 That study concentrated on fracture sealing
in impermeable rock. This paper reports on some results obtained from a unique high-pressure testing device designed
specifically for determining the sealing characteristics of drilling fluids, both oil- and water-based, in permeable formations2.
A variety of additive and fluid types have been evaluated and these have resulted in a better understanding of the interplay
between LPM, fluid loss and formation permeability.
Fluid-Loss-Control Mechanisms
Fluid-loss treatments, be they preventative or remedial (and here by implication wellbore strengthening methods are
included based on LPM blends) fall into two main categories:
Low fluid loss where the fracture or formation is rapidly plugged and sealed;
High fluid loss where dehydration of the loss prevention material in the fracture or formations forms a plug that then
acts as the foundation for fracture sealing.
2
IADC/SPE 112595
Low-Fluid-Loss Treatments
Low-fluid-loss treatments are either cement, chemical resin, particle-based, or a combination thereof. For the particlebased treatments, the particle size distribution (PSD) is broad and designed to establish a coarse-particle framework in the
loss zones upon which finer and finer particles are incorporated to reduce fluid loss. One approach is to adopt a PSD that
follows Ideal Packing Theory.3 This results in a weight- or volume-based cumulative PSD that is proportional to the square
root of the particle size. The product blend should include very coarse particles to plug or bridge the largest openings in the
formation, be they fractures or pores.. Whether the formation openings are plugged or bridged, finer particles are also
necessary to fill the voids between the coarse particles, and even finer particles are necessary to produce a tight filtercake,
thus effecting a seal and fluid loss control (Fig. 1). The distinction between plugging and bridging is not great. One
definition is that plugging results when the D90 of the LPM is greater than the aperture of the formation openings; bridging
results when the D90 of the LPM is less than ½ x the aperture. Low-fluid-loss treatments can be used in both lowpermeability (mudstone, shale) and high-permeability formations (sand, fractured or vuggy carbonates).
FRACTURE SEALING: Function of Loss Prevention Material
Fracture
Wall
Flow from Wellbore
Fluid loss to Fracture tip
FRACTURE PLUGGING
•LCM d90 > Aperture
•Wide PSD of LPM minimizes fluid loss
and forms seal behind plug.
Plugging
Agent
Leak-off to Formation
Fracture
Wall
Flow from Wellbore
Fluid loss to Fracture tip
FRACTURE BRIDGING
•Aperture > 2 x LPM d90
•Wide PSD of LPM minimizes fluid loss
and forms seal behind plug.
Plugging
Agent
Leak-off to Formation
Fracture
Wall
Flow from Wellbore
Fluid loss to Fracture tip
Plugging
Agent
FRACTURE FILLING
•Aperture >> 3 x LPM d90
•Narrow PSD of LPM maximizes fluid loss
•LPM deposited in fracture through high
fluid loss and dehydration of the LPM pill.
High Fluid loss to Formation
Fig. 1 - Illustration of fluid-loss-control mechanisms for particulate-based loss prevention materials. The mechanisms that are in
operation are affected by the particle size distribution, relative fracture aperture, fluid leak-off through the fracture walls (formation)
and fluid loss to the fracture tip. Fracture plugging and to a lesser extent fracture bridging are the criteria on which Low-Fluid-Loss
LPM formulations are designed. High-Fluid-Loss LPM pills are designed around the mechanisms of Fracture Filling and
dehydration of the LPM.
High-Fluid-Loss Treatments
High-fluid-loss treatments are generally particle based. Ideally, the particle size distribution is relatively narrow
(uniform) in order to promote fluid loss. In relative terms, the particle size of the LPM should be smaller than the fracture
opening. This is necessary to ensure the material enters into the fracture and is then deposited by a process of dehydration as
the carrier fluid leaks-off (Fig. 1). The success of the treatment requires high fluid loss; thus, contamination by drilling mud
or other fines-laden fluid can significantly impair its effectiveness. Therefore, it follows that this type of treatment is more
suited to the spotting and squeezing of pill-based LPMs.
The treatment may not be effective in sealing very wide fractures (> 2 mm) - excessive flow rates in such fractures may
prevent the deposited material from completely plugging the fracture opening. In addition, very large volumes of material
IADC/SPE 112595
3
may be required. Under these circumstances, the high-fluid-loss treatment may be used to slow the rate of loss sufficiently to
enable plugging by settable plugging treatments like cement or gunk.
High fluid loss treatments can only be used in high permeability formations or fractured formations where there already is
a pre-existing high fluid loss.
Experimental Design
An objective of the study reported here has been to investigate the interplay between LPM, fluid loss and formation
permeability in the plugging and sealing of fractures. Given the prohibitive cost, difficulty and repeatability of testing largesize sandstone cores (outcrop or reservoir material) the experimental design focused on the use of manufactured porous
media that would replicate the fractured formation. Also of importance in the study of fracture sealing in permeable media is
the separation of fluid flows: that which occurs from the fluid loss through the fracture tip and the fluid loss that occurs
through the walls of the fracture, i.e the formation.
A set of experiments have been designed to shed light on the following factors affecting fracture sealing and from this
obtain a better understanding of some of the concepts that lie behind wellbore strengthening:4, 5, 6, 7, 8
Fracture aperture size versus particle size distribution (PSD) of LPM as characterized by D10, D50 and D90;
Flow rate and its influence on fluid loss to the fracture tip and through the fracture walls (formation).
Experimental Equipment
A fracture-testing device was developed that would allow the investigation of solids bridging in permeable media and
could operate at high precision at relatively high pressures2 (Fig. 2). Furthermore, testing should be relatively quick,
reproducible and cost efficient. The test device has the ability to measure two discrete fluid streams, namely, through the
fracture tip and through the formation matrix. The test device uses two parallel 5 x 0.5-in. (12.7 x 1.27-cm) diameter porous
plates to represent the formation matrix. The porosity/permeability of these manufactured plates can be varied through the
manipulation of the size distribution of the particles that are sintered together to form the disc. In this study, 175-µm porous
plates were selected. These have a measured permeability of about 100 Darcy and were purposely selected to represent a
high-permeability fracture zone.
Fig. 2 - Schematic of the M-I SWACO Fracture Tester.
The permeable fracture test apparatus (Fig. 2) consists of a cylindrical vessel fabricated to contain the permeable
(fracture) plates, four high-pressure vessels used as receptors/accumulators for the application and collection of both pore
fluid and test fluid, four precision syringe pumps for powering the system and finally a computer and data acquisition system
4
IADC/SPE 112595
for control. Test pressures up to +410 Bar (6,000 psi) are currently achievable with this apparatus, with a fracture width
fluctuation (from the set aperture) of only ±10 µm. The wellbore pressure (mud application pressure), pore pressure, fracture
tip pressure and fracture closure pressure can all be independently controlled and measured.
Experimental Boundary Conditions
The boundary conditions used in the experiments consisted of the following:
Pore pressure within porous plates and at fracture tip = 500 psi (34 Bar);
Initial “wellbore” pressure or mud application pressure = 500 psi (34 Bar);
Fracture closure pressure (pressure applied perpendicular to the fracture surface) = 500 psi (34 Bar);
Applied flow rate (of mud) = 10 mL/min and 50mL/min;
Fracture width (kept constant throughout experiment) = 250, 500 and 1000 µm;
Porous plate permeability = 100 D (175 µm pore throat size).
In the experiments fluid that enters the fracture plane can either leak-off through the fracture tip (i.e. at the outer perimeter
of the test cell) or it can leak-off through the porous plates. These two flow paths can be controlled independently of one
another so that fluid can be guided only to the fracture tip (no formation flow) or only through the porous plates (closed
fracture tip) or a combination of both. By directing the flow paths it is possible to better understand how the flow of fluid
influences the location of fracture seals that may develop within the fracture plane.
Fluid Specifications
In the experiments a 13-lb/gal (1.56-S.G.) synthetic-based mud (SBM) was used as the carrier fluid for the LPM. The
fluid properties are described in Table 1 below, where the viscosity parameters were measured at 150 oF. The influence of
base-fluid type and rheology on fracture sealing are reported elsewhere in the literature.1,2
Table 1 - API Standard Fluid properties of SBM used
as carrier fluid
SBM
600 rpm
300 rpm
200 rpm
100 rpm
6 rpm
3 rpm
PV (cP)
2
YP (lb/100 ft )
2
10 sec (lb/100 ft )
2
10 min (lb/100 ft )
ES (V)
HPHT FL
@ 250°F (mL/30 min)
SBM
(after conditioning @ 150°F )
52
34
26
18
9
8
18
16
9
10
761
6
600 rpm
300 rpm
200 rpm
100 rpm
6 rpm
3 rpm
PV (cP)
2
YP (lb/100 ft )
2
10 sec (lb/100 ft )
2
10 min (lb/100 ft )
ES (V)
HPHT FL
@ 250°F (mL/30 min)
49
32
23
16
7
5
17
15
7
9
771
5.6
Loss-Prevention-Material Specifications
In all the experiments reported here the same blend of LPM was used and was based on a proprietary grade of graphite
and crushed nutshells (the blend ratio of these two products was respectively 50:50). This blend had been identified in an
earlier study as giving optimum fracture sealing performance.1 The D10 and the D90 of the blend is 40 µm and 890 µm
respectively. For the majority of the experiments a particle concentration of 40 lb/bbl (114 kg/m3) was used; in one
experiment (S2-3, Table 2) this was reduced to 20 lb/bbl (57 kg/m3). Other experiments not reported here tested blends of
graphite and calcium carbonate where these gave similar results to those presented in this paper. .
One of the stated objectives of the study was to understand how the PSD of the LPM relative to the fracture aperture
influenced the fracture sealing mechanisms. For this purpose, in a number of the experiments, the LPM was sieved to
remove those particles larger in size than the fracture aperture; in theory this would prevent plugging, by the LPM, at the
mouth of the aperture. Once the LPM was dry-sieved it was blended in to the carrier fluid at the correct concentration, e.g.
40 lb/bbl (114 kg/m3). This method of reducing or re-sizing the PSD of the LPM ensured that the LPM passing the sieve
retained its original composition thus facilitating direct comparisons between the experiments.
Three fracture apertures were used: 250 µm, 500 µm and 1000 µm. Accordingly, in some of the experiments, the LPM
was sieved to ensure that no particles were larger than 250 and 500 µm respectively.
Experimental Results
There are 12 experiments reported here which represent about a quarter of a much larger experimental program totaling
some 40 experiments. Those experiments reported here are for one LPM blend and one type of carrier fluid - respectively a
proprietary grade of graphite and crushed nutshells, and a 13-lb/gal (1.56-S.G.) SBM. All the experiments were performed
using 175-µm porous plates.
IADC/SPE 112595
5
The experimental results are summarized in Table 2 which details the following:
Test number
Whether the LPM blend was re-sized to the fracture aperture (500 or 250 µm) or ‘N’ if it was not sieved and
retained its original composition;
Whether the fracture tip was ‘Open’ (leak-off through the tip and through the porous plates) or ‘Closed’ (leak-off
only through the porous plates);
Flow rate - 10 mL/min or 50 mL/min;
Total time before a fracture seal begins to develop;
Total time before a seal pressure of 1000 psi (69 Bar) develops;
Maximum seal pressure achieved in the test;
Calculated location of fracture seal.
The location of the fracture seal can be calculated from the measured pressure response in the experiment. Because of the
mechanics of the system the hydraulic pressures that act on the fracture seal (wellbore side and formation side) must balance
for there to be equilibrium. This equilibrium condition can be equated to r1, the radial distance to the seal, in the following
way:
r1 =
r22 ( PF − P2 )
P1 − P2
.......................................................................................................................................... (Eq. 1)
where:
PF is the fracture ‘closure’ pressure acting to hold the fracture closed;
P1 is the mud pressure acting on the well bore side of the fracure seal;
P2 is the fluid (pore) pressure acting on the formation side of the fracture seal;
r1 is the radial distance from the center to the fracture seal;
r2 is the radial distance from the center to the outer edge of the sample/cell.
Table 2 – Summary of the experimental results from the High-Pressure Fracture Tester.
Re-Sized
Fracture
LCM
TEST No
Aperture
Sieve
(µm)
Size (µm)
S2-1
500
Fracture Flow rate
Tip
(ml/min)
Total time
Time to
before
1000psi
Seal
(min)
(min)
Sealed Seal Radial
Pressure Distance
(psig)
(in.)
500
Open
10
2.5
3.5
1190
0.22 - 0.34
S2-1#2
N
500
Open
10
2.5
2.7
3900
0.22 - 1.80
S2-3
250
250
Open
10
3.1
12
1970
0.35 - 0.65
S2-6a
500
500
Closed
50
2.5
3.26
1520
1.7 - 2.6
S2-6c
250
250
Closed
50
0.25
1.75
1490
0.25 - 2.5
S2-6c#1
250
250
Closed
50
0.25
0.75
1710
0.25 - 2.5
S2-6d
N
1000
Closed
50
0.83
0.9
1560
0.20 - 2.5
S1-1
N
500
Open
10
3
3.6
6132
0.2
S1-2
N
500
Open
10
2.2
2.5
6131
0.15
S1-6
N
1000
Open
10
2.45
2.7
3611
0.15
S1-7
N
1000
Open
10
3.65
4.2
2803
0.12
S1-9
N
1000
Open
10
3.25
3.7
2037
0.12
Fig. 3, 4 and 5 illustrate typical results from the experimental program and have been selected because they demonstrate
the effect of PSD of the LPM relative to the fracture aperture size and the effect of fluid loss at the fracture tip versus the
formation.
In Fig. 3, the results for Test S2-1#2 (Table 2) are given and these are described in further detail below. The upper plot
in Fig. 3 shows the fluid loss to the fracture tip (thick blue line) and fluid loss to the formation, i.e. through the porous plates
(thin green line). The initial total flow rate is 10 mL/min which is relatively evenly split between fluid loss to the fracture tip
and formation. At an experimental time of 2.5 min. a break in the fluid-loss curve is observed and the flow rate decreases
significantly. This break-in-slope signifies the formation of a fracture seal. The step-like pattern in the fluid-loss curve at
later times reflects the repeated failure and formation of fracture seals. After about 7 min, the fluid loss trends diverge where
6
IADC/SPE 112595
fluid loss to the formation becomes less than that to the fracture tip. This reflects the accumulation of LPM within the
fracture and the formation of a filtercake on the porous fracture surfaces.
The thin black line in the upper plot of Fig. 3 shows the fracture aperture throughout the test. This should be constant and
is seen to generally fluctuate only slightly about the 500-µm mark. Spikes are observed in the trend where these correspond
to the failure of the fracture seal causing a momentary jump in the fracture aperture. Fracture aperture control is regained
shortly after these events.
The lower plot in Fig. 3 illustrates the changes in mud pressure, i.e wellbore pressure, (red line), the back pressure; i.e.
pore pressure in the formation and at the fracture tip (blue line) and the closure pressure (green line). The closure pressure is
the pressure acting perpendicular to the fracture plane. At an experimental time of 2.5 min. the mud pressure begins to
sharply rise indicating the formation of a fracture seal. The pressure peaks and drops suddenly at just after 4 minutes as the
fracture seal fails. Repeated formation and failure of the fracture seal are observed by the peaks and troughs in the mud
pressure trend. Each time the fracture seal fails and the mud pressure drops there is a corresponding small jump in the back
pressure and closure pressure as the hydraulic pressures in the system respond.
The orange line in the lower plot of Fig. 3 is the estimated location of the fracture seal. This is calculated from the mud
pressure, back pressure and closure pressure (Eq. 1) and hence, appears as a continuous trend. The trend can be used to make
observations of where, relative to the disc radius, the fracture seal develops with each cycle of seal formation and failure.
3
Fig. 3 - Experimental data for test S2-1#2 from the High-Pressure Fracture Tester. Experimental conditions: 40-lb/bbl (114-kg/m )
proprietary grade of graphite and crushed nutshells; 500-µm fracture aperture; 10-mL/min flow rate; Fluid loss through Open
fracture tip and through porous plates.
The results for Test S2-1#2 (Fig 3) shows a typical fracture sealing behaviour for the apparatus used in these experiments.
A seal is established rapidly after 2.5 min, close to the fracture mouth (0.25-in, 6.5-mm) and the mud pressure increases
linearly until the seal fails at 3900 psi (269 Bar). The fracture seal is re-established several times during the test. Each time
this happens the location of the seal is squeezed further into the fracture - from 0.2 to 0.6-in. (6.5 to 15.3-mm). In this test,
the LPM contains particles that are much larger than the fracture aperture promoting plugging near the fracture mouth. The
D90 of the LPM is 890 µm compared to the fracture aperture of 500 µm.
In Test S2-3 (Fig. 4) the LPM blend was passed through a 250-µm sieve in order to remove particles larger than the
fracture aperture. Relative to Test S2-1#2 the mud pressure response is more erratic as only weak temporary seals are formed
in the initial stages of the test. More durable fracture seals, that are capable of withholding high mud pressures (> 1000 psi,
70 Bar), develop later in the test (after 12 min.). The calculated location of the seal within the fracture plane indicates that it
becomes established at around 0.38 to 0.42-in. (9.6 to 10.7-mm) radius. The observed pressure response is suggestive of a
gradual accumulation of LPM within the fracture which eventually bridges and seals-off the aperture. Furthermore, the
IADC/SPE 112595
7
location of the seal may in part be influenced by the radial flow pattern within the fracture: initially flow is almost entirely
dominated by fluid loss to the fracture tip but flow becomes diverted through the porous plates once the seal begins to
develop. This flow behaviour is indicative of the progressive deposition of LPM within the fracture.
3
Fig. 4 - Experimental data for test S2-3 from the High-Pressure Fracture Tester. Experimental conditions: 40-lb/bbl (114-kg/m )
proprietary grade of graphite and crushed nutshells passed through a 250-µm sieve; 250-µm fracture aperture; 10- mL/min flow rate;
Fluid loss through open fracture tip and through porous plates.
Test S2-6c (Fig. 5) is similar to Test S2-3 in that the LPM blend was passed through a 250µm sieve. The test differs in
that the initial flow rate is set at 50 mL/min and the fracture tip is closed. The latter means that fluid loss occurs through the
porous disc only. The mud pressure response is observed to be a little erratic at the start of the test, with weak seals forming
and failing repeatedly, but gradually a more durable seal develops resulting in a maximum sealing pressure of 1500 psi (103
Bar) after 1.9 min. At this point there appears to be a significant failure of the fracture seal. Subsequently mud pressure
again gradually builds-up over a period of time in a repeat of the initial cycle and peaks at 1400 psi (96 Bar). A third
‘fracture sealing’ cycle is then observed to occur but results in a further reduction in peak mud pressure. At the same time
there is a gradual yet marked change in the response of the back pressure (pore pressure) and closure pressure. Over the
course of the test these pressures increase to about 700 psi (48 Bar) and show a slower response time to the leak-off of mud
pressure as the fracture seal repeatedly fails. At the end of the test the back pressure and closure pressure increase in unison
with the mud pressure. This observed behavior indicates that a filtercake is forming over the fracture surfaces which acts as
an hydraulic seal and prevents fluid loss. As a consequence the fracture behaves as a piston so that increases in mud pressure
resulting from the accumulating fluid volume are transmitted directly as increases in closure pressure and back pressure.
Arguably, the data show that under these circumstances a genuine fracture seal does not form as the fracture tip is not isolated
from changes in the wellbore pressure.
The calculated location of the seal within the fracture plane indicates that it becomes established at around 0.25-in. (6.3mm) radius and stabilizes around 0.38 to 0.4-in. (9.6 - 10.1-mm). Furthermore, each time there is a dramatic failure of the
fracture seal and associated fall in mud pressure the data indicate a significant shift in the seal location suggesting that the
LPM gets swept further into the fracture.
8
IADC/SPE 112595
3
Fig. 5 - Experimental data for test S2-6c from the High-Pressure Fracture Tester. Experimental conditions: 40-lb/bbl (114-kg/m )
proprietary grade of graphite and crushed nutshells passed through a 250-µm sieve; 250-µm fracture aperture; 50-mL/min flow rate;
Fluid loss through porous plates only; Fracture tip is closed.
Discussion
The results described above, which are typical for the experiments in Table 1, can be subdivided into 3 groups:
1. The observed behavior in Fig. 3, Test 2-1#2, is representative of Tests S1-1 and S1-2. In all three experiments the
full LPM blend was used (D90 = 890 µm) and tested at 10 mL/min against a 500-µm aperture with fluid loss through
the fracture tip and porous plates. The maximum mud pressures in the tests vary from the 3900 psi (270 Bar) (Test 21#2) to 6130 psi (422 Bar) (Tests S1-1 & S1-2).
2. The data in Fig. 4, Test 2-3, is representative of those tests where the LPM contains particles smaller than the fracture
aperture and where fluid is lost through the fracture tip and the porous plates. Not only does this include Test 2-1,
500-µm aperture where the LPM has been sieved to remove particles larger than the fracture, but also Tests S1-6, S17 and S1-9 where the aperture size of 1000-µm is larger than the D90 of the full LPM blend (D90 = 890 µm).
3. In Fig. 5, Test S2-6c, the described behavior represents those test conditions where the LPM contains particles
smaller than the fracture aperture and where fluid loss can only occur through the porous plates (fracture tip is closed
to flow); i.e. Tests S2-6a, S2-6c#1 and S2-6d. In these experiments the initial flow rate is set at 50 mL/min.
The differing trends between the groups can be better understood when the data are plotted together with respect to
aperture size, maximum mud pressure (retained by the fracture seal) and time taken to establish a fracture seal, Figs. 6 and 7.
The data in Fig. 6 shows the relationship between PSD, aperture size and fracture sealing pressure (maximum mud
pressure) and two relatively distinct groups can be defined which for clarity have been outlined. The upper group in Fig. 6,
pertains to those experiments where the full LPM blend was used. The data relates to only two aperture sizes, 1000 µm and
500 µm, but a broad trend of increasing seal pressure can be observed for decreasing aperture size. This correlates with an
increasing proportion of the LPM being larger than the aperture size. The trend is suggestive of a transition in sealing
mechanisms from fracture bridging to fracture plugging (Fig. 1). Furthermore, it can be argued that the observed spread in
the data may reflect some natural variation in the PSD between experiments as the effectiveness of the plugging mechanism
will be dependent on the number of particles larger than the aperture - fewer larger particles lead to lower sealing pressures.
There is currently no data for aperture sizes less than 500 µm so how the trend evolves is unknown. It is speculated that the
trend either remains constant or decreases again where the latter reflects interference between the larger redundant particles
and the smaller particles required for plugging and sealing.
The lower group outlined in Fig. 6 encapsulates the experiments in which the LPM was sieved to remove the particles
larger than the aperture (so-called “undersized” or “reduced LPM” blend). This data group includes the experiments
conducted with fracture tip open and closed to fluid loss (Groups 2 & 3 described above). It is clear from the trend that the
IADC/SPE 112595
9
7000
?
6000
Total Time Before Seal Develops (min)
Maximum Fracture Seal Pressure (psi)
fracture seal pressure is relatively independent of the size aperture as long as the LPM is sized accordingly. There are no data
yet available for aperture sizes less than 250 µm so the trend for smaller aperture sizes is uncertain.
?
?
5000
4000
?
?
3000
?
2000
?
1000
?
0
100
1000
Fracture Aperture (µm)
Full LCMBlend : OPENFracture Tip
Reduced LCMblend (sieved) : OPENFracture Tip
Reduced LCMBlend (sieved) : CLOSED Fracture Tip
Fig. 6 - Illustration of the relationship between maximum fracture
seal pressure (mud pressure) and fracture aperture for the
experimental data summarized in Table 1.
14
12
10
8
6
4
?
2
?
0
100
1000
Fracture Aperture (µm)
Full LCMBlend : OPENFracture Tip
Reduced LCMblend (sieved) : OPENFracture Tip
Reduced LCMBlend (sieved) : CLOSED Fracture Tip
Fig. 7 - Illustration of the relationship between the time required
before a fracture seal develops and the fracture aperture for the
experimental data summarized in Table 1. Note: time-based data
are normalized with respect to flow rate.
It is obvious from Fig. 6 that there is a significant difference in the competency of the fracture seal that develops through
fracture filling (where the LPM is smaller than the aperture) versus fracture plugging. Much higher fracture seal pressures are
attained when the aperture is plugged and then sealed by a combination of oversized and undersized particles. When the
LPM blend is undersized or reduced relative to the aperture, sealing relies on bridging and filling of the aperture through the
processes of fluid loss, dehydration and LPM particle deposition. It can be speculated that these seals are easier to overcome
when the mud pressure reaches a critical limit that exceeds the frictional resistance between the LPM particles and the porous
plate fracture surfaces. The two trends in Fig. 6 overlap or merge at an aperture size of 1000 µm. This is as expected as the
LPM blend that is used should contain few if any particles greater than the aperture size.
The data in Fig. 7 show the relationship between time taken before a seal develops (indirectly fluid loss), aperture size
and PSD. Here the data have been normalized with respect to a flow rate of 10 mL/min, so that the seal times recorded for the
tests run at 50 mL/min (Table 1) has been multiplied by 5. It can be seen from the figure that the majority of the data fall into
a relatively narrow group regardless of the flow path for fluid loss (open vs. closed fracture tip) or relative sizing of the LPM
(full vs. reduced blend). This implies that once the foundations of the seal are established, either through plugging or
deposition/bridging mechanisms (Fig. 1), the fluid loss and pressure integrity of the seal are then controlled by the PSD of the
finer fraction of the LPM. For all the tests, this size fraction of the LPM blend is the same: only the coarser element is
removed by sieving when reducing the PSD to the aperture size. The trend in the data, outlined in Fig. 7 is one of decreasing
seal time for decreasing aperture; in other words there is a positive correlation between fluid loss and fracture size for the
LPM tested. Arguably this trend is primarily a function of the cross-sectional area of the aperture and the relative
concentration of finer LPM such that more material (higher concentration) is required to seal larger fractures, all else being
equal.
The one outlier in the data grouping in Fig. 7, Test S2-6a (500-µm fracture, reduced LPM blend and closed fracture tip),
suggests that another variable is involved in the observed trends - small variations in the PSD of the LPM or more especially
the relative concentration (how homogenously the LPM is mixed in the carrier fluid) may significantly affect the fluid loss
and time taken to establish a seal.
The trend and data grouping identified in Fig. 7 need to be investigated further using different LPM concentrations, LPM
formulations with higher fluid loss characteristics and porous plates with much lower permeabilities.
Conclusions
The study reported here had the objective to investigate the interplay between LPM, fluid loss and formation permeability
in the plugging and sealing of fractures. Specifically it was the intention to shed light on how fracture sealing is influenced
by the PSD of the LPM relative to the aperture and also the distribution of flow between the fracture tip and the formation
(fracture walls).
10
IADC/SPE 112595
The results of the study clearly show that the mechanism of fracture plugging, where a seal is formed at (or immediately
adjacent to) the entrance to the aperture, produces the most competent fracture seal that are capable of withholding high mud
pressures. This process requires that the LPM blend contains particles that are larger than the fracture aperture. Furthermore,
the effectiveness of the seal appears to be sensitive to the relative concentration of larger particles such that equating the D100
of the LPM PSD to the fracture aperture is likely to produce a less effective seal than if the D90 was used.
The mechanisms by which fracture filling and sealing occur – via dehydration and deposition of LPM within the aperture
– are observed in the experiments. In these cases the LPM contains only particles that are smaller than the fracture aperture.
The maximum seal pressures are not as high as those obtained for fracture plugging and may be limited by the frictional
resistance of the LPM particles that hold the bridge in place.
Once the foundations of the seal are established, either through aperture plugging or dehydration and deposition of the
LPM, the rapidty with which an effective pressure seal is established appears to be primarily controlled by the fluid-loss
characteristics of the LPM where this is governed by the relative concentration of the finer fraction in the particle size
distribution. This needs to be investigated further using different LPM concentrations, LPM formulations with higher fluid
loss characteristics and porous plates with much lower permeabilities.
The experiments do not prove or disprove the concepts of wellbore strengthening as they were designed to test only the
mechanisms of fracture sealing by the manipulation of the LPM PSD and fluid loss. Wellbore strengthening requires that the
LPM that seals the fracture also props open the fracture, preventing it from closure, thus increasing the tangential stress (hoop
stress) local to the wellbore wall. The apparatus that has been used in this study can also investigate the mechanisms of
wellbore strengthening (fracture propping) and this is currently the subject of another laboratory study.
Acknowledgements
The authors would like to thank StatoilHydro and M-I SWACO for their permission and support in writing this paper. We
would also like to thank Dr. James Friedheim and Huy Huynh of M-I SWACO for their valuable input.
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