Prevention and Control
of Lost Circulation
May 2011
ACKNOWLEDGMENTS
We thank the management of M-I SWACO for its support and permission to use the information
included in this manual. We also recognize members of the Technical Services team for their
contributions to the development of this manual, including Stan Alford, Mario Bouguetta, Kerati
Charnvit, Daryl Cullum, Richard Flesher, Mike Freeman, Shawn French, Fred Growcock, Quan Guo,
Janie Irvin, Esmeraldo Jimbi, Ole lacob Prebensen, Vernon Rajoo, Andrev Reznichenko, Steve Smith
and Valentin Visinescu. Special thanks also to Nelson Alfonzo, Gabe Manescu and Mary Dimataris.
Chapter 1 – Fundamentals of Lost Circulation
1-1
Consequences of Lost Circulation...................................................................................................................1-1
Losses in Fractures .................................................................................................................................................1-2
Mathematical Model for Lost Circulation in Fractures.......................................................................1-3
Chapter 2 - Classification of the Severity of Losses
2-1
Seepage Losses (0.2-15 m3/hr) ..........................................................................................................................2-1
Partial Losses (15-150 m3/hr) ...........................................................................................................................2-1
Severe & Total Losses (> 150 m3/hr) ..............................................................................................................2-1
Types of Rock Formations ..................................................................................................................................2-1
Chapter 3 - Detection and Analysis of Losses
3-1
Causes of Lost Circulation ..................................................................................................................................3-1
Location of the Loss Zone ...................................................................................................................................3-4
Nature of the Loss Zone ......................................................................................................................................3-7
Chapter 4 - Classification of Lost Circulation Materials
4-1
Particulates ...............................................................................................................................................................4-2
Cross-Linkable Polymer Pills .............................................................................................................................4-3
Soft and Hard Plugs ..............................................................................................................................................4-4
Miscellaneous Materials ....................................................................................................................................4-5
Chapter 5 - Remedial Treatments
5-1
Matrix (Seepage) Losses ......................................................................................................................................5-1
Partial Losses ............................................................................................................................................................5-3
Severe or Total Losses ...........................................................................................................................................5-3
Alternative Treatments for Severe Losses...................................................................................................5-5
VERSAPAC* chemical sealant for NAF ..............................................................................................................5-5
Reinforcing Plugs ...................................................................................................................................................5-8
Soft Plugs ...................................................................................................................................................................5-9
Other Non-Crosslinkable Solutions ........................................................................................................... 5-12
Hard (Cross-Linkable) Pills ............................................................................................................................. 5-17
Chapter 6 - Prevention
6-1
Drilling Practices ....................................................................................................................................................6-1
Drilling Fluid Selection ..................................................................................................................................... 6-10
Drilling Fluid Maintenance ........................................................................................................................... 6-12
Additives for Preventing losses..................................................................................................................... 6-12
Chapter 7 - Wellbore Strengthening Solutions
7-1
Fracture Propagation Resistance (FPR)........................................................................................................7-1
Stress Cage ................................................................................................................................................................7-1
Fracture Closure Stress (FCS) .............................................................................................................................7-4
Opti-Stress .................................................................................................................................................................7-5
Wellbore Strengthening Materials (WSM) ................................................................................................7-6
Classification and Use .........................................................................................................................................7-6
All-Purpose Pills......................................................................................................................................................7-7
Chapter 8 - Producing Zones
8-1
Effect of Lost Circulation on Formation Damage Potential ..............................................................8-1
Chapter 9 - Carbonate Formations
9-1
General Characteristics.......................................................................................................................................9-1
Preventive Measures ............................................................................................................................................9-1
Treatments ...............................................................................................................................................................9-3
“Mud Cap” Drilling (MCD) Methods.............................................................................................................9-3
Drilling Blind............................................................................................................................................................9-6
Miscellaneous..........................................................................................................................................................9-6
Recommendations ................................................................................................................................................9-6
Techniques and Procedures ...............................................................................................................................9-7
Reasons for Failure ................................................................................................................................................9-7
Chapter 10 - Deep Water
10-1
Causes and Effects .............................................................................................................................................. 10-2
Preventive Measures ......................................................................................................................................... 10-2
Controlling Deep Water Losses .................................................................................................................... 10-2
Chapter 11 - Ballooning
11-1
Managing Wellbore Ballooning .................................................................................................................. 11-4
Chapter 12 - Planning and Preparation
12-1
Preparing for Lost Circulation ...................................................................................................................... 12-1
Drilling Fluid Design ......................................................................................................................................... 12-1
Chemical Load-Out Listing ............................................................................................................................. 12-3
Chemical Procurement .................................................................................................................................... 12-3
Standing Instructions ....................................................................................................................................... 12-3
Notifying Relevant Personnel ....................................................................................................................... 12-3
LCM Logistics......................................................................................................................................................... 12-3
Reporting System ................................................................................................................................................ 12-4
Glossary/Nomenclature
G1-1
Unit Conversion Factors
G1-3
References
R1-1
Appendix 1: LCM Products by Name
A1-1
Appendix 2: Nominal* Particle Sizes of LCM
A2-1
Appendix 3: OPTIBRIDGE – Design of Particulate Blends to Stop Lost
Circulation
A3-1
What is OptiBRIDGE?.............................................................................................................................................A3-1
Appendix 4: OPTI-STRESS Design of Particulate Blends for Wellbore
Strengthening
A4-1
What is Opti-STRESS ..............................................................................................................................................A4-1
Appendix 5: FASware – Design of FORM-A Pills
A5-1
Introduction ..........................................................................................................................................................A5-1
Running the Program .......................................................................................................................................A5-1
Summary of “FORM-A” product components ..........................................................................................A5-4
Appendix 6: LCM Guidelines for Downhole Tools
A6-1
Introduction ..........................................................................................................................................................A6-1
Appendix 7: Lost Circulation Rigsite Tests
A7-1
Granulometry....................................................................................................................................................... A7-1
LCM Performance Tests.................................................................................................................................... A7-5
Thickening Rate of Crosslinkable LCM......................................................................................................A7- 7
Appendix 8: Product Bulletins
A8-1
Chapter 1 – Fundamentals of Lost Circulation
A James K. Dodson Co. study suggested
problems related to wellbore instability account
for 44% of non-productive time (NPT) during
the drilling of oil and gas wells. These problems
include lost circulation, stuck pipe, flows,
kicks, sloughing shales and wellbore collapse.
Of these, lost circulation is one of the biggest
contributors to NPT.
lost circulation attests to the limited success
of this approach and indicates that this costly,
pervasive problem needs to be addressed
comprehensively and proactively. While
proactive measures emphasize prevention,
they also recommend lost circulation materials
be held in reserve as contingency treatments
should the preventive techniques fail.
With the advent of extended reach drilling
(ERD) and the increased emphasis on deep
water over the past few years, lost circulation
now accounts for an even larger share of NPT
than that determined in the Dodson 19932002 analysis. Further, the issue of drilling into
depleted zones is increasing in importance
as fields mature, thereby exacerbating the
instances and associated risks of lost circulation.
These producing reservoirs often are overlaid
and interbedded with relatively impermeable
shale layers. Mud densities sufficiently high
to stabilize the shales can generate very high
overbalances in the accompanying depleted
sands. Pressure overbalances have been
reported as high as 90 MPa in the Gulf of
Mexico, but more typically, such as in the North
Sea, are on the order of a few thousand psi. Such
high overbalances increase the likelihood and
severity of lost circulation.
Consequences of Lost Circulation
In addition to the costs associated with lost
drilling time, the loss of drilling fluid itself to
the formation contributes a large – and perhaps
underappreciated – cost to the operation. This
is particularly true for operations using nonaqueous fluids (NAF).
In the past, methods used commonly to curtail
lost circulation focused primarily on mitigating
the problem by incorporating materials in the
fluid or in pills to bridge permeable or fractured
formations and create a filter cake over these
bridges to seal the loss zone. Indeed, drilling
fluid service companies have emphasized the
remediative aspects of the technology, i.e.
curing lost circulation after it has occurred.
The persistence and continued costliness of
May 2011
Lost circulation can occur while drilling,
running casing/liner, completing or cementing
the well. Although the drilling fluid lost is costly,
loss circulation also generates consequences
that are not only even more expensive, but can
lead to overall failure of the drilling program.
Possible scenarios and the capital-intensive
remediation/preventive measures include:
* When fluid loss occurs in depleted zones,
reducing wellbore pressure to mitigate or
prevent those losses may drop the pressure
below the pore pressure in the underlying
and normally pressured zones, thereby
destabilizing those zones and raising the risk
of wellbore collapse;
* Cuttings often settle around the BHA during
lost circulation events and can result in
the pipe becoming mechanically stuck. As
cuttings settle, they behave similar to a packer
and intensify losses below them, thus making
it prudent to always keep the pipe moving;
* As loss zones may be low pressured,
differential sticking is also possible.
Consequently, it is important that the filter
cake be as thin and firm as possible;
* Reactive clays that overlay the loss
formation may become unstable if exposed
to uninhibited fluids. Accordingly, it is
important to ensure the clays are chemically
stabilized at all times;
* A blow-out can transpire if losses occur in
a highly permeable gas-bearing formation.
In such a scenario, the likelihood of gas
invasion into the drilling fluid is high,
Fundamentals of Lost Circulation
1-1
even if the annulus is closed. This invasion
causes gas to migrate up the wellbore, thus
displacing the mud. If bull-heading is used,
the rate must never be less than 2.27 cubic
meter per minute and it is essential to be
able to calculate the hydrostatic pressure
in the well at all times. Therefore, if it is
necessary to pump a fluid into the well,
the number of strokes pumped should be
recorded to determine the fluid column
height and the hydrostatic pressure.
As discussed, the costs of drilling fluid
remediation treatments and the other
consequences of lost circulation combine to
make this prevailing problem and the NPT it
generates one of the most expensive challenges
in drilling operations.
To a large extent, the severity and persistence
of lost circulation problems are determined
by the type of formation the fluid is invading.
Generally, lost circulation can occur in three
distinct types of formations:
1. Highly permeable, where a gradual
lowering of the mud level in the tanks
indicates whole mud loss.
2. Cavernous or vugular, which usually
are found in limestone and dolomite
formations where, upon penetration, mud
Leak -Off
Pressure
(LOP)
losses may be sudden, partial or complete.
The drill string may actually drop several
meters.
3. Natural and Induced Fractures, which
usually are associated with shales or, in
the case of the latter, when some critical
fluid or other pressure exceeds the fracture
gradient of the rock, causing the formation
to break down.
The following is a more detailed discussion on
identifying and remediating lost circulation in
both natural and induced fractures
Losses in Fractures
Fractures typically create the costliest lost
circulation problems. They may be classified
as either naturally occurring or pressure
(hydraulically) induced. Usually, induced
fractures pose the most challenges for
managing lost circulation problems. At the
onset, it is crucial to distinguish drilling-induced
from natural fractures so the drilling program
can be modified to minimize the impact.
Naturally occurring fractures and faults can
occur in any type of formation, but most
commonly are found in tectonically disturbed
areas, such as those surrounding salt domes.
Accordingly, an integral part of the drilling
Formation Breakdown Pressure (FBP)
Fracture Propagation Pressure (FPP)
Pressure
Fracture Gradient (FG)
Fracture Closure Pressure (FCP)
(= Minimum Horizontal Stress , Shmin)
Time or Volume Pumped (constant pump rate)
Fig. 1-1. Idealized Extended Leak-Off Test
1-2
May 2011
Fundamentals of Lost Circulation
program should entail preparations to remediate
the potential problems that may occur.
Analytical models have been developed to
describe drilling fluid losses in natural fractures.
However, major losses often occur in fractures
that are induced during the drilling process
and subsequently widen and elongate. The
fracturing process is related to tensile failure,
which occurs when the stress exceeds the
tensile strength of the rock. Typically, tensile
failure is a consequence of the mud weight or
wellbore pressure being too high.
Fractures are induced when the wellbore
pressure exceeds the Fracture Initiation Pressure
(FIP) which, in turn, is associated closely with
the Leak-Off Pressure (LOP) as determined in an
Extended Leak-Off Test, or XLOT (see Fig. 1-1).
Induced fractures will develop and propagate in
the direction in which they most easily can be
opened and extended. Normally, this means the
fracture will develop in directions perpendicular
to the lowest principal in-situ stress, and is held
open by the fluid pressure acting against the
formation stresses. Thus, a reduction in well
pressure serves to close an induced fracture.
Induced fractures propagate in an uncontrolled
fashion when the wellbore pressure exceeds
the Formation Breakdown Pressure (FBP), which
is always higher than the LOP. However, they
also can proliferate at a wellbore or Fracture
Propagation (extension) Pressure (FPP) that is
lower than FBP and close to the LOP. The FBP
is considered the pressure at which losses
essentially become uncontrollable or total.
On the other hand, the FPP is considered
the pressure at which fracture propagation
occurs in a more controlled fashion, and
the losses that occur typically are lower
(partial) and controllable. In either case,
generally it is believed whole mud loss can
occur when wellbore pressure exceeds FPP.
Consequently, it is prudent to maintain the
Equivalent Circulating Density (ECD) below
FPP. Interestingly, wellbore deviation does not
appear to affect FPP, though it can affect FBP
considerably.
May 2011
During a XLOT, two other parameters commonly
are measured, namely the Minimum Principal
or Horizontal Stress, Shmin, and the Fracture
Closure Pressure (FCP). Normally the latter is
the lowest of the geomechanical parameters
measured and traditionally is the point usually
taken as the “Fracture Gradient” or “Fracture
Pressure.” However, FCP and Shmin often are
similar; this is particularly true for vertical wells
through formations with little stress anisotropy.
For instance, in this environment, Shmin and Shmax
(Maximum Horizontal Stress) are the same.
Consequently, Shmin often is taken as the Fracture
Gradient. To complicate matters further, in
many cases only standard Leak-Off Tests are
run, meaning neither Shmin nor FCP is measured.
This usually results in LOP being taken as the
Fracture Gradient.
Mathematical Model for Lost
Circulation in Fractures
The Tulsa University Drilling Research Projects
initiative recently developed a model for lost
circulation in drilling-induced fractures. The
purpose was to model the rate of drilling fluid
invasion into induced and natural (existing)
fractures. This model permits quantification
of the volume and rate of losses in terms of
operational conditions, fracture parameters and
fluid properties.
Assumptions used to develop the model include:
* For induced fractures, a single radial fracture
is created and is associated with radial flow.
* With regard to its properties that influence
the fracture propagation process,
the formation can be characterized
as homogeneous and isotropic. The
deformations of the formation during
fracture propagation can be derived from
linear elastic stress-strain relations.
* Fluid flow in the fracture is laminar
throughout and a Power-Law model is used
to describe the viscosity of the fluid.
* Fracture extension occurs in a simple
geometric pattern from a point source.
Fundamentals of Lost Circulation
1-3
Flow Equation
Rate of Mud Loss
For a slot of local width w(r) through which
a Power-Law fluid (of flow behavior index, m
and consistency index, k) flows at the flow
rate q under laminar conditions, the elemental
frictional pressure is:
The rate of mud loss is expressed as a function
of fracture extension, which ultimately yields
the following expressions:
For Induced Fractures
where r is distance from the wellbore.
For Natural (existing) Fractures
Fracture Geometry
The geometry of induced fractures depends
on the properties and stresses of the different
layers into which the fracture may propagate.
Since the vertical stress often is the major
principal stress, the two other principal
directions are in a horizontal plane. A fracture
expanding from a point source in an isotropic
rock in a homogeneous stress field will expand
equally in all directions in the fracture plane,
thereby forming a circular or penny shape
fracture. Fracturing of sufficient depth in highly
deviated wells is widely recognized as having
the potential to generate transverse fractures,
since the wellbore axis is not being contained
in the fracture plane. The model assumes
radial fracture geometry and flow to simulate
transverse fracturing treatments.
Fracture width
Under the assumption of plane strain, for a
pressurized circular crack opened by a constant
net pressure pn the average width is related to
the net pressure as:
where the fracture width is proportional to the
net fracture pressure, which is defined as the
difference between the wellbore pressure (pw)
and the fracture closure pressure (FCP) or Shmin,
i.e. pn = pw - FCP. Here, v is Poisson’s Ratio and E is
Young’s Modulus. The proportionality constant
kn is introduced here for the other parameters
to represent the normal fracture deformation
modulus or fracture stiffness.
1-4
May 2011
Thus, induced fractures are very sensitive to the
compliance, kn (particularly Young’s Modulus,
E), the fracture pressure, pn, and the viscosity
parameters, k and m. The flow equation for
natural fractures is not affected by changes in
the fracture width and, consequently, does not
contain the compliance term, kn. It is affected
by ∆p and the k and m terms, though not as
strongly as induced fractures; note that ∆p =
(pw – pf ). For Newtonian fluids, where m = 1,
q for induced fractures is proportional to pn4
and inversely proportional to E3, whereas q for
natural fractures is proportional to ∆p.
The rate of mud loss in induced fractures is
related to the net fracture pressure, while the
rate of loss in natural fractures depends on the
overbalance pressure ∆p = (pw – pf). Moreover,
the rate of loss in induced fractures is much more
sensitive to overpressure; for example, the loss
rate of a Newtonian fluid varies with the fourth
power of net fracture pressure. Thus, any small
change in pressure could alter the propagation or
closure of induced fractures considerably.
Identification of Loss Mechanism
Since the different loss mechanisms may
require different treatments, during drilling it
is important to differentiate between losses in
natural as opposed to induced fractures. The
characteristic responses of the two types of
fractures with respect to the rate of loss and
pressure measurement can be used to identify
the type of fracture.
Fundamentals of Lost Circulation
Unlike natural losses, which are observed to
occur at the bit when it encounters a natural
fracture, induced fractures occur in the weakest
formation. Fractures may be induced when
the wellbore pressure or ECD is increased.
Procedures such as increasing mud density,
tripping, drilling too fast, the formation of
mud rings or any other situation that causes a
temporary pressure surge can raise the wellbore
pressure above Shmin or even LOP. Excessive surge
pressure is the most common cause of fracture
opening and propagation. Such fractures often
occur at depths much shallower than the bit;
indeed, it is common for them to occur just
below the casing shoe of the previous interval.
This attribute of induced fractures complicates
the identification of the loss zone and the
placement of material designed to combat the
problem.
Induced fractures are extended easily and are
difficult to seal without reducing the hydrostatic
pressure. And once initiated, they are difficult
to control, because as the fractures widen and
elongate, any seal that may have been formed
is destroyed. Thus, lost circulation quickly can
spiral out of control.
Dyke et al. (1995) provided a qualitative way
of characterizing losses through the pit level
change with time, as illustrated in Fig. 1-2.
Fig. 1-2. Losses from Pit Level
The figure shows the change of pit level against
time for losses into pores, natural fractures and
induced fractures. Losses through pores start
slowly and gradually increase, whereas losses
into natural fractures are associated with a
rapid initiation followed by gradual decline with
time. Owing to the high sensitivity of the width
of induced fractures to fluid pressure, induced
fractures exhibit a very different profile. Thus,
with changes in wellbore pressure, such as
when the pumps are turned off and on, the pit
level may change dramatically.
Acoustic, electrical, and optical wellbore
images also provide a means of detecting and
characterizing natural fracture systems and
to distinguish them from induced wellbore
failures. Barton et al present techniques and
criteria to measure and characterize attributes
May 2011
of natural and induced fractures in borehole
image data, e.g. FMI (Formation Micro Imager)
and OBMI (Oil-Based Mud Micro Imager) logs.
Both resistivity and annular pressure
measurements can be used to ascertain the
location of the loss zone. Bratton presents a
methodology for diagnosing drilling-induced
fractures from real-time measurements, thereby
facilitating the prompt initiation of remedial
actions. Using Annular Pressure while Drilling
(APWD), ballooning can be identified from the
shape of the pressure response to the cycling of
the mud pumps. However, exponential tails will
be observed on the pressure response when the
additional volume of fractures is considered.
The flow of drilling fluid from the fracture and
back into the borehole delays the drop in ECD
Fundamentals of Lost Circulation
1-5
when the pumps are turned off. When the
pumps are turned on, it takes additional time to
re-fill the fractures. From the pressure analysis,
a marked change in slope at different ECDs is
interpreted as the fracture gradient or fracture
reopening and extension pressure. A “square”
response in the annular pressure when the
mud pumps are cycled on or off indicates no
fractures. When fractures exist, an ‘exponential
tails’ is observed when the pump pressure opens
and extends the fracture and removal of pump
pressure closes the fracture.
the rate of loss can be used to interpret fracture
characteristics.
Unlike log-based methods, mud loss analysis
techniques allow fracture flow properties to
be measured directly by monitoring fluid flow.
Moreover, logging techniques are more localized
around the wellbore, whereas mud loss analysis
measures the fracture properties within a large
volume of rock and is more representative of
real scale.
Minimizing Risk of Induced Fractures
Adachi et al. noted that, in contrast to
hydraulic fracturing models, which normally
assume constant flow rate in contrast to
hydraulic fracturing models (which normally
assume constant flow rate), the problem of
lost circulation in fractures is derived from
a hydrostatic overbalance, and therefore a
constant pressure boundary condition is more
realistic. The authors applied a numerical model
for flow into an expanding fracture under
constant wellbore pressure boundary (PBC)
to a number of lost circulation scenarios. This
approach has come to be accepted as current
industry practice.
The following guidelines can help minimize
the risk of inducing fractures and distinguish
between the losses in natural and induced
fractures:
* Determine the loss rate and record the
characteristics of the loss whether the
losses associated with an increase in ECD,
sensitivity to ECD or pump rate, increase/
decrease in ROP, crossing a fault.
* Reduce mud weight and ECD if possible.
* Reduce circulation rate / viscosity.
* Reduce ROP.
In attempting to manage lost returns and
well control problems, Dupriest exploited the
new concept of using hydrostatic packers in
propagating fractures. Employing hydrostatic
packers requires a solid understanding of the
fracture propagation mechanism through
which the major lost returns events occur, in
particular the role of fracture closure pressure
(FCP). The idea promotes that the fracture is
open when wellbore pressure is sufficient to
overcome the sum of the stress holding the rock
closed (Fracture Closure Stress) and the tensile
strength of the rock. Hydrostatic packers were
used to control the placement of Lost Circulation
Material (LCM), cement and cross-linked
polymers.
The measurement of pressure and flow rate
while drilling can be used as an indication of the
type of the fracture. High-resolution flow meters
can measure the rate of fluid flow into and out
of the wellbore. The characteristic response for
1-6
May 2011
* Trip in hole more slowly and break (stop)
circulation while rotating.
Lost Circulation Materials
A number of techniques available to “cure” and
even prevent losses are discussed throughout
this Manual, especially in Chapters 6 and 8.
Many of the solutions that help prevent and
remediate lost circulation involve treatment
of the mud with particulates or chemicals
that engage the loss zone in some fashion
so as to isolate or patch the wellbore. While
LCM generally denotes the particulates, in
some cases, chemical solutions also carry that
designation. Other terms recently coming into
vogue are Loss Prevention Materials (LPM) and
Wellbore Strengthening Materials (WSM), which
are identical and constitute a sub-set of LCM, as
shown in Fig. 1-3. These materials are usually
granular and have relatively high fracture
toughness, i.e. they do not crush easily. Both
Fundamentals of Lost Circulation
WSM and LPM refer to the LCM used specifically
to prevent, rather than remediate, losses.
The characteristics of LCM and how they
function to cure or prevent lost circulation
will be described in subsequent chapters. In
addition, other aspects of lost circulation, such
as best practices in drilling and solids control,
are detailed to provide input on all of the latest
tools engineered to deliver a quality wellbore.
Most Salts
Flakes
Reactive Materials
Most Fibers
Plates
Marble
Synthetic
Graphite
Laminates
Hard, Granular
Fibers
Soft Granules
Fig. 1-3. Lost Circulation and
Wellbore Strengthening Materials
May 2011
Fundamentals of Lost Circulation
1-7
Chapter 2 - Classification of the Severity of Losses
Lost circulation is often classified according
to the rate of loss as seepage, partial or severe
(including total).
Seepage Losses (0.2 - 1.5 m3/hr)
Seepage, or matrix, losses take the form of very
slow losses that can appear as filtration to a
highly permeable formation. Seepage losses
also can be confused with cuttings removal and
evaporation of the water phase at the surface.
It is important not to confuse these completely
different events.
If seepage losses are suspected, the bit must be
pulled off bottom and the mud volumes checked
with and without circulation. All mixing
equipment and non-essential solids removal
equipment should be turned off and base line
values recorded.
Once it is established that whole drilling fluid
is indeed being lost, a decision must be made
on whether to cure the losses or merely tolerate
the situation. Depending on the economics
of the drilling fluid and/or rig time, it may be
preferable to continue drilling with seepage
looses. However, if pressure constraints are
tight, a good cement job is required. If formation
damage or stuck pipe are the primary concerns,
an attempt should be made to cure the losses
before proceeding with drilling.
Partial Losses (1.5 - 15 m3/hr)
Since partial losses are greater than seepage
losses, the cost of the fluid becomes more crucial
in deciding whether to drill ahead or take
remedial action.
Once again, all the factors discussed previously
must be taken into consideration to decide if
drilling with partial losses can be tolerated
economically. Drilling with partial losses can be
considered if the fluid is relatively inexpensive
and the pressures are within operating limits.
May 2011
Severe & Total Losses (> 15 m3/hr)
In almost all circumstances when losses of this
type are encountered, regaining full circulation
is required. Accordingly, the first step is to pump
a fluid of lower density down the annulus while
monitoring the volume required to fill the well.
If the well becomes stable, calculate the
hydrostatic head required to fill the wellbore.
If losses persist, begin controlling same by
spotting conventional LCM pills, and later
progress to using plugs ging agents if that
standard treatment is unsuccessful. Because of
the reduced hydrostatic head, the well must be
monitored closely at all times for fluid influx.
In some areas it may be possible to continue
drilling if the fluid cost is low and pressures are
manageable.
Types of Rock Formations
The nature of the drilled rock formations plays
a significant role in the risk and severity of lost
circulation. Formations may be classified as:
Unconsolidated Formations
While these formations typically are at shallow
depths and normally consist of sands or gravel,
they can occur in shell beds or reef deposits.
Coarse unconsolidated formations can possess
permeability sufficiently high to allow whole
mud to invade the formation matrix (10 - 100
Darcies). For whole mud to be lost, the average
particle found in the mud must be 1/3 or less of
the formation opening. Normally, these losses
are confined to shallow wells or surface hole.
The rate of loss can vary from seepage to total
losses. In the event losses are total, a common
practice is to drill blind, providing a sufficient
supply of water is available and environmental
or well control considerations do not pose
concerns. One justification for preventing
shallow mud losses is that these unconsolidated
formations may wash out, forming a large
cavity that is less stable and which could
cave in from overburden and rig weight. In
Classification of the Severity of Losses
2-1
mountainous areas, preventing losses may be
accomplished by drilling with air, mist, foam or
aerated drilling fluids.
Highly Permeable / Low Pressure (Depleted
Zones) Formations
These mainly are depleted sand reservoirs
and can occur at any depth. The extraction of
formation fluids from producing formations
in the same field or general vicinity may cause
subnormal (depleted) formation pressure. The
loss of mud to these formations require the
passages be of sufficient size and intergranular
connectivity and that the mud pressure exceeds
the formation pressure, thus allowing the entry
of whole mud. This type of mud loss can range
from seepage to severe and often can lead to
differentially stuck pipe.
Caverns, Vugs and Faults
Cavernous or vugular formations usually
are associated with low-pressure carbonate
(limestone and dolomite) or volcanic formations.
In limestone, vugs are created by the earlier
and continuous flow of mildly acidic water that
dissolved part of the rock matrix (leaching),
thereby creating a void space that often is filled
later with oil or gas. When these formations are
drilled, the drill string may fall freely through
the void zone, precipitating a sudden loss of
returns. The volume of losses will depend on the
degree to which the vugs are interconnected. In
more mature areas with a drilling history these
losses usually are predictable.
Faults are another type of irregularity that
ultimately can lead to catastrophic losses.
Accordingly, it usually is best to avoid them,
if possible, but if not most well plans call for
traversing faults in a normal or perpendicular
orientation to minimize instability-related
problems.
extended by hydraulically imposed pressures.
In many cases, natural fractures exist that
may be impermeable under balanced pressure
conditions. Losses also may occur at unsealed
fault boundaries.
Natural Fractures
This type of mud loss occurs mainly in shales
where fractures or fissures exist naturally. These
intrinsic fractures require only that the mud
pressure exceed the fluid pressure within the
rock. This can happen at overbalances as low as
350 Pa. Initial loss rates can vary from seepage
to severe, but are more likely to be the latter.
This type of loss rate can be troublesome to cure
as they tend not to be localized, but rather exist
through the geological interval being drilled.
Induced Fractures
Induced fractures occur when the wellbore
pressure or some other critical pressure exceeds
the fracture gradient of the rock, causing the
formation to break down. Once a fracture is
created or opened by an imposed pressure, it
may either be difficult to heal or never regain
the original formation strength. These losses
are much harder to cure with NAFs than with
their water-based counterparts, especially in
formations that contain clay. Another oft-cited
reason is that NAFs generate thin filter cakes,
which produce poor pressure isolation at the
fracture tip compared to the thicker filter cakes
generated by water-based drilling fluids It has
been suggested that induced losses account
for up to 90% of all lost circulation incidents
recorded. Accordingly, it is prudent to plan or
pre-treat to prevent lost circulation.
These losses often occur from intermediate
casing being set in the wrong place or by
excessive downhole circulating and surge
pressures.
Microfractures
Mud loss also occurs to fissures or fractures in
wells where no coarsely permeable or cavernous
formations exist. These fissures or fractures
may occur naturally, or may be initiated or
2-2
May 2011
Classification of the Severity of Losses
Conditions that can lead to excessive downhole
pressure include:
* Improper Hydraulics
• Excessive flow rates and fluid rheological
properties resulting in high ECD
pressures.
* Poor Drilling Practices
• Pump surges caused by increasing the
pump rate too rapidly after connections
and trips. This is extremely important
when dealing with invert emulsions.
Since inverts tend to have higher
viscosities when cooled, failure to bring
the pumps up to speed slowly can result
in much higher circulating pressures on
the formation. This condition occurs after
trips and is exacerbated when drilling in
deep water.
• Raising and lowering the pipe too quickly
on connections or during trips (surge/
swab).
• Excessive cuttings in the annular flow
stream from excessive ROP will result in a
high ECD.
• Washouts can lead to cuttings
accumulations in the enlarged hole
section. Afterwards, these accumulations
can fall back into the hole, resulting in a
pack off condition or create bridges in the
absence of drill pipe.
• Cuttings beds or barite sag in deviated
wells may result in a localized density
increase.
• Kicks and well control procedures.
* Poor Drilling Fluid Properties
• Excessive viscosities and gel strengths.
• Build-up of drilled solids.
• Thick filter cakes that reduce the hydraulic
diameter of the wellbore.
• Excessive mud density or increasing the
mud weight too rapidly.
• Unbalanced mud columns.
• Barite sag.
• Excessive low gravity solids (LGS) and
high MBT values.
* Poor Hole Quality
• Sloughing or caving shales will increase
solids loading in the annulus, resulting
in high ECD. This condition may also
result in a pack off. Packing off, if even
temporary, can result in extremely
high pressures being imparted to the
formation.
May 2011
Classification of the Severity of Losses
2-3
Chapter 3 - Detection and Analysis of Losses
Effective treatment of lost circulation comprises
a series of steps that include:
1. Assessing the cause(s) of lost circulation
2. Establishing the location of the loss zone
3. Identifying the nature of the loss zone
4. Selecting the proper remedial action
The rate of success depends heavily on
addressing these steps in a sequential and
coordinated fashion. Planning should identify
formations that are potentially troublesome
or prone to losses and afterwards outline the
procedures and actions to be taken prior to
entering those zones. For exploratory drilling
and/ or when encountering unexpected events,
the 4-step strategy outlined above can deliver
an effective and timely solution.
Causes of Lost Circulation
When a drop in the mud volume is noted, it
frequently is assumed the losses are occurring
down hole. However, this may not always be
the case. The first response to a reduction in the
mud volume should be to pick the bit off bottom
and observe the well for fluid movement. Once
losses have been confirmed, the following
verification steps are recommended:
* Establish the loss rate
* Check the solids control equipment to
ensure no new equipment has been placed
on-line and the discharge rates are normal
* Check to ensure no mud has been dumped,
transferred or otherwise removed from the
system
* Check all joints, pipe connections and valves
for leaks
* Assess casing wear potential for each type
of operation as a function of hole trajectory,
wellbore structure, drillpipe configuration
and mud system
May 2011
In addition, it is necessary to identify the type of
formation being drilled and practices that may
increase the risks of losses in pre-existing as
well as induced openings in the rock:
Unconsolidated and Highly Permeable
Formations
Usually, extremely permeable formations
with high inter-granular porosity are found at
shallow depths and rarely are over-pressured.
In these zones, the pores typically are too large
to accommodate the creation of a competent
filter cake. Consequently, when hydrostatic
pressure exceeds the formation pore pressure,
mud will be forced into the rock. As a result,
lost circulation may be initiated while drilling,
tripping or while circulating to condition the
hole prior to running casing.
The loss usually starts with a gradual reduction
in the pit level, and, if no remedial action is taken,
the loss may exceed rig pumping capacity. This
type of mud loss can range from seepage to severe
loss and often leads to differentially stuck pipe.
Natural Fissures and Fractures
This type of lost circulation can occur in a
number of rock types and requires only that the
mud pressure exceeds the fluid pressure within
the rock. Overbalances as low as 350 Pa may be
sufficient to initiate losses in fissures or fractures.
Older, harder and more consolidated formations
are the more likely locations for natural fractures.
They are created by geological movements after
sedimentation and compaction and have a
higher frequency of occurrence near faults and
areas that have been subjected to tectonic forces
and stresses, such as those occurring with the
movement of salt domes or diapirs.
While the initial loss rate can be minor (seepage)
it quickly can approach severe if drilling
proceeds. This type of loss has caused some of
the most troublesome lost circulation incidents
recorded.
Detection and Analysis of Losses
3-1
Cavernous and Vugular Formations
* Hold back formation pressures
These normally are found in carbonate and
limestone formations. Losses during drilling
often are characterized by sudden and complete
losses with the bit often dropping several feet.
Often, the loss rates will exceed rig pumping
capabilities. The caverns are caused by water
percolating through the formations over
geological periods of time creating channels.
Caverns can be localized or form part of a more
extensive system where the voids may range in
size from pinhole to tunnels. Pressures in these
formations usually are sub-normal, meaning
they are below that of a fresh water gradient.
* Allow tripping (trip margin)
Caverns are the most difficult lost circulation
zones in which to re-establish circulation and
in many cases the well must be drilled “blind”,
i.e., with no returns. Air, foam or aerated mud
drilling may be effective in these circumstances.
If the caverns occur close to surface, there is a
risk of location collapse.
* Stabilize the wellbore (note that with
respect to the in-situ stresses weak
formations require an effective mud
overbalance for stability, which is dependent
on well inclination and direction).
During drilling a transition from an abnormally
pressured zone to a normal or sub-pressured
zone may be encountered. This pressure
differential may be sufficient to cause induced
losses, which occur in the form of hydraulically
fracturing the formation or either the pressure
may be sufficient to cause whole mud invasion
into a permeable formation. During well
control situations lost circulation can occur
when the well is shut-in. The shut-in pressure
is transmitted down the wellbore, breaking the
formation at its weakest point. This not only
results in lost circulation, but also losing control
of the well.
Hole in the Casing or Riser
A hole in the casing or a leak in a liner hanger
can lead to lost circulation by subjecting the
formation, previously protected by the casing or
liner, to a mud weight that exceeds its fracture
gradient. A leak in an offshore drilling riser also
will lead to drilling mud being lost from that
section of pipe.
Induced Fractures
Induced fractures occur when the wellbore
pressure exceeds the fracture pressure of the
rock, causing the formation to break down.
Conditions leading to this type of loss are
included in the VIRTUAL HYDRAULICS* software
package and could be predicted and minimized
through thorough planning and monitoring.
Conditions that cause excessive wellbore
pressure include:
Excessive Mud Weight
Mud weight is the major source of pressure
in the well. The density of the fluid should be
maintained at a safe minimum to:
3-2
May 2011
Proper planning and execution will minimize
the possibility and severity of the kick.
Personnel responsible for the operation at the
well site should be aware of the maximum
allowable casing shut-in pressure (MACSP) and
volume. The volume of the intruding fluid or gas
is related directly to the MACSP and should be
minimized.
If a well has been shut-in, proper kill procedures
should be used to maintain the proper constant
bottom hole pressure to kill the well. If proper
procedures are not followed, an underground
blowout can occur. Proper planning and
execution is the key to avoiding mud losses due
to excessive mud weight. Always maintain as
low a mud weight as practical.
Excessive ECD
Circulation of the drilling fluid generally
increases the effective mud weight, or ECD, and
it may reach a level that exceeds the fracture
gradient, thus resulting in mud losses. Where
conditions allow, these losses may be cured by
reducing the base mud weight, the rheology, the
Detection and Analysis of Losses
cuttings concentration in the annulus, slowing
down the pump rate or a combination thereof.
Proper attention, however, should be given to
hole cleaning and wellbore stability when these
remedies are considered.
ECD is calculated by the following equation:
ECD (kg/m3) = ρ (kg/m3) + pa (Pa) / [0.052 x TVD (m)]
where ρ = fluid density in kg/m3
pa = pressure loss in annulus in Pa
If a high mud weight is required to control
abnormal formation pressures in another
part of the hole, losses may occur in a weak
zone. If the mud density cannot be reduced
without destabilizing the well or inducing a
kick, consideration should be given to reducing
the ECD through alteration of either the pump
rates or the flow properties of the fluid. If either
of these options is considered, close attention
should be paid to hole cleaning so as not to stick
the pipe, overload the annulus with cuttings, or in
high-angle wells, induce weighting material sag.
Excessive Pump Rate/Fluid Viscosity
Flow properties and circulating rate should
be balanced to deliver the minimum pressure
losses consistent with cuttings removal. High
rates of circulation, while improving hole
cleaning, may expose the formation to excessive
pressure.
Conversely, high yield point and gel strengths
also may result in the formation being subject
to high pressures for a given pump rate. When
these types of losses are of seepage in nature,
simply reducing the pump rate for a given
period of time may actually cure the losses.
Once the losses are cured, the pump strokes can
be brought up gradually until the desired pump
rate is achieved.
Poor Filtration Control
A high filtration rate generally equates to a thick
filter cake building against the formation. This
reduces the annular clearance. For instance, a
½-in filter cake reduces an 216 mm hole to
190 mm or a 165 mm hole to 140 mm. Smaller
diameter annuli lead to higher velocities for
a given flow rate and, hence, a higher ECD. In
severe cases, the mud cake can reach a level
where the hole packs off around the drill string.
On the other hand, the filter cake quality itself
can provoke cutting agglomeration due to
stickance.
Cuttings-Related Losses
Cuttings can affect lost circulation in a number
of ways. When hole cleaning is inadequate,
cuttings may accumulate in the annulus,
loading up the mud weight locally until losses
are induced.
Hole washouts can reduce the annular
velocity to the point where cuttings are no
longer transported out of the well. When this
occurs, the drill solids may accumulate, slough
downwards and bridge off where the hole size is
normal, thereby resulting in pressure surges.
In deviated wells, cutting beds that are not
properly eroded and left to build-up may slump
in the hole, packing off and pressurizing the
formation to the point that it breaks down. One
common practice when drilling deviated wells
is to pump pills to assist with hole cleaning.
Warning: Once these beds are disturbed, it
is possible that the cuttings will slump and
pack off, thereby increasing pressure to the
formation perhaps to the breakdown point.
Slumping typically occurs in the angle-building
sections of deviated wells.
Pressure Surges
Pressure surges that derive from pump surging
while breaking circulation or a rapid lowering
of drill pipe or casing can result in a pressure
peak high enough to break down the formation.
Consequently, the induced fracture(s) may
propagate rapidly at the fracture propagation
May 2011
Detection and Analysis of Losses
3-3
pressure, which can be significantly lower than
the formation breakdown pressure, resulting
in losses. VIRTUAL HYDRAULICS is a powerful tool
to model achievable maximum pressure in all
the aforementioned situations; therefore, it is
highly recommended that VH be employed in
the planning and execution stages to identify
high-risk situations.
In addition, a number of drilling practices can
induce downhole drilling fluid losses by creating
surge pressures that will increase the pressure
on the formations:
* Running in with the drill string or casing
inevitably will create a piston effect and
surge pressure. This problem will be
aggravated by packed hole assemblies
and when the mud is cold with high gel
strengths. Circulating and filling casing
tools allow continuous homogenizing of the
fluid column, thus circulating out any loose
obstruction. Not all operations have access
to this hardware so it may be necessary to
break circulation at several stages during the
trip into the hole. It is important to establish
and adhere to maximum allowable pipe
handling speeds.
* Pump surge. If the pump speed is increased
rapidly, this will generate a surge pressure.
Therefore, it is essential to bring the pump
on line slowly and carefully.
* Excessive penetration rate. It is always
necessary to control penetration rates
to ensure the annulus is being cleaned.
Controlled drilling will be required if a
formation with a low fracture gradient is
exposed in the open hole section.
Hole Enlargement
Hole enlargement will drop annular velocity in
the portion of the wellbore where it occurs. An
increase in the wellbore size allows depositional
build up of the cuttings in the enlarged section.
Once cuttings accumulate in the washout
section they may begin to slump in and bridge
the wellbore, resulting in a packed off situation.
3-4
May 2011
Pack offs subsequently increase the pressure
resulting in a breakdown of the formation.
Circulating Casing
Owing to the higher pressures resulting from
a smaller annular clearance, losses often occur
while circulating the casing. During this stage
of the operation, the fluid often cools. This
leads to an increase in the static density of the
fluid. In addition, viscosity usually rises with
a decrease in temperature. The combination of
these phenomena has the effect of causing a
significant increase in the ECD. Applying proper
operational practices and using circulating
casing tools help minimize pressures surges.
Open-Hole Displacements
Open hole displacements can create conditions
of abnormal pressures. The increased pressure
may arise from frictional losses while displacing
fluids of significantly different weight, an
unbalanced hydrostatic column, or chemical
interactions between fluids in the hole or
formation-fluids. Careful planning and design
criteria should be sufficient to minimize or
mitigate these situations. With its capacity to
generate comprehensive pressure and volume
displacement profiles, the proprietary VIRTUAL
COMPLETIONS FLUIDS* software package can help
adjust planned execution conditions for open
and cased hole displacements.
Cementing
In cementing, the drilling fluid is displaced in an
open hole with cement slurry. The intrinsically
high density of the cement slurry contributes
to very high pressure surges in the exposed
open hole intervals. Hence, this type of losses
occurs most often and is considered a ‘necessary
evil’. However, careful simulation of the
displacement using VIRTUAL COMPLETIONS FLUIDS may
help in selecting the proper pumping regime to
minimize the probability of the losses.
Location of the Loss Zone
Identifying the position of the loss zone
is paramount in rectifying lost circulation
problems. Correctly identifying the position
Detection and Analysis of Losses
of the theft zone is critical for the proper
placement of the lost circulation material. The
theft zone may be located from previous drilling
records, drilling rates, drilling breaks, formation
changes and various logging techniques. For
known areas, pore pressure/fracture pressure
gradients or trends provide important guidance
in narrowing down the location of the weakest
zone or the formation most prone to lost
circulation.
* If the losses are experienced while drilling,
the loss zone likely is on bottom and caused
by natural fractures, caverns or highly
permeable formations.
* If losses are experienced while either
tripping or increasing mud weight, it is
likely the loss zone is not on bottom and is
the result of induced fractures. Recognizing
a loss while tripping back into the hole
requires attention to the volume of fluid
being displaced by the pipe. This volume
can be determined by observation or from
regular examination of the pit level record.
* Drilling into a sub-normally pressured,
naturally fractured formation usually is
indicated by a sudden high loss of returns
accompanied by an increase in rotary
torque. When no previous problems
have been encountered, this is a reliable
indication that the lost circulation zone is at
bit depth. Losses are normally “on bottom”
if:
• They first occur while drilling ahead
• The loss is accompanied by a notable
change in ROP, torque, or drilling
fluctuations
• Induced fractures on bottom can be
caused when the BHA or bit balls up,
thereby restricting the annulus
• The loss is due to natural fractures, faults,
caverns, vugs or high permeability sands
and gravels. An increase in torque follows
a drilling break or the kelly free falls while
drilling and is coupled with an instant
loss in circulation
May 2011
* Losses are normally “off bottom” if:
• They first occur while tripping, drilling
fast or increasing mud weight
• They obviously are the result of an
induced fracture
• They result from shutting in and killing
the well
• The annular loading is sufficient to
increase a return apparent mud weight
to the extent that it is higher than the last
casing shoe fracture gradient
Onsite fluid engineers must be alert for any
indication of a potential loss, which will
facilitate expedient identification of the root
cause. While pit monitors and PVTs offer
drilling crews a reliable detection system, more
rudimentary methods, such as strapping pits
with physical marks wherever the surface
system permits, are a good backup practice.
Several logging methods also are available for
locating the point of loss.
Spinner Survey
A spinner survey tool acts as a down hole flow
meter to identify the fluid flow into the lost
circulation zone. The spinner survey is made
by running a small spinner attachment into
the well on a single conductor cable and is
configured so the rotor spins or turns if any
horizontal movement of the mud occurs. The
rpm of the rotor is recorded on film as a series
of dashes or spaces. The rpm will be very slow
initially, but will speed up considerably when
the loss zone is encountered. However, this
method poses a couple of limitations:
* It requires deliberate loss of large volumes of
mud
* It is not effective when sealing particles are
already present in the mud
Temperature Survey
The temperature survey depends on a
subsurface thermometer for measuring
Detection and Analysis of Losses
3-5
the difference in the mud and formation
temperatures. This survey involves running
a sensitive element in the well that changes
its resistance as the temperature changes.
Two surveys are run. One is to establish the
temperature gradient of the well after the mud
has come to equilibrium with the formation.
The second survey is run immediately
after adding cool mud to the well. A sharp
temperature discrepancy will occur at the point
of loss. As with the previous survey, this also
one requires a large volume of fluid.
Radioactive Tracer Survey
Hot Wire Survey
The hot wire essentially is a calibrated
resistance wire that is sensitive to temperature
changes. It is run to a desired point in the well
where the resistance is noted before mud
pumped into the hole. If the tool is above the
point of loss, the mud flow will indicate a
change in resistance. If the resistance remains
constant, the tool is below the point of loss.
Although the tool can be used in any type of
mud, a large volume of fluid is required while
making the survey.
Pressure Transducer Survey
This type of survey involves using a short
cylinder that is open at the top and swaged
at the bottom to restrict flow of mud through
the tube. The survey involves a window fitted
with a neoprene diaphragm on one side of the
tube. An electrode on the diaphragm moves
back and forth between two fixed electrodes.
As the pressure differential varies across the
diaphragm, the potential varies in the electric
May 2011
This method appears to have certain
advantages:
* It is simple to construct and operate
* It is not easily clogged by lost circulation
material
* It is workable in almost any type of mud
* It can be used to locate a hole in the casing
The disadvantages are:
Radioactive surveys for the point of loss consist
of making two gamma ray surveys. A base log is
run before radioactive materials are introduced.
Afterwards, a slug of mud containing radioactive
material is pumped down the hole. A new log
is run and high concentrations of radioactive
material will be noted at the point of loss. This
method provides accurate data for locating the
point of loss, but requires expensive equipment
and additional deliberate loss of mud to obtain
the desired data.
3-6
circuit, thus indicating the rate of flow and
where the mud becomes static.
* Considerable mud flow is required
* The equipment may not be readily available
Open Hole Logs – Wireline
Open-hole logs can be used to indicate zones
of high mud invasion, which may be linked
to induced fractures. Logs also can provide
information regarding the mechanical
properties of the formation in the wellbore and
the directions of the minimum and maximum
stresses. While they do not give exact formation
strength, these logs offer a comparison among
the various formations. Thus, a formation
properties log can be qualitatively used to
identify weak zones quickly.
The sonic logs are particularly useful. The UBI
Ultrasonic Borehole Imager tool provides a
high-resolution image of the borehole, identifies
the orientation of any breakouts (washouts),
and shows any fractures that may be present.
Breakouts usually appear in the direction of the
minimum stress, whereas induced fractures
are perpendicular to the minimum stress
direction. The DSI Dipole Shear Sonic Imager
tool uses shear wave anisotropy in the rock to
determine the stress orientation. Since it does
not rely on wellbore failure, it therefore is more
reliable than other logs. Fluid invasion also can
be inferred from differences in the transit time
between LWD and wireline logs. If invasion
occurs, the previously slow sonic exhibits an
increase (i.e., wireline logs will indicate a slower
formation than the LWD log).
Detection and Analysis of Losses
In addition, the Compensated Dual Resistivity
(CDR) tool can be used for fracture detection,
but only if an invert emulsion mud is used.
This tool is unreliable in water-based drilling
fluids, because they have insufficient resistivity
contrast. The CDR measures deep and shallow
resistivities. This log can be run as part of the
LWD tool. A comparison with logs run later
on wireline can identify both post-drilling
fracturing or fracture healing.
Another useful logging tool in identifying losses
and fractures is FMI. With this tool, arrays of
electrodes are deployed on pads mounted on
four or six caliper arms and pushed against the
side of the well. The current measured at each
electrode indicates the contact resistance with
the well. FMI logs are unwrapped images of the
wellbore wall. Their position around the well
is shown in the abscissa while depth is shown
on the ordinate. For example, breakouts, vugs
or caverns appear as out-of-focus areas in FMI
logs, because of the poor contact of the electrode
arrays on the pads of the tool. Fractures or
bedding planes are shown as sinusoids on the
FMI images.
While locating the thief zone is good practice,
there are several reasons why surveys are not
run more often:
* Considerable time is spent in getting the
necessary equipment to the rig, and a
deliberate loss of mud is required for these
surveys.
* The survey results sometimes are difficult to
interpret.
* Conditions may not allow these tools to
be run because of abnormal subsurface
pressure.
Mud Loggers Chart
These data can provide an accurate record of
how and when the losses occurred. Offset well
log data also is very useful in this identification
process. The rig geologist often has offset log
data of the formation from adjacent wells,
which can help identify the cause and potential
location of the loss. The mud engineer can help
May 2011
in deciding whether any changes in the mud
properties are warranted.
Nature of the Loss Zone
It is very important to characterize the loss
zone(s) comprehensively. If done improperly,
chances are treatments will not be successful
in overcoming lost circulation. Knowing what
type of losses are occurring makes it possible to
determine the type of lost circulation material,
the probable position of the loss zone(s), and
whether any changes in the density and
properties of the mud or drilling practices are
necessary.
Downhole Tools
Downhole tools can provide significant
information and control. For example, the
drilling team might have access to real-time
annular pressure sensors, such as APWD
tools, to detect losses and identify the relative
location. Discontinuities in pressure trends
directly indicate a disturbance on normal
drilling parameters and potential loss zones.
Further, resistivity measurements (LWD tools)
use comparisons of offset wells or historical
measurements to help indicate fluid migration
to the formation.
An example would be a “square” response from
APWD measurements (Fig. 3-1) when the mud
pumps are turned on and off, indicating no
losses through fractures. When the pumps are
off, the ECD drops immediately and conversely
increase instantly when the pumps are on and
the system is “closed”. On the other hand, if a
non-square response is observed from APWD
data, as shown in Fig. 3-2, losses through
fractures are taking place. This non-immediate
response in pressure with the pumps on or off
results from the additional volume taken by the
fractures when the pumps are turned on, or else
by the closing of fractures when the pumps are
turned off, thus returning fluids to the wellbore.
A separation between the shallow resistivity
and the deep resistivity from LWD tools
indicates fluid migration to the formation, either
through fracture or matrix leak-off, as illustrated
Detection and Analysis of Losses
3-7
in Fig. 3-3. Since oil-based mud was used in this
example, a higher shallow resistivity than deep
resistivity indicates where the loss occurs.
Formation Characteristics
The characteristics of fractured impermeable
rock contrasts with those of permeable zones.
Typically, fractures are found in permeable rock
formations within a depleted sand or carbonate.
These fractures normally are more easily
“Sealed” or “closed” than those induced in tight
sands, siltstones, and shales. This is due in large
part to permeable formations having a higher
potential for filtrate loss and fracture plugging.
Field data compiled from lost-circulation events
within permeable formations show them
having a higher potential for filtrate loss and
fracture plugging.
Before initiating any preventive or remedial
treatment, it is important to identify the exact
nature of the losses.
* Loss rate while tripping is similar to
circulating
* Loss rate somewhat sensitive to pump rate
* With additional penetration, loss rate is
highly variable
* Loss may be associated with a drilling break
Losses Through Caverns
* Mud weight below fracture gradient
* Losses are instantaneous
* Loss may be associated with a drilling break
or immediately preceding the loss the bit may
drop from a few milimeters to a few meters.
* Excessive torque may be experienced before
loss
* Rock may have been subjected to
dolomitization or karstification
* Loss rate while tripping is similar to circulating
Losses Through Pores
* Occur in unconsolidated or high-matrix
permeability formations
* Occur when the solids content of the mud is
low
* Losses starts gradually and, with additional
penetration, build up to a maximum rate.
* A loss rate that is not appreciably higher
while tripping in
• A loss rate that is relatively insensitive to
pump rate
• Mud weight substantially below fracture
gradient
Losses Through Natural Fractures
* Mud weight substantially below fracture
gradient
* Formation is not of high matrix permeability
* With additional penetration, loss rate is highly
variable
Losses Through Induced Fractures
* Mud weight approximately equal to or
greater than fracture gradient
* Formation may be impermeable (such
a shale) and without a high matrix
permeability
* Likely to occur when encountering a change
in lithology, such as going from shale to
sandstone
* Losses start suddenly with a maximum
initial rate
* Loss rate is considerably higher when
tripping pipe
* Loss rate is very sensitive to pump rate
* Loss rate not associated with a drilling break
* Losses start suddenly
* Loss rate may increase exponentially with
time
3-8
May 2011
Detection and Analysis of Losses
Fig.3-1. PWD – No Fractures
Fig. 3-2. PWD - Fractures
Fig. 3-3. LWD – Higher Resistivity Indicates OBM Losses
May 2011
Detection and Analysis of Losses
3-9
Chapter 4 - Classification of Lost Circulation Materials
A number of approaches are employed to
classify lost circulation materials (LCM).
Most methods are based on some physical or
mechanical characteristic, such as:
•
•
•
•
•
•
•
•
Particle Size and Size Distribution
Particle Shape and Texture
Aspect Ratio
Compressive Strength
Bulk Density
Resiliency
Deformability
Destructibility
By far the most common criterion for classifying
LCM is size. Some LCM are supplied in three
grades related to size - Fine, Medium and Coarse.
Others are supplied in grades related to the
median particle size or D50. For easy reference,
Table 1 shows the approximate particle sizes for
some very common M-I SWACO LCM products.
Besides providing good fluid-loss control in
moderate-to-high-permeability formations, the
four OPTISEAL blends are designed to plug fracture
apertures up to 1,200 μm.
Table 4-1. Median Particle Size of M-I SWACO Granular LCMs
Product Name
C-SEAL
C-SEAL Fine
G-SEAL
G-SEAL HRG
G-SEAL HRG Fine
G-SEAL PLUS
G-SEAL PLUS Coarse
NUT PLUG Fine
NUT PLUG MEDIUM
OPTISEAL I
OPTISEAL II
OPTISEAL III
OPTISEAL IV
D50 (m)
100 - 50
20 - 40
300 - 350
450 - 550
25 - 55
200 - 500
400 - 500
1400 - 1600
500 - 600
500 - 600
500 - 600
500 - 600
500 - 600
Product Name
D50 (m)
SAFE-CARB 2
1-4
SAFE-CARB 10
60 - 15
SAFE-CARB 20
16 - 29
SAFE-CARB 40
31 - 48
SAFE-CARB 250
225 - 300
SAFE-CARB 500
430 - 520
SAFE-CARB 600
550 - 650
SAFE-CARB 750
655 - 800
SAFE-CARB 1400
1200 - 1550
SAFE-CARB 2500
2300 - 2700
VINSEAL Fine
50 - 90
VINSEAL Medium 250 - 350
VINSEAL Coarse
600-800
** Median Particle Size (D50) is reported as a size range due to variations in the manufacturing and grinding
process. Generally, particle size distributions are measured using laser light scattering if D50 < 100 µm and
dry sieve analysis if D50 ≥ 100 µm (as measured by dry sieve analysis). If a precise size distribution of a
product is critical to a drilling operation, it should be measured with the appropriate test procedure using
samples that are representative of those expected to be used in that operation. Nominal D10 and D90 values
are available from Houston Technical Services upon request.
* OPTISEAL I and II are designed as fracture
sealing and Wellbore Strengthening
Materials (WSM) in porous and fractured
formations while drilling with aqueous
fluids.
May 2011
* OPTISEAL III has been optimized specifically
for non-aqueous fluid (NAF) applications.
* OPTISEAL IV is composed of acid-soluble
marble for use in reservoir drilling
operations.
Classification of Lost Circulation Materials
4-1
Another way to classify LCM is by its physical
form and/or the manner in which it performs
downhole. To this end, LCM are classified as
either Particulates or Chemicals, and beneath
these there may be subcategories, such as:
Particulates
•
•
•
•
•
Fibers
Granules
Flakes or platelets
Mixed
High fluid loss squeezes
Soft and Hard Plugs
Gunk Squeeze
Reverse Gunk Squeeze
Barite/Hematite Plugs
VERSAPAC*
Miscellaneous
• POLYSWELL
• Sodium Silicate
Particulates
* NUTPLUG: Three grades of these pecan or
walnut shells (location specific) are available
- Fine, Medium and Coarse.
Fibers:
These materials have a relatively small degree of
rigidity and are thought to mat or entangle on
the surface or within a formation that is taking
fluid.
Examples: M-I-X II, M-I CEDAR FIBER, Sawdust and
Drilling Paper. Most of these materials are provided in
grades of Fine, Medium, and Coarse.
Granules:
Examples: Calcium Carbonate, Sized Salt, G-SEAL and
NUTPLUG.
* Calcium Carbonate: Different grades of
May 2011
Novel Materials: These LCM include highresiliency graphites - G-SEAL HRG, G-SEAL HRG
Fine
Flakes or Platelets:
Materials with a flat, layer-like appearance and
may have limited or no rigidity.
Examples: Mica, Phenoseal and Cellophane.
These are particulate materials of various
degrees of rigidity, rugosity and size. These
materials are able to bridge and wedge either
at the face of or within formations capable or
taking mud.
4-2
* Sized Salt: This LCM encompasses various
grades of salt, suspended in salt-saturated
solutions. They are used in pill form or as a
complete system, especially when drilling or
working over producing zones. The blocking
effect can be removed by the application of
fresh water and acid to dissolve the pill.
* G-SEAL: This graphite material comes in
Coarse grind size and may be used in both
water-based and invert emulsions. This
material has been applied successfully for
both natural and induced losses. Laboratory
and field studies indicate that G-SEAL
promotes fracture healing properties with
invert emulsions. Normally 28.5 kg/m3 is
carried in the active mud system to limit
losses to induced fractures. G-SEAL also has
proven beneficial for blocking permeable
formations and reducing the differential
sticking potential of the fluid. G-SEAL PLUS and
G-SEAL PLUS Coarse are graphite/coke blends
with bimodal particle size distributions.
Cross-Linkable Polymer Pills
•
•
•
•
ground limestone or ground marble used
to prevent seepage/partial losses. Since it is
acid soluble, calcium carbonate often is used
to reduce losses in producing zones.
* Mica: Can be one of several silicates of
varying chemical composition, but with
similar physical characteristics. All micas
tend to cleave into thin sheets that are
flexible and elastic. This material comes in
Fine, Medium and Coarse grades.
* Phenoseal: A thermoset, laminated, flaked
material, it comes in three grades: Fine
Classification of Lost Circulation Materials
(1190μ - 177μ), Medium (2000μ - 250μ) and
Coarse (4750μ - 850μ). This is a very rigid
material and will not degrade as fast as
mica.
* Cellophane: Flakes measuring on average
3/8-in. and manufactured from pure,
precipitated cellulose. The flakes are inert
and do not react with other mud products
and are not affected by crude oil and brines.
Mixed:
Examples: Diatomaceous Earth (DE), DiaSeal M, DE/
Attapulgite or Sepiolite Pills, FORM-A-SQUEEZE,
FORM-A-BLOK
Novel Material: High-shear-strength EMI-1820
Materials, which are mixes of fibrous, granular
and flaked material in one sack. These materials
offer the benefits of mixing all three materials
with regards to proper sizing.
Examples: M-I SEAL* (Fine, Medium and Coarse) and
Kwikseal (Fine, Medium and Coarse).
* M-I SEAL is a combination of granular, fibrous
and flaked in one sack. It is one of the most
widely used LCM, especially in water-based
muds. Although Kwikseal can reduce the
emulsion stability of oil-based muds, it has
been used primarily to cure losses in partial
or severe situations.
High-Fluid-Loss Squeezes:
The composition of this type of slurry is
engineered to dehydrate readily when squeezed
into the loss zone. The solids pack the fractures
forming a seal. A typical high fluid loss slurry
contains a mixture of diatomaceous earth,
bridging agents and barite suspended in either
water or oil.
These slurries are ideal for induced fractures
where external bridging is not paramount and
it is important to get a high pressure drop into
the fracture. Mud solids should provide the
necessary fines for bridging. In fractured, low
porosity formations, 30 kg/m3 of Fine fibrous
LCM usually is added. Coarse or granular LCM
should not be added as they may prevent
ingress of the diatomaceous earth into the
fracture or, if they do invade, may act as a
proppant.
May 2011
With these slurries, hydrostatic pressure often
is sufficient to seal the loss zone. A light squeeze
pressure (700 - 2000 Pa) may be applied to open
up and then seal fractures, which otherwise
would cause problems later. The basic slurry or
a slurry containing low concentrations of fiber
can be pumped through bit jets.
Cross-Linkable Polymer Pills
In polymer chemistry, when the polymer chains
are linked together by cross-links (bonds linking
one polymer chain to another) they lose some
of their ability to move individually. M-I SWACO
uses liquid or dry polymer chains that are
rehydrated and can be formed into a gel or solid
mass. Some types include sized particles that
will help reduce fluid loss to the formation.
* FORM-A-SET* and FORM-A-SET AK* are
polymer plugs that are cross-linked with
Cr+3, in which cross-links develop with time
and temperature. These plugs are designed
with a retarder for formation temperatures
over 25°C. The FORM-A-SET plug can be
weighted up to 2.16 sg, while the FORM-A-SET
AK plug can be weighted up to 1.92 sg. Both
plugs are thermally stable to 150°C. Care
should be exercised in or near the producing
interval as they cannot be degraded and
produced back.
* FORM-A-PLUG II* lost circulation plug is a
blend of cross-linkable polymers and borate
minerals designed for suspension and fluid
loss control. Cross-links develop with time
and temperature and can be designed with
varying concentrations of accelerators and
retarders to provide the optimal setting
time. In laboratory testing, the FORM-A-PLUG
II material was shown to be 95% dissolvable
when contacted with 15% HCl solution.
Classification of Lost Circulation Materials
4-3
Novel Materials:
Cross-linkable reversible or breakable polymer
squeezes.
* EMS-8320 is a urethane-based system that
is effective as both a lost circulation and
a wellbore strengthening material. It is a
seven- component system that forms an
oil-soluble gel and is well suited for both
permeable and non-permeable formations.
Typical setting time for the gel is 2-3 hours,
which is determined by the temperature
and the ratio of the components (a
chemical accelerant and retardant). This
system has an operational temperature
range of 20°-120°C. However, at higher
temperatures, more retardant is necessary,
is which decreases compressive strength.
It is compatible with both lost circulation/
prevention material and barite. Increasing
the density of the pill results in higher
compressive strengths.
* EMS-8420 is a HTHP water-based lost
circulation pill. It is a breakable pill
that consists of a gelling agent, a crosslinker, a retarding agent and acid soluble
weighting material (calcium carbonate or
ferrous carbonate). It has an operational
temperature range of 65-230°C and, likewise,
can be mixed in densities up to 2.16 sg.
Soft and Hard Plugs
Gunk Squeezes:
Oil/Bentonite (OB) or Conventional Gunk
Squeeze is a hydration-type plug with a high
concentration of un-hydrated clay material
(bentonite). This plug gels/thickens rapidly
when intermixed with the downhole fluid
or mud. Usually, these fluids are a mixture of
diesel and bentonite, which gel quickly when
intermixed with water-base mud or some
type of brine. Cement often is added to the
conventional Gunk mixture to add additional
strength to the final Gunk-mud material, thus
forming Oil/Bentonite/Cement (OBC).
4-4
May 2011
OBC is a hydration-type plug with a high
concentration of bentonite and cement mixed
with diesel where it hydrates when mixed with
water or brine to form a hard plug. The cement
allows the pill to develop compressive strength
over time. The ratio of bentonite and cement
can be varied to alter the final compressive
strength.
The final strength of OBC is determined by the
bentonite to cement ratio, the pumping ratio
of OBC down the drill string and the drilling
fluid pumped concurrently down the annulus.
Usually, the starting ratio of the fluid to OBC is
4 to 1 and produces progressively firmer plugs
as the ratio of fluid to OBC decreases to 1:3. The
4:1 ratio mix will produce a highly viscous fluid,
while the 1:3 mix produces a semi-soft to hard
plug.
OBC is applicable for lost returns where more
conventional lost circulation materials have
failed. OBC can be used with freshwater
and saltwater fluid systems (chlorides less
than 50,000 ppm). If the chloride content of
the drilling fluid exceeds 50,000 ppm, it is
recommended to use a 1:1 blend of attapulgite
and bentonite to reduce chloride sensitivity.
Reverse Gunk Squeezes:
Reverse Gunk Squeeze is another example of a
bentonitic squeeze. This treatment employs the
same method as the Gunk Squeeze. Unlike the
Gunk Squeeze, which can be used with waterbased muds, the Reverse Gunk Squeeze is used
only with NAF.
The treatment is applied by pumping the Gunk
fluid down the drill pipe or tubing to the end
of the string. With the annulus closed, the
treatment is pumped simultaneously down
the drill pipe and the annulus. Intermixing of
the Gunk fluid and the mud occurs at the end
and below the drill pipe, forming a gelatinous/
highly-viscous/thick mass that is squeezed
into the loss circulation zone. A Reverse Gunk
Squeeze fluid is a mixture of organophilic clay
(clay that is treated to swell in the presence
of NAF) and water, which rapidly gels when,
intermixed with a NAF downhole.
Classification of Lost Circulation Materials
The clay/water mixture is squeezed into
the formation, while the NAF is pumped
simultaneously down the annulus. The two
mix and cause the clay to swell and form an
impermeable zone. Although the slurry can be
weighted with barite, this is not recommended
since the effective concentration of clay will
be reduced with the volume of barite added.
Cement is not added to Reverse Gunk fluids
since it will not hydrate when contacted by an
NAF mud.
Barite/Hematite Plugs:
Barite/Hematite Plugs are another effective
means of sealing off active borehole sections
in extreme or emergency situations. They can
be inserted to provide an immovable sealing
column through either settling or dehydration,
thereby preventing further formation fluid
from intruding into the wellbore. Hereafter,
barite and hematite plugs will be referred to as
“wellbore plugs”. A wellbore plug is defined as
a slurry composed of either barite, hematite or
both and uses water or an NAF as the carrying
agent. The slurry is designed for the rapid
settlement of the weight material, thereby
forming a hard pack.
VERSAPAC:
VERSAPAC organic thixotrope is thermally
activated and sets up under static conditions. In
combination with ECOTROL* RD fluid-loss control
additive and LCM/WSM, it forms an effective
lost circulation pill when mixed in NAF systems.
When activated, VERSAPAC* produces a soft-set
ductile plug in the temperature interval 50°115°C. VERSAPAC has an advantage in that it can
be combined with LCM/WSM or WSM blends
available at the rig-site. Thus, it can be used as
a settable, reinforcing plug should conventional
remedial pill treatments fail.
Cement:
Cement is an inexpensive lost circulation
material, but can be very effective in sealing
lost circulation zones. It is critical, however, that
the treatment be performed properly to avoid
contaminating the cement. Cement composition
can be neat or with different additives to
vary properties, such as density, setting time,
filtration loss, bridging capabilities, gel strength
and compressive strength.
The primary application of a wellbore plug
is in a well control situation where a kick is
occurring in a lower zone and circulation is lost
simultaneously to an upper zone. There are
other special circumstances where wellbore
plugs may be utilized. The settling rate can be
affected by several factors, including density,
contaminants in the makeup water, variations
in weight material, pH, type of dispersant, and
the addition of surfactants.
Neat cement slurries, which are effective for
solving all types of losses, have the advantage
of providing high final compressive strength.
Normally, LCM is added for partial or total
losses. The size of the LCM is increased as
the losses become more severe. Low-density
cement systems can be used for any type of
lost circulation problem and have the added
advantage of reducing the hydrostatic pressure.
Slurries are formulated normally with a limited
degree of fluid loss control and may contain a
mixture of clays or diatomaceous earth.
The settling rate of a weight material/ water
slurry is inversely proportional to the density of
the slurry. Because of their high concentration
of solids and gel strengths, high density slurries
settle more slowly than low density slurries.
The optimum barite slurry weight is between
14.0 and 1.9 sg although the barite slurry can be
weighted up to 2.65 sg. When hematite is used
as the weighting agent, the optimum slurry
weight is 1.9 to 2.16 sg.
Pore pressure should govern the choice of
the slurry density, especially for circulation
lost to fractured or cavernous zones. To cure
lost circulation in these zones with cement,
a lower density slurry, preferably containing
LCM, should be used for the first attempt. Once
this system has sealed the larger fractures and
voids, hardened, higher density cement can be
pumped to consolidate the first job and provide
additional strength.
May 2011
Classification of Lost Circulation Materials
4-5
Miscellaneous Materials
POLYSWELL:
POLYSWELL* is a copolymer used to fill or seal
fractures. It expands up to 200 times its original
volume when hydrated in freshwater. Full
hydration takes 20 to 30 min., and as it fully
hydrates and expands the fracture/void is filled.
This product also can be spotted in caving zones
to reduce caving problems. After spotting a
POLYSWELL pill the pipe should be picked up above
the problem zone to prevent sticking. After
the copolymer is fully hydrated, mud and lostcirculation material (LCM) should be circulated
to fill the bridge. Because of its swelling capacity
and variability in size, POLYSWELL additive can
accumulate in a variety of fracture sizes. It can
be prehydrated before adding it to the system
and is an environmentally safe material.
POLYSWELL dry polymer beads can be mixed in
water or in drilling mud with or without LCM.
Formulations of 0.5 to 1.5 kg per 0.02 m3 of
water or mud are suggested, although lesser
or greater amounts have been used effectively.
Once the dry polymer beads are mixed, the
mixture should be pumped as soon as possible.
Repeat as necessary to stop fluid loss.
Sodium Silicate pills
Sodium Silicate pills often can be used to control
severe to complete losses in large fractures, vugs
and caverns. They can be paired with cement
pills, or can be used as a stand-alone solution. A
slug of sodium silicate solution can be spotted
into the formation, and followed with a spacer
of calcium chloride brine. When the calcium and
silicate make contact they react to form a stiff,
gelatinous mass that is competent enough to
block fractures.
4-6
May 2011
A cement pill can be pumped behind the
sodium silicate gel to act as a permanent seal.
Instead of pumping a calcium chloride spacer,
cement slurry is pumped as an alternative.
When the cement contacts the silicate, a flashset reaction occurs and the mixture solidifies in
a few minutes. This mixture has more strength
than a calcium silicate gel and may, but not
necessarily, eliminate the need for a follow-up
cement treatment. An alternative way to handle
this strategy is to first pump calcium chloride
brine, followed by sodium silicate and, finally
with cement. A freshwater spacer should be
placed between all the components.
Upon contact with connate water or the calcium
chloride pill pumped ahead, the sodium silicate
forms a crystalline insoluble precipitate of
calcium silicate and sodium chloride. To form
this precipitate, a divalent cation must be
present, usually in the form of Ca+2 or Mg+2. This
precipitate remains in situ and stops the cement
from flowing away until it sets. Also occurring
at the same time is the reaction of the unused
sodium silicate and the cement, which causes
the cement to flash set at the point of contact.
To avoid any flash setting inside special care
must be taken to avoid contact between
the silicate and calcium chloride and/or the
cement inside the surface lines, drill string or
casing. Therefore the use of a suitable spacer is
necessary (freshwater spacers can be used).
Classification of Lost Circulation Materials
Chapter 5 - Remedial Treatments
When lost circulation initially is experienced,
the drilling fluid density should be reduced, if
possible. The following method can be used
to estimate the maximum fluid density the
formation can withstand:
between wellbore pressure and pore pressure
(Pw-Pp).
* If the fluid level in the annulus falls when
the pumps are off, fill the annulus from
the top with a measured volume of water
or base oil, depending on the drilling fluid
system. Afterwards, calculate the new
gradient.
* If there are no returns when pumping:
• Fill the annulus from the top with water
or base oil
• Compare the circulating pressure (in
ksc or psi) prior to the losses occurring
(pressure P1) with the pressure at the
same circulating rate after the losses
have occurred (pressure P2). Length of the
empty hole in meters is calculated from:
10 (P1 – P2) / d
where P1 and P2 are standpipe pressure in
psi, and d is drilling fluid specific gravity.
* If the position of the loss zone is known, a
new drilling fluid gradient can be calculated
to balance the weakened formation.
* Reduce the ECD by lowering the pumping
rate or conditioning the fluid to deliver lower
gel strength and plastic viscosity.
* The rock may swell and the fractures
possibly seal themselves. If losses stop,
drilling can be resumed, though it is prudent
to reduce mud weight and/or pump rate.
If these measures fail to eliminate loss of whole
mud, treatment of the drilling fluid is indicated.
Indeed, seepage (matrix) losses may require
treatment under all circumstances. Seepage
losses usually occur in normal overbalanced
drilling in a highly permeable formation or
one possessing natural fractures. Here, the rate
of mud loss is proportional to the difference
May 2011
Large natural fractures or pressure-induced
(drilling induced) fractures can lead to partial or
severe mud losses. Pressure-induced fractures
typically are caused by a mud weight so high
that it exceeds the minimum principal stress or
fracture gradient and fractures open. However,
excessive annulus friction pressure or ECD,
wellbore pressure surges, imposed/trapped
pressure in the annulus or unexpectedly low
formation pressure can all contribute to lost
circulation. Since pressure-induced fractures
tend to open with increasing wellbore pressure,
the rate of mud loss is an exponential function
of Pw-Pp, and is proportional to (Pw-Pp)n, where
n > 1.
The flow chart and procedures (Fig. 5-1) are
designed to provide drilling fluid treatments
that should be applied when encountering
losses or when a reduction in drilling fluid
density cannot be achieved or fails to work.
Also, specific conditions may dictate changes
over time. Pilot tests should be run with all
treatments to ensure compatibility with mud,
effectiveness, etc.
Matrix (Seepage) Losses
Normally, loss rates lower than 1.5 m3/hr
are considered seepage, occurring usually
in unconsolidated and, highly permeable
formations (such as gravel beds) and those with
small natural fractures. They frequently are
observed at shallow depths. Often, this type of
loss is first observed as a gradual decrease in
pit levels, but can worsen rapidly if no action is
taken.
Seepage losses frequently are cured by simply
reducing or stopping the pump rate and
allowing the formation to heal and become
sealed off by the development of a filter cake.
The pump rate can be increased gradually after
the losses have stopped.
Remedial Treatments
5-1
5-2
May 2011
Remedial Lost Circulation Treatment
(For Short Loss Zones)
Matrix (Seepage)
Losses
Fractures
Severe or
Total Loss
Partial Loss
Water
Base
Fluid
Remedial Treatments
Spot Pill:
30 Kg/m³ M-I-X II (F)
20 Kg/m³ CaCO₃ (C)
20 Kg/m³ Nut Plug (F)
20 Kg/m³ Nut Plug (M)
15-30 Kg/m³ G-SEAL
(G-SEAL Plus)
Non
Aqueous
Fluid
Spot Pill:
30 Kg/m³ Vinseal (F)
30-60 Kg/m³ G-SEAL
(G-SEAL Plus)
30 Kg/m³ CaCO₃ (M)
30 Kg/m³ CaCO₃ (C)
Water
Base
Fluid
Spot Pill:
30 Kg/m³ M-I-X II (M)
30 Kg/m³ CaCO₃ (M)
30 Kg/m³ CaCO₃ (C)
20 Kg/m³ Nut Plug (F)
20 Kg/m³ Nut Plug (M)
15-30 Kg/m³ G-SEAL
(G-SEAL Plus)
FORM-A-SQUEEZE*
Cross Linked
Polymer Pills
FORM-A-SET*
SQUEEZE PLUG*
FORM-A-SET AK*
Attapulgite Squeeze
FORM-A-PLUG II*
Non
Aqueous
Fluid
Water
Base
Fluid
Non
Aqueous
Fluid
Spot Pill:
30 Kg/m³ Vinseal (F)
30 Kg/m³ Vinseal (M)
30-60 Kg/m³ G-SEAL
(G-SEAL Plus)
30 Kg/m³ CaCO₃ (M)
30 Kg/m³ CaCO₃ (C)
Spot Pill:
20 Kg/m³ M-I-X II (F)
20 Kg/m³ CaCO₃ (M)
20 Kg/m³ Nut Plug (F)
15-30 Kg/m³ G-SEAL
(G-SEAL Plus)
Spot Pill:
30-45 Kg/m³ G-SEAL
(G-SEAL Plus)
30 Kg/m³ CaCO₃ (F)
20 Kg/m³ CaCO₃ (M)
No
Success
No
Success
High Fluid Loss
Pills
Seepage
Loss
Soft Plugs
Gunk Squeeze
Reverse Gunk Squeeze
Chemical Sealant
for N.A.F
VersaPac*
Miscellaneous
POLYSWELL
Sodium Silicate-Cement
Diesel-Oil-Bentonite
Diesel Oil-Bentonite-Cement
Fig. 5-1. Remedial Lost Circulation Flow Chart
Large Particulates
Pump Conventional LCM Pill with
highest concentration and particle size
allowed by BHA. Pill will contain:
45-70 Kg/m³ Fiber (M-I-X II for WBM
and Vinseal for N.A.F ) + 85-140 Kg/m³
CaCO₃ (Medium and Coarse) + 45-70
Kg/m³ Nut Plug Medium
If losses do not heal by themselves and
economics or other reasons dictate the rate of
loss cannot be tolerated, an LCM pill must be
pumped to return full circulation.
Partial losses may, of course, also occur in
naturally occurring fractures or in formations
with very high permeability, even if the
wellbore pressure is not excessive. In
these instances, the following LCM pill is
recommended:
When drilling with a water-based fluid the
recommended pill to be used and spotted for
seepage losses is:
M-I-X II Fine
Calcium Carbonate Medium
NUT PLUG Fine
G-SEAL/G-SEAL PLUS
20
20
20
15-30
M-I-X II Fine
NUT PLUG Fine
NUT PLUG Medium
Calcium Carbonate (C)
G-SEAL/G-SEAL PLUS
kg/m3
kg/m3
kg/m3
kg/m3
Calcium Carbonate Fine
30
kg/m3
Calcium Carbonate Medium 20
kg/m3
G-SEAL/G-SEAL PLUS
30-45 kg/m3
If seepage losses are expected during drilling,
treating the whole drilling fluid system
with LCM before entering the loss zone is
recommended.
Such a treatment will depend on pore/fracture
size distribution in the loss zone, but a general
recommendation is to treat the system with:
VINSEAL (F)
Calcium Carbonate (M)
Calcium Carbonate (C)
G-SEAL/G-SEAL PLUS
30-50 kg/m3
15
kg/m3
20
kg/m3
While the grade of the fiber (M-I-X II or VINSEAL)
will depend on the losses, both Fine and
Medium are acceptable. For invert emulsion
muds, VINSEAL is usually recommended over
M-I-X II because the former does not absorb
water from the internal water phase.
Partial Losses
Losses from 1.5 m3/hr up to 15 m3/hr often are
referred to as partial losses. Typically, these
occur in existing (natural) or pressure-induced
fractures. The latter result when the wellbore
pressure exceeds the fracture pressure of the
formation. This may yield formation of cracks
in the rock and subsequent loss of fluid to the
formation.
May 2011
kg/m3
kg/m3
kg/m3
kg/m3
kg/m3
However, at the onset of losses, the bit should be
pulled off bottom and the pump(s) shut down.
After zeroing the stroke counter, the annulus
should be filled with either light mud or water,
after which the number of strokes required to
fill the annulus should be recorded. In addition,
at this point the well should be monitored for
flow. Although the formation should be given
the opportunity to heal by itself, if the LCM
pill does not heal the losses, the pill used for
severe or total loss of returns should be pumped.
For the initial treatment of partial losses, the
following formulation is recommended:
For non-aqueous fluids, the recommended pill
formulation to spot for seepage losses is:
Calcium Carbonate
G-SEAL/G-SEAL PLUS
Fiber
30
20
20
20
15-30
30
30
30
30-60
kg/m3
kg/m3
kg/m3
kg/m3
If this pill does not heal the losses, another pill
with Coarser particles is recommended, or else
the pill described under severe or total loss of
returns should be pumped.
Severe or Total Losses
Partial or total losses occur at any time or depth
when whole mud is lost to the formation.
In almost all circumstances when severe to
total losses (> 15 m3/hr) are encountered, it is
necessary to regain full circulation. Once well
control is established, the most effective method
for curing the losses can be determined.
It is important to match the type of LCM to the
type of loss, but the most successful approach
generally is to use a mixture of various LCM
types and grades. A dual pill (Coarse and
Remedial Treatments
5-3
Medium followed by Fine) should be considered.
As well control usually will be the priority, the
annulus must be filled from the top with either
drilling fluid, water or another lightweight
liquid. Unless the fracture is induced, losses
normally cannot be stopped by pumping
conventional LCM pills. The alternative is a
reinforcing plug or cement. In the absence of
information about the nature of the fractures,
an LCM pill often is the first choice, because, if
successful, it delivers a quick response and is
easy to apply.
For severe and total losses, the LCM
concentration in the pills should be at least
140 kg/m3. A 10-20 m3 treatment should be
tried initially. Great care must be taken to avoid
plugging the drillstring when using this LCM
concentration. It also is important to keep the
pits well agitated. A displacement rate of 1-2
m3/min should be used. Never stop pumping
until the LCM is displaced in the well with
particles that should be less than a third of
the nozzle size. Some tools and motors may
further resitrict particle size and type. In some
circumstances, increasing the viscosity of the
pills may be more beneficial than increasing the
LCM concentration.
A standard recommended formulation for
water-based muds is:
M-I-X II (M)
CaCO3 (M)
CaCO3 (C)
NUT PLUG (F)
NUT PLUG (M)
G-SEAL/G-SEAL PLUS
30
30
30
20
20
15-30
kg/m3
kg/m3
kg/m3
kg/m3
kg/m3
kg/m3
For NAF, one formulation that has proved
successful is the following:
VINSEAL (F)
VINSEAL (M)
CaCO3 (M)
CaCO3 (C)
G-SEAL (G-SEAL PLUS)
5-4
May 2011
30
30
30
30
30-60
kg/m3
kg/m3
kg/m3
kg/m3
kg/m3
NUTPLUG (F) and (M) may also be added at
concentrations of 20 kg/m3 each.
Planning – preparation and procedures – are
critical for handling severe losses.
Preparation
* When the drilling operation approaches
the loss zone, a pit should be dedicated
for LCM slugs. For severe losses, at least 16
m3 of usable volume should be built. LCM
material should be mixed to the maximum
concentration that can be agitated safely
and continually as it is essential this mixture
be agitated fully at all times.
* Large bags of LCM should be available to aid
in the rapid mixing of the pills.
* Ensure all restrictions in the BHA and at
surface have been reduced to a minimum.
Procedures
* On encountering severe losses, pump the
drilling fluid and LCM down the annulus,
and afterwards pump out the drill pipe. The
well should be monitored continuously.
* Close the annular preventer if the drilling
fluid level falls from sight.
* Pump and displace 16 m3 of the LCM pill.
Pump out of the hole while displacing the
LCM. The pipe should be kept moving to
prevent packing-off as cuttings descend
in the annulus. Monitor the pits when
pumping and displacing LCM. Do not rely on
pump strokes alone.
* Pull back to a safe location, preferably to the
casing shoe or at least to a depth where the
bit will be above the top of the LCM pill. This
is providing all the LCM stayed in the hole
(i.e., have a minimum of 16 m3of open hole
beneath the bit or size LCM pill accordingly).
* Monitor the displacement pressure at all
times. Attempt to keep the annulus full. Use
water/seawater if necessary. Displace all
Remedial Treatments
LCM from the drillstring. Displace to leave
the hole full of LCM across the loss zone.
* Circulate across the well head for at least
two hours. If the LCM has begun to work,
close the annular preventer and apply a light
squeeze pressure to force the LCM into the
fractures.
* If the treatment does not work, proceed
with a second particulate pill or consider
alternative treatments. These generally take
the form of mud gelling agents, reinforcing
plugs or cement. Begin preparing for this
contingency during planning of the well.
Alternative Treatments for Severe
Losses
of the material involves a swelling of the
initial “agglomerates” and a gradual release
of the individual oligomer chains (Fig. 5-1
stage 2). The oligomers associate with other
particulate material in the system to produce
the rheological effect. When fully activated, a
type of “micelle” structure is formed involving
the gelling agent and the other components in
the system. In the absence of shear and below
the temperature of activation, rheological
activity is minimal as the particles do not swell.
As the temperature rises, swelling begins to
take place and eventually a stable system forms
when equilibrium is achieved. The process takes
place much faster in the presence of shear and
temperature (Fig. 5-2 Stage 3). When the system
is fully activated, it remains stable even if the
temperature drops (Fig. 5-2 Stage 4).
VERSAPAC Formulation
Mud Gelling Agents
If the LCM pills are unable to stop the losses,
a reinforcing pill should be pumped. If total
losses are expected, always have a pill ready and
mixed prior to entering the zone. Since such
a pill needs to be spotted across the loss zone
to be effective, it is essential to determine the
exact location of the loss zone.
VERSAPAC* chemical sealant for NAF
This thermally activated gelling agent that will
generate viscosity and develop gel structure
as soon as the temperature exceeds 60°C. It is
important to keep in mind that the melting
point for VERSAPAC is 120°C, at which point
the material becomes ineffective. VERSAPAC is
activated by a combination of temperature and
shear (Fig. 5-1 stage 1). The gelling mechanism
VERSAPAC can be formulated in diesel, mineral
and synthetic oil. Laboratory tests showed it
possible to engineer a 100% oil-based drilling
fluid system, where both the rheology profile
and the fluid loss are controllable.
The VERSAPAC formulation in each fluid system
was as follows:
Base Fluid
VERSAPAC
ECOTROL*
M-I-X II/CaCO3
VERSAMUL
0.16
30
20
330
9
m3
kg/m3
kg/m3
kg/m3
kg/m3
Table 5-1 shows the rheology profile after each
drilling fluid system has been sheared to 80°C.
Table 5-2 shows the static shear test data after
Fig. 5-2. Schematic of Mechanism for VERSAPAC Gelation
May 2011
Remedial Treatments
5-5
Table 5-1. Typical Viscosity Profiles of OBM and SBM
Rheology
Units*
Diesel
Mineral
Synthetic
Diesel
Mineral
Synthetic
Temp
600 rpm
300 rpm
200 rpm
100 rpm
6 rpm
Celsius
Dial Reading
Dial Reading
Dial Reading
Dial Reading
50
90
60
45
30
50
45
28
21
14
50
69
40
30
21
50
79
45
35
23
50
55
35
26
19
50
59
44
35
22
Dial Reading
13
8
10
11
11
13
3 rpm
GELS 10’/10”
PV/YP
HTHP Fluid
Loss (120°C)
Dial Reading
lb/100 ft2
lb/100 ft2
12
12/14
30/30
7
8/11
17/11
9
14/16
29/11
10
12/15
34/11
10
8/10
20/15
11
16/20
15/29
ml/30 min
-
-
-
10
7
3
*Measured units are actually in° Fann: 1° Fann = 1.065 lb/100 ft2,
but in practical applications they are assumed to be equivalent.
Table 5-2. Static Shear Test Results for Mud Products in Non-Aqueous Fluids
Note: Static shear strength > 150 – indicating not pumpable.
Mud System
VERSAPORT
VERSAPORT
VERSAPORT
NOVAPLUS
NOVAPLUS
NOVAPLUS
Diesel
Diesel
Diesel
VERSAPAC
(kg/m3)
29
43
57
29
43
57
29
43
57
M-I-X II
(kg/m3)
14.3
14.3
14.3
14.3
14.3
14.3
14.3
14.3
14.3
ECOTROL
(kg/m3)
14.3
14.3
14.3
14.3
14.3
14.3
14.3
14.3
14.3
Static Shear
Strength (Pa)
24
56
114
29
62
108
33
63
85
Note: Static shear strength > 150 lb/100 ft2 indicates that the sample
suggests that the sample is not pumpable.
each fluid system had been sheared to 80°C
before being static aged for three hours.
Each mud system exhibited higher shear
strength with increased VERSAPAC concentration.
VERSAPAC also was tested in a consistometer to
more closely examine the effect of temperature
on setting behavior. The tests were conducted
with mineral oil, synthetic oil and diesel, the
results of which are displayed in Table 5-3.
5-6
May 2011
Note: The tests were run in a Chandler
consistometer with a setting pressure of
20,680 kPa and a heating period of 30 min.
With this test, a reading of 70 Bearden units of
consistency (Bc) was the upper limit that would
still enable pumpability of the fluid, and 100 Bc
was the endpoint where the set was considered
complete.
Remedial Treatments
Table 5-3. Consistometric Test Results for Mud Products in Non-Aqueous Fluids
Mud System
VERSAPORT
VERSAPORT
NOVAPLUS
NOVAPLUS
Diesel
Diesel
VERSAPAC
(kg/m3)
57
57
57
57
57
57
M-I-X II
(kg/m3)
14.3
14.3
14.3
14.3
14.3
14.3
ECOTROL
(kg/m3)
14.3
14.3
14.3
14.3
14.3
14.3
Temp.
(°C)
75°C
120°C
75°C
120°C
75°C
120°C
Set up
(Hours)
3.5
No set
3.5
No set
3.5
No set
Limitations
The results clearly demonstrate the effect
of temperature. As shown, so long as the
temperature is in the range of 60 to 100°C
the VERSAPAC will set up. Conversely, when the
temperature exceeds 100°C and continues
to increase toward the critical melting point
temperature of 120°C, it will not set.
The temperature range for this system is
therefore 60° to 100°C. When the VERSAPAC is
totally activated, it remains stable even if the
temperature drops below 60°C.
Figure 5-3 shows the thickening time for the
various LCM plugs tested on the consistometer.
All samples were tested at 75°C. For comparison,
the graph also plots a cement plug. As the graph
indicates, the thickening times for drilling fluid
and cement is different; but the final endpoint
(100 Brabender Consistometer units) eventually
will be reached for all the samples, and thereby
form the plug.
It is recommended that the standard VERSAPAC
formulation be used when mixing the drilling
fluid (see Formulation). Of course, a different
concentration of VERSAPAC will influence the
rheology profile. The larger the vugs/fractures
that have to be sealed, the higher the desired
rheology/static shear. A small amount of
emulsifier should be added to the pill to
Recommendations
Fig. 5-3. Thickening Rate for three NAFs
May 2011
Remedial Treatments
5-7
emulsify any formation water incorporated, as
well as help oil-wet solids.
from the active mud system.
Reinforcing Plugs
Reinforcing Plugs can take on many forms,
including High-Fluid-Loss pills, Soft Plugs (gunks
and crosslinked polymers) and Hard Plugs
(usually crosslinkable polymers).
High-Fluid-Loss Pills, Soft Plugs
* Gunk and Reverse Gunk Squeezes
The ready availability of the necessary
materials is the principle reason for including
this treatment in the contingency plan. Thus,
in an emergency, these materials invariably
are stocked on the rig. The “Gunk” is simply
a mixture of clay and a fluid dissimilar to the
active drilling fluid system. When mixed with
the fluid lost in the thief zone, the Gunk forms
an impermeable plug that seals off the borehole.
Prior to mixing the pill, the mud pit, mixing lines
and mud pump suction lines must be flushed
and cleaned thoroughly and drained and as dry
as possible. This is a time consuming job that
requires a substantial amount of effort.
A Gunk squeeze to be used with water-base
drilling fluid is formulated with bentonite and
diesel (or base oil). Conversely, when using a
Gunk squeeze in an oil-base drilling fluid, it is
formulated with organophilic clay and water.
The bentonite will not yield in diesel (or base
oil) and the oil-wet organophilic clay will not
yield in water, thus resulting in a high-solids/
low-viscosity mixture.
May 2011
The treatment is applied by pumping the Gunk
fluid down the drill pipe or tubing to the end of
the string. When the Gunk squeeze reaches the
bit, the annular preventer should be closed. The
Gunk fluid should be pumped down the drill
pipe while simultaneously pumping the drilling
fluid in the annulus at an equivalent flow rate.
Intermixing the Gunk fluid and the drilling
fluid occurs at the end and below the drill pipe,
forming a gelatinous/highly viscous/thick mass
that is squeezed into the loss-circulation zone.
This treatment essentially has no temperature
limitation.
Normally, the Gunk fluid can be mixed and
pumped with little difficulty. In water-base
drilling fluids, cement often is added to
the conventional Gunk mixture to provide
additional strength to the final Gunk/drilling
fluid combination. To ensure the proper
consistency of the final mixture, the Gunk fluid
must be tested on location with the drilling fluid
in the hole. In addition, the ratio of Gunk to
drilling fluid needs to be optimized on location
using mixing tests to select the proper pump
rates during the operation.
The advantages of utilizing the Gunk Squeeze
technique include:
The dissimilarity of the fluids in the Gunk
squeeze and the active drilling fluid system
is the reason it is essential that the mud pit
and mixing system be cleaned thoroughly
beforehand. Contamination of the pill with
active drilling fluid easily can result in a mixture
that cannot be pumped in the mud pit. This
dissimilarity also means the pill must be
displaced with spacers of at least 1.6 m3, both
before and after, thereby separating the pill
5-8
The fluid used to formulate the pill also should
be used for the spacers and, for practical
purposes, usually are unweighted. Since
bentonite and organophilic clay are not acid
soluble, they are regarded as a conventional,
non-acid soluble treatment.
1. Needed materials typically are readily
available.
2. Technique is not sensitive to temperature.
3. Effectively seals off severe/total loss
circulation when applied properly.
Remedial Treatments
2. Pump in a 1.59 m3 cushion of water-free
diesel oil ahead of the slurry.
Special Considerations
1. Exposure of Entire Loss Zone: The entire
lost circulation zone must be drilled
and fully exposed before the treatment.
Otherwise, the treatment is unlikely to
work.
2. Contamination: Extreme care must be
taken to ensure the Gunk treatment fluid
is not contaminated with a fluid that
would cause premature gelation in either
the surface equipment or the drill string.
Before pumping the Gunk fluid, mixing
and pumping equipment must be drained
and flushed with appropriate materials (for
example, diesel for a conventional Gunk
treatment). A sufficient volume of the flush
needs to be pumped ahead of and behind
the Gunk fluid.
3. Waiting Time: Once the treatment
is squeezed into the zone of interest,
circulation of the hole and resumption of
drilling operations should not begin for
at least three hours. This will allow the
treatment fluid to fully yield and provide
maximum resistance to further losses.
Table 5-4. Mixing Chart for Gunk
Final Volume
3.18 m3
3.97 m3
4.77 m3
5.56 m3
6.36 m3
Diesel
Volume
2.54 m3
3.18 m3
3.82 m3
4.45 m3
5.09 m3
Bentonite
1140 kg/m3
1140 kg/m3
1140 kg/m3
1140 kg/m3
1140 kg/m3
The final density of the pill will be ± 1198.26 kg/
m3. The final viscosity will be ± 40 seconds.
4. Displace the slurry down the drill pipe,
followed by 0.8 m3 of diesel oil. When the
front of the 1.6 m3 diesel oil cushion in the
drill pipe enters the bottom of the open
hole, close the rams and, using a second
pump, begin pumping drilling fluid into the
annulus at a rate of 38 m3/hr.
4. Gunk Placement: Although the drill string
needs to be placed close to the loss zone,
care must be taken to make sure none of
the fluid circulates above and around the
drill pipe. Gelled fluid around the drill pipe
increases the risk of sticking problems.
Diesel – Oil – Bentonite (DOB) Gunk
A conventional Gunk Squeeze fluid is a mixture
of bentonite and diesel, which gels rapidly when
mixed with water-base drilling fluid or some
type of brine.
The following procedure should be followed for
a Diesel – Oil – Bentonite Gunk Squeeze:
1. If possible, before tagging the loss zone,
plan for losses and pull out of the hole,
install large nozzles and lay down MWD
and mud motor. This will enable pumping
of the Gunk.
May 2011
3. Mix 200 sacks (45.4 kg/sx) of bentonite
with 8 m3 of diesel oil. For smaller volumes,
use Table 5-4. Generally, mix four sacks
of bentonite for each barrel of diesel oil.
Mixing can be carried out continuously
with a cementing truck. For severe loss
zones, 600 sacks of bentonite in 23.8 m3
of diesel oil mixed continuously should be
used.
5. Control the pumping rates so the ratio of
slurry volume to drilling fluid volume is 1:1.
Pump rates of 38 m3/hr down the drill pipe
and 38 m3/hr down the annulus usually
will be satisfactory with 127 mm drill pipe
in 216 mm and larger holes.
6. Displace one-half the slurry into the
formation at this fast pumping rate or until
pressure begins to build up on the annulus.
Once the desired pressure is obtained, start
pulling off-bottom so the drill string does
not get stuck in the Gunk. Slow the pump
rates on both the drill pipe and annulus
until the slurry enters the loss zone without
exceeding the maximum pressure set (690
to 2070 kPa). The drill pipe occasionally may
Remedial Treatments
5-9
be reciprocated slowly, which will make
it possible to observe whether the slurry
is moving up the annulus. If the weight
indicator shows any increased drag, break
the connections and raise the pipe until it
is free. Afterwards, make connections and
continue displacement. Since the slurry has
no pumping time limitation inside the pipe,
there is no concern over short shutdown
periods.
7. Displace the next quarter of slurry volume
and drilling fluid at one half the rate used
in Step 6.
8. Displace the last quarter of slurry volume
at a rate of one-half the rate used in Step 6.
Use a hesitation squeeze to try and build
up pressure. When pressure buildup is
achieved, open both rams and stage-up
pumps and circulate out long way any
DOB Gunk that might have moved up the
annulus above the bit. Do not reverse out,
as it will set up inside the drill pipe.
9. After the squeeze job, dress the Gunk
down to 3 m above the loss zone. If no
squeeze pressure develops, use a diesel oilbentonite-cement squeeze.
Precautions
Avoid contaminating the slurry with fluid
or water in the suction lines and pumps. The
following steps will minimize the possibility of
contamination:
1. Field test for diesel oil suitability.
2. Fill a sand content tube with diesel to the
20% line.
3. Add water to the “mud to here” line.
4. Shake vigorously for 10 sec, then allow it to
stand for 10 min.
5. If the oil and water separate into two
distinct layers, the diesel is suitable for
use. However, if the fluid separates into
three layers with the oil on top, the water
on bottom, and a white emulsion in the
middle, the diesel is unsuitable and should
not be used.
5-10
May 2011
6. Prior to mixing, drain all water and drilling
fluid out of all pumps, lines and tanks.
Alternatively, use a batch mixing tank and
the cement line and unit to mix and pump
the DOB Gunk.
7. Use 0.65 m3 of diesel oil to thoroughly flush
the pumps, lines and mixing facilities.
Diesel – Oil – Bentonite – Cement (DOBC)
Slurry Squeeze
This technique is recommended for complete
losses. The following steps should be used in
applying the DOBC technique:
1. Before tagging the loss zone, plan for losses,
if possible, pull out of the hole, install large
nozzles and lay down the MWD and mud
motor to enable pumping of Gunk.
2. Run in hole and position bit 5 m above the
loss zone.
3. Pump in a 1.6 m3 cushion of water-free
diesel oil ahead of the slurry.
4. Mix 100 sacks of regular cement and 100
sacks of bentonite with 8 m3 of diesel oil.
For volumes other than 8 m3, mix 2 sacks of
cement and 2 sacks of bentonite with each
bbl of diesel oil. For large fractures of long
sections of honeycomb, 300 sacks of each
material should be used.
5. For large batches, use a cementing unit
and mix the dry materials with the diesel
oil continuously; use a suitable tank for
smaller batches. This mixture will yield
0.22 m3 of slurry for each barrel of diesel oil
and weigh almost 1400 kg/m3.
6. Displace the slurry down the drill pipe and
follow it with 0.8 m3 of diesel oil.
7. Start pumping drilling fluid into the
annulus when the 1.6 m3 cushion of diesel
oil reaches the bit. Close the rams. Control
the pumping rates so the ratio of the slurry
volume to the mud volume is 2 to 1. Pump
rates of 36 m3/hr down the drill pipe and
0.3 m3/min down the annulus will usually
be satisfactory with 12.7 mm drill pipe in
21.6 mm and larger hole sizes.
Remedial Treatments
8. Displace one-half of the slurry into the
formation at this fast pumping rate. The
drill pipe occasionally may be reciprocated
slowly to provide an indication if the slurry
is moving up the annulus. If the weight
indicator shows any increased drag, break
the connections and raise the pipe until it is
free; then make connections and continue
displacement. Since the slurry has no
pumping time limitation inside the pipe,
there is no need to be concerned over short
shutdown periods.
9. Displace the next quarter of the slurry
volume and drilling fluid at one-half the
rate used in Step 8.
2. Prior to mixing, drain all the water and mud
out of all pumps, lines and tanks. Use a
batch mixing tank and the cement line and
unit to mix and pump the DOBC.
3. Use 0.636 m3 of diesel oil to thoroughly
flush the pumps, lines and mixing facilities.
Reverse Gunk Squeeze
10. Displace the remaining quarter volume of
slurry at one-half of the rates used in Step 8.
If the hole fills, as indicated by pressure on
the annulus, use a hesitation squeeze in an
attempt to obtain a pressure buildup using
rates of 9.6 m3/hr into drill pipe and 4.8 m3/
hr into annulus.
11. If pressure builds up, open rams and stage
up pumps and circulate out long way
any DOBC that might have moved up the
annulus above the bit. Do not reverse out, as
it will set up inside drill pipes.
A “Reverse Gunk” is simply a mixture of
clay and a dissimilar fluid that, when mixed
with the fluid lost in the thief zone, forms an
impermeable plug that seals off the borehole. A
Reverse Gunk for use in an oil-base drilling fluid
is formulated with organophilic clay and water.
The organophilic clay will not yield in water,
thus resulting in a high solids low-viscosity
mixture.
Note: Reverse Gunk treatments usually are not
compatible with MWD tools.
Typical Formulation
1. Water as required
2. Organophilic Clay 650 kg/m3
3. Barite as required
12. After the squeeze job, pull the string to
the shoe and wait on the cement to set a
minimum of eight hours before dressing
it off. If the first attempt is unsuccessful,
repeat the procedure after waiting on the
cement for 8 hrs.
See Table 5-5 for details of a typical Reverse
Gunk pill.
Table 5-5. Mixing Chart for Reverse Gunk
Precautions
Avoid contamination of the slurry with mud
or water in the suction lines and pumps. The
following steps will minimize the possibility of
contamination:
1. Field test for diesel oil suitability.
• Fill a sand content tube to the 20% line with
the diesel.
• Add water to the “mud to here” line.
• Shake vigorously for 10 sec, then allow to
stand for 10 min
• If the oil and water separate into two distinct
May 2011
layers, the diesel is suitable for use. However,
if the fluid separates into three layers with
the oil on top, the water on bottom and a
white emulsion between them, the diesel is
unsuitable and should not be used.
Final Volume
3.18 m3
3.97 m3
4.77 m3
5.56 m3
6.36 m3
Remedial Treatments
Diesel
Volume
2.54 m3
3.18 m3
3.82 m3
4.45 m3
5.09 m3
Bentonite
570 kg/m3
570 kg/m3
570 kg/m3
570 kg/m3
570 kg/m3
5-11
Mixing Procedure
organophilic clays and base oils to determine
the best formulation for the Reverse Gunk.
Following is the mixing procedure for Reverse
Gunk Squeeze treatment:
Choosing the Right Organophilic Clay
3
1. 3.2 to 6.4 m is the optimum pill volume
and usually can be mixed in the slug pit. All
of the materials are mixed freely through
a standard hopper, although the mixing
will be more difficult as the material
concentration increases.
2. Flush and clean out the mud pit and mixing
system. Ensure the mud pit, mixing lines
and mud pump suction lines are drained
and as dry as possible.
3. Add the required volume of water.
4. Add the required amount of organophilic
clay, as indicated in Table 5-5, and circulate
for a homogeneous mixture.
Operational Procedure
1. Run in until the bottom of the drill string is
above the thief zone.
•
•
•
•
Bentone 128
Bentone 38 Versagel HT
Geltone II
VG-69
With the exception of the base oils, the
components were mixed together in a Hamilton
blender. Afterwards, the base oil was stirred in by
hand. The resulting Gunk formed very quickly.
Successful Gunking can be achieved with any
of the base oils examined and with the drilling
fluids formulated with these base oils. However,
it is clear that Gunks derived from Bentone
128 or Geltone II have superior properties for
successful plugging of lost circulation zones
than those built with VG-69 or Bentone 38.
Thus, it is recommended that Bentone 128/
Geltone II be employed for all reverse Gunking
applications.
2. Pump and displace so the entire pill is
outside the bottom of the drill string. Pump
at least 1.6 m3 of water, both before and
after pumping the pill.
Other Non-Crosslinkable Solutions
3. Pull out so the bottom of the drill string is
inside the last casing shoe.
Sodium Silicate/Cement, POLYSWELL, SAFELINK,
Barite/Hematite Plugs
4. If the hole is full, close the annular rams and
squeeze the pill into the thief zone at 2070
to 3450 kPa. Squeezing should stop once the
total pill volume has been squeezed away.
5. If the hole is not full, close the annular rams
and pump the pill at 0.16 m3/min down
the drill pipe. The drilling fluid should be
pumped at 0.16 m3/min down the annulus.
6.
Allow at least 4 hr for the plug to set.
7. Run in and carefully wash and ream
through the thief zone.
Note: Ensure the entire pill is pumped out of the
string. Do not attempt to reverse circulate.
Choosing the Right Organophilic Clay
Several tests were conducted with different
5-12
Optimization tests were conducted with
different base oils and organophilic clays,
including:
May 2011
Sodium Silicate / Cement Plugs
For severe lost circulation in which pevious
treatments have been unsuccessful, a
combination of calcium chloride, sodium silicate
and cement can be used.
Calcium chloride is pumped first to wet the rock,
followed by sodium silicate and the cement.
A freshwater spacer should be incorporated
between all the components. When the sodium
silicate comes in contact with the calcium
chloride brine it forms a gelatinous mass, thus
providing a pad for the cement to set up against.
Any unused sodium silicate will then flash set
with the cement, resulting in either partially or
fully sealing off the loss zone.
Remedial Treatments
The application of sodium silicate without
cement may allow some pressure to be applied
to the well, but usually not enough to offer any
great advantage.
Calcium Chloride Pre-flush
In formations where the rock is not waterwet, the effectiveness of the sodium silicate
treatment may be limited. To overcome these
limitations a pill of calcium chloride (about onehalf to equal the volume of the sodium silicate)
can be pumped ahead of the sodium silicate to
wet the rock with calcium ions. Caution must
be exercised when attempting this procedure
to ensure no calcium chloride comes in contact
with the sodium silicate in the surface lines or
drill string. If this procedure is used, pump the
calcium chloride with the rig pumps and use
the cement unit on the annulus to pump the
sodium silicate and cement. Use a hesitation
squeeze to try and build up pressure using rates
of 9.6 m3/hr into the drill pipe and 4.8 m3/hr into
the annulus.
Chemical Mechanism
Upon contact with connate water or the calcium
chloride pill pumped ahead, the sodium silicate
forms a crystalline insoluble precipitate of
calcium silicate and sodium chloride. To form
this precipitate divalent cation must be present,
usually Ca+2 or Mg+2. This precipitate remains
in place and prevents the cement from flowing
away until it sets. Also occurring at the same
time is a reaction of the unused sodium silicate
with the cement, which causes the cement to
flash set at the point of contact.
Following the recommended operational
procedures for pumping this treatment are
critical, as it is essential that the cement and
sodium silicate remain separated until they
reach the loss zone. A freshwater spacer is
used for separation between all the pills to be
pumped. Placement is designed to leave the
cement in the wellbore across the loss zone to
counteract its tendency to leak away. The spacer
is then squeezed away, providing a bridge has
formed.
May 2011
After the sodium silicate/cement treatment
been placed, the pipe should be kept well
clear of the cement (depending on placement
location, always pull back to the casing shoe or
farther). Caution should be exercised to avoid
disturbing the treatment.
Preparation
1. Flush all tanks and lines with drill water
ensuring they are all clean. Use a dedicated
tank to hold the liquid sodium silicate. The
cement and sodium silicate must never
come in contact while pumping. Sodium
silicate must be maintained clear of salt
water and calcium chloride brine, which
this will generate an undesirable gelatinous
precipitate.
2. For a visual demonstration of what
happens when salt water and calcium
chloride brine are mixed with cement and
sodium silicate, place the solution it in a
glass jar and add some cement. The visual
result magnifies the need to segregate
these two chemicals.
3. Prepare the sodium silicate in the dedicated
cement batch tank. Mix at least 12.72 m3
dead volume of 50:50 by volume sodium
silicate and fresh water. This applies to all
types of sodium silicate.
4. Prepare mix water and additives for
standard 6.36 m3 “G Neat” slurry at 1.90 sg.
Final slurry composition is to be advised
after testing in the cement company lab.
5. Ensure the BHA has been checked for
restrictions. There should be no nozzles in
the bit or floats, motors, or logging tools in
the string.
6. Double check all depth and volume
calculations.
Procedure
1. Pull back to the casing shoe while filling the
annulus with fresh mud (or fresh water/sea
water, if necessary) as fast as possible.
Remedial Treatments
5-13
2. Space out drill string to above the loss zone.
Place the bottom of the drill string at a
height above the zone that is equal to the
pill volume. For example, (A 310 mm hole
has a volume of 7.8x10-3 m3/m, and for a
20.7 m3 pill, enabling the bottom of the drill
string can be placed 271.2 m above the thief
zone). Close the annular preventer.
7. Stop pumping down the kill line and flowcheck the well. Open the annular preventer
and move the pipe back to the casing shoe
or 152.4 m above the placement depth.
Wait on cement and monitor the well. Keep
the hole full of mud or fresh water/sea
water, monitoring volumes of each fluid
pumped into the well.
3. Pump down the annulus to fill the riser. At
the same time, pump down the kill line to
maintain wellbore hydrostatic and prevent
the U-tubing from backing up around the
drill string when the treatment exits the
bit.
8. Repeat the procedure as required until
losses are cured. While use progressively
larger treatments may be used, if necessary,
a greater number of small treatments may
be more effective.
4. Rig up circulating head and pressure test
line.
5. Pump the sodium silicate/cement plug as
follows:
Fresh water Pre-flush
10% CaCl2
Fresh water
Sodium silicate
Fresh water spacer
G-Neat @ 1.90 sg
Fresh water
Mud displacement
6.36
1.59
0.79
3.18
0.79
6.36
0.79
xx
POLYSWELL LCM Pill
POLYSWELL* is a copolymer used to fill or seal
fractures. It expands up to 200 times its original
volume when hydrated in freshwater. Full
hydration takes 20 to 30 min, and as it fully
hydrates and expands, the fracture/void is filled.
This product also can be spotted in caving zones
to reduce caving problems.
3
m
m3
m3
m3
m3
m3
m3
m3
An individual should be assigned to observe
the batch tanks and continuously check on
the volume of the sodium silicate pumped.
Do not rely solely on the cement pump
strokes.
6. Displace the treatment. Monitor pressures
and be prepared to slow down the injection
rate as the treatment hits the loss zone.
Continue pumping the treatment out of
the drill pipe and into the open hole, even
if further losses are induced. Ideally, all the
treatment should be displaced from the
drill pipe before it reaches the loss zone.
As the sodium silicate and cement
start to exit the drill pipe, reduce the
pump rate down the kill line to prevent
cement contamination. At any stage of
the operation, never attempt to reverse
circulate if the job cannot be completed, as
it is likely to set up inside the drill string.
5-14
May 2011
9. Once surface cement samples are set, RIH
and drill out cement. Continue to drill
ahead while observing for losses.
To prevent sticking after a POLYSWELL pill is
spotted, the pipe should be picked up above the
problem zone. After the copolymer is hydrated
fully, mud and lost- circulation material (LCM)
should be circulated to fill the bridge. Because
of its swelling capacity and variability in size,
the POLYSWELL additive can accumulate in a
variety of fracture sizes. It can be pre-hydrated
before being added to the system. Further,
POLYSWELL is an environmentally sound material.
For the initial LCM pill design, SUPERSWEEP* (cut
nylon rope) was mixed into the slurry to help
bind all LCM in the pill. POLYSWELL was added
last and immediately before the pill was
pumped down the drillstring with the following
composition:
M-I GEL
Cottonseed Hulls
KWIKSEAL* (C)
SUPERSWEEP
Remedial Treatments
60 kg/m3
40 kg/m3
30 kg/m3
15 kg/m3
POLYSWELL
Mica (C)
20 kg/m3
15 kg/m3
SAFE-LINK LCM Pill
Although SAFE-LINK is generally considered a
“completion fluid” product, it possesses many
of the attributes of POLYSWELL, i.e. it is a crosslinked polymer with a gelatinous character that
can serve to plug pores and fractures. It has the
additional advantage of being breakable with
acid.
Barite/Hematite Plugs
Barite/Hematite plugs are effective in sealing
off active borehole sections in extreme or
emergency situations. They can be administered
to provide an immovable plug through either
settling or dehydration, thereby preventing
any further formation fluid intrusion into the
wellbore. Barite and hematite plugs often
are referred to as “wellbore plugs”. They are
prepared as a slurry composed of barite,
hematite or both, mixed in water or diesel oil,
mineral oil, or synthetic as a carrier.
The slurries are designed for the rapid
settlement of weight material, forming a hard
pack. The primary application of a wellbore plug
is in well control situations where the well is
kicking from a lower zone and simultaneously
losing circulation to an upper zone. The wellbore
plug will allow safe withdrawal of the drill pipe
before setting a cement plug. The cement plug
should normally be 1890 kg/m3 or 10 % above
the current mud weight, whichever is higher.
Cement should not be pumped until no gas
remains in the wellbore. Otherwise, the gas
migration may compromise the cement plug.
Circumstances other than well control also are
candidates for the use of wellbore plugs.
If the wellbore plug is made up using water,
only freshwater should be used, because the
gel strength of the plug increases with salinity
and hardness. It is important the barite in the
plug is able to settle out at the bottom of the
wellbore. The settling rate of wellbore plugs also
can be affected by a number of other factors,
such as density, contaminants in the make-up
May 2011
water, variations in weight material, pH, type
of dispersant, and the addition of surfactants.
The settling rate of a weighting agent slurry
is inversely proportional to the density of the
slurry. As such, high-density slurries settle
slower than low-density slurries, because of the
high concentration of solids and gel strengths.
The optimum Barite slurry weight is between
1670 kg/m3 and 1920 kg/m3, although a barite
slurry can be weighted up to 2640 kg/m3. When
Hematite is used as the weighting agent, the
optimum slurry weight is 1920 kg/m3 to 2160
kg/m3. These slurries should be treated with
thinner (lignosulphonate) to ensure settling
and caustic to control pH. Both the thinner and
raised pH will aid settling.
Cross-Linkable Pills
FORM-A-SET FAMILY OF PRODUCTS
The FORM-A-SET family of chromium-crosslinked
products form particulate-laden, rubbery plugs
to stop losses into matrix and fractured zones.
It has three members with distinctly different
properties. FORM-A-SET is a one-sack blend of
polymers, cellulose and crosslinker with a
wide range of particle sizes. It can be used to
solve a wide range of lost circulation problems,
especially when the size of the downhole
openings is not known. FORM-A-SET AK is a blend
of polymers and smaller fibrous materials
designed to plug fine-to-medium sized deep
fractures and faults. DUO-VIS* biopolymer
provides suspension. It does not contain
crosslinker, and so can be made up in advance as
a contingency. FORM-A-SET AKX comprises coarse
calcium carbonate and a high polymer loading
to create mechanically stronger plugs. It does
not contain crosslinker and can also be made up
in advance.
FORM-A-SET
FORM-A-SET is a one-sack blend of polymers,
cross-linkable agents, and fibrous lost
circulation materials designed to plug matrix
and naturally fractured or vugular zones. When
activated with time and temperature, FORM-A-SET
produces a rubbery, ductile and spongy soft set
Remedial Treatments
5-15
gel that effectively prevents loss of fluid to the
formation.
be added to the water before the FORM-ASET material. Table 5-7 shows the typical
concentration for the retarder.
Two products are available with the material
to help control the setting times: FORM-A-SET
RET* and FORM-A-SET ACC*. FORM-A-SET RET is a
retarder designed for situations requiring longer
setting or pumping times and higher squeeze
temperatures. An accelerator, FORM-A-SET ACC is
engineered for situations where set conditions
are faster or lower water temperatures will not
allow the polymers to hydrate.
Application
FORM-A-SET can be used in any applications
where a squeeze plug would be
It particularly is advantageous in areas where
loss of whole drilling fluid is prevalent. FORM-ASET also may be employed to shut off water flows
and stabilize gravel sections. Equally effective in
vertical and horizontal wellbores, FORM-A-SET can
be weighted with M-I BAR* or FER-OX. FORM-A-SET
can be used to shut off losses to depleted sands
and isolate gas/water zones.
The following formulation for a Barite/Hematite
Plug is recommended:
Freshwater
Barite/Hematite
Lignosulfonate
Caustic Soda
As many bbl as are
desired
Density to 1670-2640
kg/m3
2.85 kg/m3
(or a sufficient amount)
0.71 kg/m3 (pH 8-10)
FORM-A-SET may be blended with either fresh
water, seawater or salt water up to saturation.
Seawater and sodium chloride tend to retard the
cross-link set time. FORM-A-SET may be used to
stop losses in wells drilled with any kind of mud.
Retarder/Accelerator
The FORM-A-SET RET should be used with all
applications above 1°C A retarder is required
when bottom-hole temperature (BHST) and
pumping time increase. The retarder should
5-16
May 2011
Table 5-7 Retarder
Concentration vs. Temperature
Bottomhole Static
Temperature (oC)
FORM-A-SET Ret,
kg/m³
27-38
-
38-49
11
49-66
17
66-93
29
93-121
45
121-149
51
149-177
57
It is important to pilot test the formulation
to assure that the pill will remain fluid long
enough to be placed, and yet set within a
reasonable time.
Physical Properties
FORM-A-SET RET
Appearance
Specific Gravity
Water solubility
Clear liquid
1.323
Soluble
FORM-A-SET ACC
Appearance
Specific Gravity
Water solubility
Dark Green liquid
1.4
Soluble
FORM-A-SET ACC is used to decrease set times
with the slurry. It is used when ambient
temperatures or make-up water are below 16°C.
Caution must be exercised when adding the
accelerator to avoid over-treatment.
The FORM-A-SET ACC should be added after the
dry material has been added to the water. Allow
the dry material to blend thoroughly before
adding the FORM-A-SET ACC to the slurry slowly.
It is suggested the accelerator be diluted in 0.02
to 0.03 m3 of water before being added to the
FORM-A-SET slurry.
Remedial Treatments
Advantages
Because FORM-A-SET contains cross-linkable
agents and polymers in a single package, FORMA-SET RET is not required at lower temperatures.
However, at increased temperature and
longer pumping times, it is recommended
a minimum concentration of 20 kg/m3 be
used. At temperatures of 93°C to 177°C, it is
recommended to use 30 to 45 kg/m3 of FORM-ASET RET. Pilot testing is suggested before pumping
to obtain an estimate of time needed to create a
firm set plug.
Limitations
The FORM-A-SET plug will not degrade bacterially
in the wellbore over a period of time, but should
be used cautiously in or near producing zones.
Mixing/Pumping Instructions
A clean pit or blending tank should be used to
mix a pill of FORM-A-SET and water. Allow the
mixture to stir until the entire pill has been
well-dispersed. If the retarder is to be used, add
it to the water before mixing the polymer. On
the other hand, if using the accelerator, add it
after the FORM-A-SET product has been mixed.
Weighted Slurries
Adhere to the schedule in Table 5-6 to mix FORM-
A-SET slurries heavier than fresh water, using the
following sequence:
* Add the retarder before the FORM-A-SET.
The retarder concentration should be
proportioned to the water volume.
* Add one-half of the FORM-A-SET material
* Add the barite
* Add the remaining FORM-A-SET
* Add the accelerator concentration in
proportion to the water volume.
A clean pit or blending tank should be used to
mix a pill of FORM-A-SET and water. Allow the
mixture to stir until the entire pill has been
well-dispersed. If the retarder is to be used, add
it to the water before mixing the polymer. On
the other hand, if using the accelerator, add it
after the FORM-A-SET product has been mixed.
Note: Defoamer may be added when any air
entrapment is observed.
For unweighted slurries, add one sack (18.1 kg)
to 0.16 m3 of water.
Typical viscosity is from 125 to 170 sec/L
funnel viscosity directly after initial mixing.
A defoamer, such as DEFOAM A*, should be
available in case any aeration causes foaming.
Table 5-6. Mixing Schedule for Weighted FORM-A-SET Pills
Density
(kg/m3)
Water
(m3)
FORM-A-SET
(kg/m3)
M-I BAR
(kg/m3)
1015
0.145
104
0.00
1078
0.142
102
79
1198
0.137
98
237
1318
0.131
94
396
1438
0.126
91
554
1558
0.121
87
712
1678
0.115
83
870
1797
0.110
79
1028
1917
0.104
75
1187
2037
0.99
71
1345
2157
0.93
67
1503
May 2011
Remedial Treatments
5-17
Avoid using any defoamer containing glycol or
aluminum stearate as they might cause changes
in the cross-linkable mechanism.
Use approximately 3.2 to 4.8 m3 of viscosified
water or drilling fluid as a spacer both ahead
and behind the pill.
Pump the pill to the annulus at the depth of loss
and pull above the loss zone, being careful not
to leave any pill in the pipe even if losses have
stopped or slowed. Do not shut down pumping
while the pill is in the drill string. Watch for any
sign that the pill has reached the loss zone, such
as an increase in pressure or improvement in
the return flow.
Pull above pill and close the annular preventer
to begin squeezing. If pressure is noted, hold
for at least three hours to obtain a firm set
of the pill. Allow about 4 hr for pill to obtain
maximum strength.
Packaging and Handling
FORM-A-SET is packaged in 18.1 kg sacks. It should
be used in areas with sufficient ventilation
to remove airborne particulates and should
be stored in a dry location. The use of eye and
respiration protection is recommended.
Total time for the job, including blending,
pumping and squeezing, is about 6 hrs.
FORM-A-SET RET is packaged in 20 Qt (18.9 L) cans.
Warning: Use in an area that is well ventilated
and care should be used to avoid breathing
vapors. Store in a dry, ventilated place.
FORM-A-SET ACC is packaged in 1 Qt (0.95 L)
containers. Warning: Use in a well-ventilated
area and avoid breathing vapors. Store in clean
and dry location. For more information on the
design of FORM-A-SET pills, see Appendix 5.
FORM-A-SET AK
crosslinker is added separately. When added to
DUO-VIS* and activated with a combination of
FORM-A-SET XL*, time and temperature, FORMA-SET AK produces a firm, rubbery and ductile
plug that prevents loss of fluid to the formation.
The lost circulation material in the FORM-A-SET
AK package comprises a broad size distribution
of fibrous cellulose capable of plugging deep
fractures, faults, and vugular formations
Typical Physical properties
Physical appearance Light tan powder
Actual density
960 kg/m3 ( 0.96 sg)
Bulk density
550 kg/m3
Applications
The FORM-A-SET AK plug can be mixed in
freshwater, seawater or saltwater up to
saturation, although salt may retard set times.
FORM-A-SET AK can be used in any application
where a squeeze plug is beneficial and a smaller
particle-size distribution of bridging material
is desired. This enhances the ability of the
material to penetrate a porous or fractured zone.
It can also be mixed with larger bridging agents
to block larger openings. Often, it is used as the
second half of a dual or ‘tandem pill’, following a
coarse LCM or a FORM-A-SQUEEZE pill.
FORM-A-SET AK is a variation of FORM-A-SET.
The cross-linkable agent for FORM-A-SET AK is
packaged separately. Thus, the plug without
cross-linkable agent can be mixed and stored on
location as a contingency.
Because the cross-linking agent for FORM-ASET AK is packaged separately, the plug can be
mixed and stored on location as a contingency.
Once losses are encountered, the plug is
activated by adding the appropriate amount of
FORM-A-SET RET and FORM-A-SET XL.
FORM-A-SET AK can be used to stop losses
occurring with any water, oil or synthetic-base
fluid system.
FORM-A-SET AK provides the plug-forming
chemistry of FORM-A-SET in a more flexible
system. Like FORM-A-SET, it is a special blend of
polymers and fibrous materials. However, the
5-18
May 2011
Remedial Treatments
Unweighted slurries mixing & pumping
instructions
To mix an unweighted pill of FORM-A-SET AK, use a
clean mud pit or re-circulating mixer.
• Add 4 kg/m3 DUO-VIS*
• Add 70 kg/m3 FORM-A-SET AK
• Add 4 kg/m3 DUO-VIS
Note: The defoamer may be added at any time
air entrapment is observed.
Defoamers containing aluminum stearate or
glycol might cause changes in the cross-linkable
mechanism.
thoroughly for approximately five minutes.
Then add 14 kg/m3 of FORM-A-SET XL to the pill
and mix thoroughly for approximately five
minutes.
Place the bit across the loss zone. Pump the
pill to the bit as fast as possible and continue
pumping the pill until the whole pill has cleared
the drill string, even if losses have stopped. DO
NOT SHUT DOWN PUMPING WHILE THE PILL
IS IN THE DRILLSTRING. It is important not to
leave any pill in the pipe. Watch for any sign
of the pill reaching the loss zone, such as a
pressure increase or improved return flow.
Use approximately 3 to 5 m3 of viscosified water
or drilling fluid as spacers in front of and behind
the pill. The preferred spacer is 9 kg/m3 DUO-VIS
in water.
To begin squeezing, pull above the pill height.
Close the annular preventer and begin applying
pressure. If pressure is noted, hold for at least
three hours to obtain a firm set of the pill. Allow
about 4 hr for the pill to obtain maximum
strength.
Once losses are encountered, add the required
amount of FORM-A-SET RET to the pill and mix
Total time for the job, including blending,
pumping and squeezing is about five hours.
Table 5-8. Mixing Chart for FORM-A-SET AK Pills
Density
(kg/m3)
Water
(Liters)
1000
1020
1080
1140
1200
1260
1320
1380
1440
1500
1560
1620
1680
1740
1800
1860
1920
0.148
0.147
0.144
0.142
0.139
0.136
0.133
0.130
0.128
0.125
0.122
0.119
0.117
0.114
0.111
0.108
0.106
May 2011
M3
DUO-VIS
(kg/m3)
FORM-A-SET AK
(kg/m3)
FORM-A-SET XL
(kg/m3)
M-I BAR
(kg/m3)
8.0
7.9
7.8
7.6
7.5
7.3
6.0
5.8
4.6
4.5
3.3
3.2
2.1
2.0
1.5
1.4
0.9
66.6
66.3
65.0
63.8
62.5
61.3
60.0
58.8
57.5
56.3
55.0
53.8
52.5
51.37
50.0
48.8
47.5
14.2
14.2
13.5
13.5
12.8
12.8
12.1
12.1
11.4
11.4
10.7
10.7
10.0
10.0
9.3
9.3
8.6
0
22
100
189
258
337
415
490
570
650
730
810
890
966
1040
1120
1200
Remedial Treatments
5-19
* DUO-VIS: 0.6 kg/m3 (the second half of the
total required concentration)
Weighted slurries mixing & pumping
instructions
1. FASWARE should be followed to mix FORMA-SET AK slurries heavier than freshwater.
If FASWARE is not available, Table 5-8 can
serve as a guide. The recommended mixing
order is: Add one-half of the DUO-VIS. Add
one-half of the DUO-VIS.
2. Add one-half of the FORM-A-SET material.
3. Add the barite.
5. Add the remaining DUO-VIS.
6. If the pill is to be held for more than 24 hr,
an appropriate biocide should be added at
this point.
Objective: To formulate a FORM-A-SET AK pill for
195°F (91°C) formation temperature, 1860 kg/
m3 density and pumping time averaging 90 min.
As always, use approprate Personal Protective
Equipment.
As detailed in the FORM-A-SET RET table (Table 5.6)
for the formation temperature of 195°F (91°C)
the recommended concentration of FORM-A-SET
RET is 29 kg/m3 so the formulation and mixing
order are:
* Water: 0.108 m3
* DUO-VIS: 0.6 kg/m3 (half of the total required
concentration)
* M-I BAR: 1120 kg/m3
* FORM-A-SET AK: 24 kg/m3 (the second half of
the total required concentration)
5-20
May 2011
Advantages
* FORM-A-SET AK contains only the polymer
and LCM, therefore it may be mixed on
location and stored before the anticipated
losses are encountered.
* Because of this firmer set, FORM-A-SET AK
has a wide range of applications, ranging
from partial (1.6 to16 m3/hr) to total losses.
Furthermore, the material can be used
for both water and gas shutoff in nonproductive zones and may be used for gravel
consolidation.
Once losses are encountered, add the required
amount of FORM-A-SET RET to the pill and
mix thoroughly for approximately five min.
Then add FORM-A-SET XL to the pill and mix
thoroughly for approximately five minutes.
FORM-A-SET AK mixing example
* FORM-A-SET AK: 24 kg/m (half of the total
required concentration)
* FORM-A-SET XL: 9 kg/m3
* Owing to its increased polymer loading and
the smaller size of the fibrous material, the
FORM-A-SET AK has a much firmer set than
the conventional FORM-A-SET.
4. Add the remaining FORM-A-SET AK.
3
* FORM-A-SET RET: 29 kg/m3
* Extended times in the wellbore will not
cause a FORM-A-SET AK plug to degrade
Limitations
* Caution should be exercised when it is used
in or near the production zone.
* Pilot testing for thermal stability is
recommended when temperatures exceed
120°C.
* When premixing the pill, include 0.6 kg/m3
of biocide for all plugs. Pilot tests should be
run with available biocides.
Packaging and Handling
FORM-A-SET AK is packaged in 25-lb (11.3 kg)
sacks. FORM-A-SET AK should be stored in a dry
location.
FORM-A-SET RET is packaged in 5-gal (18.9 L)
cans. Use in a well-ventilated area and avoid
breathing vapors. Store in a dry, ventilated place.
Remedial Treatments
FORM-A-SET ACC is packaged in 1-qt (0.95 L)
containers. Use in a well-ventilated area and
avoid breathing vapors. Store in a clean, dry
location.
FORM-A-SET XL is packaged in 50-lb (22.7 kg)
containers. Use in a well-ventilated area and
avoid breathing vapors. Store in clean dry
location.
FORM-A-SET AK pills refer to the software
FASWARE, which is detailed in Appendix 5.
May 2011
Other Crosslinkable Pills
FORM-A-PLUG II, EMS-8320 and EMS-8420 are
crosslinkable pills which can be broken or
reversed when the well is ready to be put on
production. Consequently, they are thought to
be suitable for curing severe losses in reservoirs.
Because they are primarily intended for
producing zones, which is the theme of Chapter
8, these crosslinkable pills will be discussed
under that heading. Additional information on
the design of FORM-A-PLUG II pills can be found in
the discussion on FASWARE in Appendix 5.
Remedial Treatments
5-21
Chapter 6 - Prevention
Various techniques are now available that can
complement and even preclude conventional
lost circulation remediation practices. These
techniques rely upon a comprehensive approach
for stabilizing the wellbore to prevent lost
circulation, which includes implementation of
or improvements in:
* Drilling Practices - locally applicable, more
reliable wellbore stability modeling, and
ECD management practices, including the
use of relatively new techniques like MPD,
CWD, UBD, CTD
* Drilling Fluid Selection and optimization
of Mud Properties - choosing drilling fluids
that provide better control of ECD and fluid
invasion into the formation
* Surface and Downhole Hardware –
Minimize obstructions and ECD surges
* Wellbore Stabilization or Strenghening
Techniques - Hoop stress enhancement
methods, including stress cage and fracture
closure stress (see Chapter 7)
This chapter focuses on the first two of these
four key strategies.
points and mud weights and quantify the risk
of hole collapse and lost circulation (hazard
mapping). Doing so requires the use of data and
wellbore stability models that generate locally
accurate pressure and stress profiles, rather
than average gradients. Much of the necessary
information can be obtained from offset
wells and documented drilling experience. In
addition, risk and wellbore stability assessment
can be updated while drilling using real-time
logging and data processing techniques. This
requires real-time monitoring of downhole
pressure, condition of the well, the volume of
drilled cuttings and morphology.
Keep ECD to a Minimum
* Use VIRTUAL HYDRAULICS (VRDH* module) for
estimating equivalent circulating density
* Reduce restrictions in the annulus (filter
cake buildup).
* Keep hydraulics at the minimum level
required to clean the hole.
* Control ROP to avoid loading the annulus.
* Reduce the length of the exposed loss zone
and reduce influx size.
Drilling Practices
Minimize Annular Loading
The technique used to drill a well plays a major
role in determining and controlling the wellbore
hydrostatic pressure throughout the drilling
operation. Thus, it is important to strongly
consider the mechanics of the drilling process.
To minimize the risk of lost circulation it is
important to consider the following general
precepts:
Increase in annular mud weight because of
drilled cuttings can break down the formation,
particularly in surface holes. Thus, the effective
increase in annular mud weight must be
calculated and taken into account. Controlled
drilling may be required. Use VIRTUAL HYDRAULICS
to predict the cuttings effect for the given ROP at
the annular loading.
Enhance Precision and Accuracy of Wellbore
Stability Analysis
Minimize Surge and Swab Pressures
Obtaining an accurate geomechanical picture
of the planned wellbore is of paramount
importance. This will help determine the casing
May 2011
* The TRIPPRO* module in the VIRTUAL HYDRAULICS
software should be used for determining
trip velocity and acceleration schedule
Prevention
6-1
* While tripping in, break circulation at the
shoe and at approximately every 300 m in
open hole.
* Circulate for at least 5 min.
* Bring the pumps up slowly after
connections.
* Rotate the pipe before turning on the
pumps.
* While tripping out, pump out for the first
few stands/singles off bottom.
* Maintain slow tripping speeds across areas
of potential lost circulation.
* Consider the use of lubricants to reduce drag.
* Using sweeps to clear the cuttings from
the wellbore prior to POOH to run casing
should be considered. In addition, circulate
bottoms-up at least 1.5 times the theoretical
stroke count, or until the shaker screens are
clear. This will minimize cuttings beds and
bridges when RIH to set casing and cement.
Optimize Surface Equipment
* Remove pump strainers, if allowable.
However, contractor safety considerations
may prevent this
* Line up surface piping so at least one mud
pump can be switched quickly to water or
seawater.
* All surface equipment should be pressuretested in advance. Offshore, have the ROV/
SSTV check the riser daily for leaks. The
normal procedure would be to check for
leaks in the surface equipment before
assuming losses were down hole. Since
there might not be time to do so afterwards,
constant attention to the surface equipment
is essential.
* Ensure no mud transfers, additions, or
dilutions are carried out while drilling
proceeds toward or in a loss zone.
6-2
May 2011
Optimize Downhole Equipment
* If hydraulics permit, consider replacing bit
nozzles with larger nozzles or remove them
altogether.
* Minimize the BHA. No stabilizers and only
the minimum number of drill collars and
heavy weight drill pipe should be run.
Restrict angle build by maintaining high
rpm and low weight.
* If using large LCM, employ bypass
circulating valves such as WELL COMMANDER*
above the BHA to avoid pills being circulated
through tools with limited flow paths or
restrictions. This might include core barrels,
MWDs, mud motors, floats and survey rings.
* Avoid running drill pipe casing protectors,
which can swell and act like a packer.
Reliance on Well-Trained Personnel
* If severe and prolonged losses are expected,
two drilling fluid engineers should be on
board/at the rig site for 24-hr coverage
Doubling up the drilling fluid engineers,
project engineers and supervisors also
should be considered.
* Demonstrating the HSE impact of mixing
sodium silicate and calcium chloride mixing
instantaneously form a precipitate is a
powerful reminder to rig personnel of the
danger of allowing these two reagents to
mix inside pipe. A similar demonstration
should be made to illustrate the reaction
between sodium silicate and cement.
Pull Back to Safety
* The string can be pumped out of the well,
thereby displacing the treatment while
pulling out. Continue pulling to the shoe,
maintaining constant pipe movement.
* Cement should not be pumped if there are
doubts whether the string can be pulled
back safely to the shoe.
Prevention
Observe Warning Signs
* There is a possibility of seepage losses
occurring prior to major losses.
* It is essential to monitor for signs of
increasing overpressure.
Attack Losses Immediately
* Losses should be dealt with as they occur.
While it is possible, though expensive, to
drill ahead with losses, if the open hole
section is too long, it is difficult to direct
the treatment to the correct location,
Additionally, penetrating a higher pressure
zone could result in an underground
blowout.
* In order to apply/spot a treatment as soon as
the loss zone is encountered, a slug pit full of
an LCM pill should be available. A minimum
of 15.9 m3 pumpable volume should be on
location. This should be mixed at the highest
concentration the agitators can handle.
Additional LCM to 230 kg/m3 can be added
by dumping straight into the top of the pits
or via big bags.
* Have a large volume of reserve mud
prepared.
Identify Location of Loss Zone
* If losses first occur while drilling ahead, or
are accompanied by a change in torque or a
drilling break (including the bit dropping),
the losses likely are on bottom.
* If, however, losses occur while tripping
or increasing mud weight, they may be
off bottom. If necessary, a temperature or
spinner survey should be run.
moving. Where possible, pull to the shoe
before attempting a treatment. As a rule,
it is recommended to have sufficient open
hole volume below the bit to accommodate
the whole treatment.
* More than likely, reactive clays overlying
the loss formation will become unstable if
exposed to uninhibited fluids.
* As loss zones may be low-pressured, it is
critical to guard against differential sticking.
* Carry out pilot tests for each treatment.
Practice Good Well Control Procedure
With the annular closed and losses occurring
into a highly permeable gas- bearing formation,
the likelihood of gas invasion is high. When
this happens, gas migrates up the wellbore,
effectively displacing the mud.
If employing bull heading, it is very important
to maintain rates of 2.27 cubic meter per
minute. If it is necessary to pump water,
seawater, or any fluids of varying density, it is
also important to record the number of strokes
pumped. In addition, it is essential to be able
to calculate the height of water/seawater, and
therefore the hydrostatic pressure, in the well at
all times.
Unconventional Drilling Techniques
Various drilling techniques are now available
that can reduce the risk of lost circulation. These
include Managed Pressure Drilling, Casing while
Drilling, Expandable Tubulars, Underbalanced
Drilling and Coiled Tubing Drilling. The
following discussion focuses on the three most
relevant techniques used today - MPD, CWD and
Expandable Tubulars.
Managed Pressure Drilling (MPD)
Avoid Stuck Pipe
* When losses occur, cuttings will settle out
around the BHA and may mechanically stick
the pipe. The cuttings will act as a packer
and exacerbate underlying losses. That is
why it is critical to always keep the pipe
May 2011
MPD should be investigated to determine if it is
economically viable. Unlike underbalanced and
power drilling, the primary objective of MPD
is obtaining a stable wellbore within a narrow
operating PP/FG window, while avoiding any
influx of formation fluids. MPD effectively
Prevention
6-3
manipulates the pressure window so the fluid
“walks the line” between wellbore collapse and
wellbore failure (fracturing, ballooning) with
greater certainty. An important goal of MPD
technology is to stretch or eliminate casing
points. In a typical MPD application, the fluid
system is closed utilizing (a) a Rotating Control
Device (RCD) and a drilling choke to restrict and
control the exposed wellbore pressure profile,
and (b) a casing pump to provide back-pressure
when required. However, other configurations
also are used, thus helping to expand the range
of possibilities for MPD technology.
In conventional drilling, maintaining wellbore
stability is accomplished by manipulating
the static and dynamic pressure profile of
the annular fluid by controlling fluid density
and viscosity. As the wellbore stability (PPG/
FG) window narrows, the risks of fluid influx/
wellbore collapse and wellbore failure increase.
The traditional response is to set casing and
reestablish a wider window, but MPD offers
various alternatives for avoiding or defering the
setting of casing. Most of these methods depend
upon keeping the wellbore closed at all times, as
indicated in Fig. 6-1. Under such conditions, any
changes in the pressure or volume of the fluid
in the annulus are apparent immediately. As
such, fluid influxes and losses can be detected
almost instantly using advanced model tools
and automated control systems.
In addition, MPD may be approached reactively
or proactively. In the reactive mode, wells are
designed conventionally, though equipment
is rigged up to react quickly to unexpected
pressure changes in the well. In the proactive
mode, a well is planned to include equipment
that is rigged up to intervene continuously to
alter the annular pressure profile. The proactive
approach is preferred because it promises to
provide better wellbore stability and perhaps
extend or eliminate casing points.
MPD is carried out by manipulating
backpressure, fluid density, fluid rheology,
circulating friction, hole geometry, and
employing active devices to control the mud
pressure gradient. The MPD techniques that
6-4
May 2011
have been used successfully include:
* Constant Bottom-Hole Pressure Profile
(BHPP)
* Dual Density Gradient
* Pressurized Mud Cap
Fig. 6-1. Typical MPD Closed Pressurized Mud System
Constant BHPP is used primarily to avoid
exceeding the fracture gradient. Figure 6-2
depicts a typical scenario that can be resolved
by applying the Constant BHPP technique.
When the mud is not flowing, the wellbore is
stable, but when it is circulating, losses occur in
an upper zone.
BHP = Bottom-Hole Pressure; HH = Hydrostatic
Head, given by the mud weight MW; and AFP =
Annular Friction Pressure.
To remedy this problem, the density of the
fluid is lowered, and back-pressure is imposed
only when the fluid is static, i.e. when making
connections. As a result, BHP (Static) > BHP
(Dynamic). Imposing a Constant BHPP in this
manner requires a rotating control head, a
surface choke and a drill pipe float. Figure 6-3
demonstrates the effect of this technique, where
BP = Back Pressure.
An alternative “Constant BHPP” technique
involves circulating continuously, i.e. through
the bit while drilling and through the concentric
casing string while making connections (Fig.
6-4).
Thus, BHP(static)=HH(MW) + AFP(shoe). The
Prevention
Fig. 6-2. Drilling scenario where wellbore is stable
under static conditions, but failure occurs in a
shallow zone under dynamic conditions.
Fig. 6-3. Imposing back-pressure when fluid is static.
Fig. 6-4. Circulating the fluid
continuously yields a near-constant BHP
pressure gradient curves are shown in Fig. 6-5.
Dual Density Gradient Drilling
The technique includes the following:
This is recommended – with or without a riser –
when the pore pressure (PP) gradient increases
so rapidly with increasing depth that neither
a static or dynamic column of a single-density
fluid can be managed without fracturing the
shallower formations. While this technique is
useful particularly in deep water drilling where
seawater controls the pore pressure in the
shallower formations, it also could be applied in
land jobs.
* Use lower density and keep the fluid
dynamically dead at all times (no RCD
required)
* Tailor the friction losses by increasing or
decreasing clearances or varying lengths of
drill string components
* Run a down hole pump in the drill string
that adds energy to the annulus return flow
May 2011
Prevention
6-5
Fig. 6-5. When fluid is circulated down the back side under “static” conditions, the pressure gradient is
similar to that for the fluid circulating through the bit.
Conventional drilling usually calls for several
casing strings to be set just below the seabed.
Applying Dual Density Gradient drilling
offshore requires a lifting mechanism or the
introduction of a lighter fluid over the heavier
fluid. For the latter case, the mud often is
discharged at the mud line while drilling the
top hole and before running the surface casing,
riser and BOP. Onshore, Dual Density Gradient
drilling can be carried out by using a parasite
string, where air or nitrogen is injected into
the annulus at the casing shoe. Indeed, the first
applications of Dual Density Gradient drilling
- and still perhaps the most common - were
onshore.
The specific Dual Density Gradient method used
will depend on the particular drilling operation.
One common method specifies the use of a
lower density gradient at the top of the wellbore
and a higher density gradient at the bottom, as
shown in Fig. 6-6. The lighter fluid is injected
through a parasite string or concentric casing.
This changes the hydrostatic head in the upper
part of the wellbore, thereby reducing the BHP
in the upper zones, which in turn, effectively
Fig. 6-6. Dual density gradient drilling can handle rapidly increasing PP
6-6
May 2011
Prevention
avoids the risk of fracturing those formations.
On the other hand, the BHP in the lower zones
remains high enough to keep the wellbore from
collapsing.
Dual Density Gradient drilling differs from
Single Density Gradient drilling in several
respects:
Single Gradient MPD
* Surface Control
• RCD and choke
• Friction management
* Subsea/Sub Surface Control
• Shallow water flow diverter
• RCD and dynamic choke
* Down hole Control
• ECD reduction tools
• Friction Control
Dual Gradient MPD
* Surface Control
• Fluid density management
• Mud cap
* Subsea Control
• Top hole mud recovery
• Conventional dual gradient
Several variations of this technique are possible,
depending on the locations and PPG/FG of
the formations in question. For example, if
the formations are further apart or the pore
pressure or fracture gradients not as steep,
the water/mud interface may be created at
a shallower depth, along with reducing mud
density. By way of another example, drilling a
deep water surface hole riserless requires some
density to avoid collapse. In this scenario, “Pump
and Dump” can be tried, although it requires
huge volumes and is expensive. Furthermore,
Pump and Dump does not offer dynamic
methods of controlling kicks or the formation of
gas hydrates, as it depends heavily on accurate
seismic data to avoid shallow hazards.
Pressurized Mud Cap Drilling
With MCD it is possible to balance a single point
in the reservoir either statically or dynamically.
This is because some very thick reservoirs
contain hydrocarbons with a much different
hydrostatic gradient than the drilling fluid,
making it impossible to simultaneously balance
Fig. 6-7. Typical equipment layout for Light Annular Mud Cap Drilling (LAMCD)
May 2011
Prevention
6-7
fractures that are separated by any significant
vertical distance.
Since the formations in question sometimes
are quite sour, allowing the sour gas to come
to surface is justified. In addition, there is some
concern when using floating MCD techniques
in that the fluid level is unknown and kicks
often are sudden and occasionally quite forceful.
Acoustic fluid-level guns have been employed
to monitor behavior within the wellbore, but
since the gas migration is transient, the results
have had limited value. The pressurized mud
cap technique was developed to continuously
monitor pressure at the surface.
Also known variously as light annular mud
cap, or closed-hole circulation drilling, this
method places a column of mud in the annulus
that is lighter than that required to balance
the formation pressure. Figure 6-7 shows the
surface equipment required for pressurized
mud cap drilling. With this technique, drilling
is conducted through a rotating head with
the well shut in at the surface and the surface
annular pressure used as an indicator of what
is occurring downhole. Sacrificial drilling fluid
(preferably one that is economical and nondamaging) is pumped down the drill string, and
all fluid and cuttings are pumped back into the
fractures or vugs. Maintaining a full hole with
a static column of fluid reduces mud losses and
maintains constant contact with the reservoir.
The static surface annular pressure is the
difference between reservoir pressure at the
top fracture and the hydrostatic pressure
exerted by the annular fluid. Typically, the
pumping annular pressure is slightly higher, as
determined by the friction pressure required to
pump into the fractures. If gas migration occurs,
the annular pressure rises as the gas replaces
the annular fluid. As the gas rises to the surface
and expands, the annular pressure increases
accordingly. Once the annular pressure rises
above a predetermined value, the situation
can be corrected by pumping additional fluid
into the annulus, thus displacing the gas and
contaminated fluid back into the formation
until the previous annular pressure is restored.
6-8
May 2011
By doing so, control of the well can be
maintained with undesirable substances, like
H2S, left below surface.
With a single density gradient fluid, Pressurized
Mud Cap drilling may require unsatisfactorily
high surface back-pressure to generate a BHPP
that stabilizes the wellbore from top to bottom.
A combination of Dual Density Gradient and
Pressurized Mud Cap techniques can be used
effectively to avoid this problem
If a plane of weakness or rubble zone is present,
the hydrostatic pressure of the mud column
sometimes will not support the wellbore wall
sufficiently. Mitigating this mode of instability
requires a lower mud weight or less pressure
fluctuation. One MPD technique that would
help remediate this condition is dual gradient
to reduce the annular pressure across the
fractured/fissile zone and continuous circulation
to prevent pressure fluctuations. Therefore, in
situations where mud penetrates fractured/
fissile zones, annular pressure management is
paramount.
For riserless drilling, special techniques may
prove beneficial, including:
* A subsea RCD and a ROV-controlled choke,
with seawater and gelled sweeps.
* For zero-discharge, riserless MPD, one
possible solution is to use a subsea pump
to return mud to the rig. For dual density
drilling, the mud/water interface may be
regulated to achieve an acceptable operating
window. Also, back-pressure (BP) may be
imposed at the mud line.
Recent MPD innovations allow for more
automation to control the BP and choke, along
with smaller equipment footprints and the
allowance of larger tubulars in RCDs. This
is enhanced by more precise monitoring,
simulating and predictive software. The RCDs
are becoming easier to install on all types of
BOPs and have increased pressure ratings.
MPD equipment for floating rigs also has been
developed.
Prevention
Where possible, MPD should be considered and
incorporated in the drilling plan as an integral
part of the well control program, rather than
a contingency. This pro-active approach can
realize significant gains, both in continuity
of the drilling operations and enhanced
safety. Also, where possible, the drilling
operation should be designed as an automated
MPD closed-fluid system with redundancy
incorporated to minimize the risk of accidents.
Casing While Drilling (CWD)
In CWD, or more simply known as Casing
Drilling, a well is drilled and cased
simultaneously using standard oilfield casing.
Figure 6-8 illustrates a typical casing drilling
assembly. As shown, the BHA is latched into
the bottom joint of casing where it is run and
retrieved through the casing via wireline. For
directional or horizontal wells, the BHA can be
fitted with conventional directional equipment,
such as mud motors and measurement-whiledrilling (MWD) tools. Since these tools are run
and retrieved inside casing, they are protected
from the harsh downhole environment while
in transit. Accordingly, problems that can occur
typically during tripping operations, such as
kicks, unintentional sidetracks, casing wear,
and wellbore instability due to surge/swab
pressures and formation sloughing/swelling,
are eliminated.
Fig. 6-8. Casing Drilling Assembly
May 2011
In this technique, the casing provides hydraulic
and mechanical energy to a retrievable drilling
assembly that is suspended from a profile
nipple located near the bottom of the casing.
The profile nipple has the same drift diameter
as the casing and can be used to land cementing
equipment after the drilling assembly is
removed.
With Casing Drilling, the BHA is connected
to the casing with a “drill lock” (DLA) that
provides a running/retrieval interface, along
with a mechanical attachment to the casing
and a hydraulic seal. The pilot bit is located
at the end of the drilling assembly, which is
suspended below the DLA and also may include
other conventional drill-string components,
including an under-reamer, mud motor, core
barrel, or directional assembly (non-mag. collars,
LWD, MWD, UBHO, motor, etc.). A pilot bit that
will drift the drill casing is run with an underreamer to open the hole to the appropriate size
for running the casing. For example, a 159 mm
pilot bit is used with 3.18 kg/m 17.8 mm casing,
along with an under-reamer to open the hole
to a final diameter of 21.6 mm. The hole may be
opened to a larger diameter to reduce the ECD in
critical applications.
Expandable Tubulars
Also know as Expandable Liner or Expandable
Casing solutions, the primary application for
this technology is delivery of the proper casing/
liner without losing any hole diameter. This
technology also can be used to isolate downhole
problems (lost circulation, wellbore instability
or damaged casing) after the issues have
arisen. Thus, since the problem is addressed
after the targeted well section has been drilled,
expandable tubular are used essentially as a
remedial treatment.
The method consists of setting a tubular against
the troublesome wellbore zone (up to a few
thousand feet) and afterwards expanding
the tubular, thus sealing off the zone. For this
purpose, an expansion tool exceeding the inner
diameter of the tube by a predetermined degree
of expansion is forced through the tubular.
Prevention
6-9
This is accomplished either hydraulically (by
applying mud pressure) or mechanically (by
pulling the conical \ tapered expansion tool).
Two types of expandable tubulars are now in
use:
* For Cased Holes - expandable liner hanger
and the cased hole clad. Basically, the
expandable liner hanger is an evolution of
existing equipment currently used, but with
a better through bore and perceived higher
reliability. The Cased Hole clad provides
a casing patch across a damaged section
of casing, or is used to close off previously
perforated casing. This product has two
main advantages – minimal through bore
loss [basically two times the wall thickness
of tubular being expanded] and high
pressure integrity performance.
*
For Open Holes – liner and open hole
clads. The tools are very similar to the
conventional liner technologies with the
exception of having no lost internal wellbore
diameter after setting and expanding. The
open hole diameter in the proposed set zone
might require under-reaming to provide the
required expansion space.
Drilling Fluid Selection
Before planning treatment methods and
the quantities of LCM needed for a specific
well, selecting the right drilling fluid for the
application must be the first step of any Lost
Circulation Assessment Plan (LCAP). Fluids with
the inherent capacity to minimize or cure lost
circulation exhibit reduced invasion rates into
fractures. This is a function of having a lower
impact on ECD’s than other fluids, independent
of shear rates, wellbore temperature gradients,
or mud weight requirements.
High-LSRV Fluids
When encountering an existing open fracture,
the drilling fluid will flow into the formation
if the hydrostatic pressure is greater than the
formation pressure. By nature, drilling fluids
are all shear thinning, but the mixed metal
oxide DRILPLEX* fluid is one that produces high
6-10
May 2011
viscosities at low shear rates. An extreme case
of a Non-Newtonian fluid, DRILPLEX develops a
near-to-perfect plug flow. While drilling through
an open fracture, the shear rate decreases
from the mouth of the fracture to the tip. At
that point, the effective viscosity of DRILPLEX
starts to increase. This leads to a rapid rise in
fluid viscosity with increasing fracture depth;
indeed, at the fracture tip the viscosity is so high
that the the rate of invasion drops to near zero.
Figure 6-9 illustrates the effect of the DRILPLEX
LSRV on the invasion rate.
ECD-Friendly Fluids
Fluids with rheological profiles that deliver
less impact on ECD can help to reduce or even
prevent the inducing or re-opening of fractures.
The RHELIANT system, for instance, with its
3-rpm and 6-rpm dial readings and YP relatively
independent of temperature, offers the double
advantage of providing good hole cleaning
capability and a unique gel strength structure
that eliminates the pressure spikes typically
seen with other invert emulsion fluids.
The cold environment within the large risers of
deep water wells present unique challenges that
a fluid such as RHELIANT can help overcome by
drilling with higher pump rates to ensure good
hole cleaning while reducing the tendency to gel
in the riser when the pumps are off. The system
has been known to reduce the risks of ECD
spikes considerably when breaking circulation,
especially in narrow drilling windows.
Similarly, fluids utilizing micronized weight
material, such as WARP, requires minimum
rheology, thus allowing higher pump rates than
fluids weighted with API barite. This serves
to improve hole cleaning considerably, reduce
sag tendencies and lower plastic viscosities.
Especially effective in small-diameter holes,
these features give the micronized weight
material systems a definite edge on API
barite-weighted fluids when it comes to ECD
management and reduced wellbore fracturing
and lost circulation risks.
Prevention
Fig. 6-9. DRILPLEX fluid flow in a fracture
Fig. 6-10. RHELIANT rheology profile
Fig. 6-12. WARP vs API Barite
May 2011
Fig. 6-11. RHELIANT flat gels
Fig. 6-13. WARP vs. Conventional OBM Viscosity
Prevention
6-11
Wellbore Isolation Fluids
Wellbore isolation (a cased hole being the
perfect isolated wellbore) can be considered the
ultimate lost circulation cure as it will create a
barrier to pressure, chemical contaminants and
fluid transmissions.
Very few fluids have the capacity to create
such an impenetrable structure around the
wellbore. One that can come close, however, is
the silicate-based SILDRIL* system. The drilling
industry used silicate chemistry as early as
the 1960’s to overcome troublesome watersensitive clays. A secondary feature of silicates
was for use as a corrosion inhibitor in many
industries other than petroleum. The bond
created between the silicate and clay layers is
such that it can be compared to a covalent bond
in organic chemistry, creating a structural film
that will seal existing openings and prevent the
development of new fractures.
Various wellbore-isolating techniques may also
be used, including plastering agents, such as
asphaltic and asphaltenic materials and others
that generate very tight filter cakes and, in turn,
ultra-low fluid loss. Fluid/pressure isolation
also can be achieved through the formation of
relatively impermeable plugs using swellable or
cross-linkable polymers.
Drilling Fluid Maintenance
Regardless of the type of drilling fluid used,
it also is critical to maintain excellent fluid
properties. To minimize the potential for
wellbore instability that may lead to lost
circulation, it is important to:
* Accurately calculate the hydraulics profile of
the well and monitor it at the rig;
* Use good hole-cleaning practices;
* Optimize the configuration and
performance of solids control equipment;
* Use minimum mud weight while drilling,
and any change in density should be
performed slowly.
* Maintain low fluid loss and a thin filter cake;
6-12
May 2011
Follow prescribed tripping schedules;
* Maintain gel strengths, yield point, and
viscosity at the lowest levels that will clean
the hole effectively;
* Maintain low MBT levels.
Additives for Preventing losses
A flow diagram for the prevention of losses
is provided in Fig. 6-14. To prevent losses in
reservoirs, the choices available are more
restrictive; these are summarized in Table 6-1
and discussed more fully in Chapter 8 .
Treatments with additives to prevent or
mitigate lost circulation can be classified as
either low or high-fluid-loss.
Low-Fluid-Loss Treatments
These are effective where the openings in the
formation can be sealed relatively rapidly. These
treatments entail materials such as cement,
resins, cross-linkable materials and particulates
that pack tightly at the wellbore or within the
openings of the loss zone. Sealing the wall of
the wellbore can be effective if the fraction of
larger particles are capable of forming a stable
external barrier (or a plug just inside the mouths
of the openings) that can be sealed with smaller
materials. If a bridge can be created internally,
the seal is more permanent, inasmuch as fluid
and mechanical motion will not dislodge it as
easily.
Low-fluid-loss treatments generally use
LCM, which usually is administered as highconcentration pills to cure losses. Conversely,
to prevent losses, the whole drilling fluid
may be treated with LCM to provide a
“background” concentration of the material.
Alternatively, though less effective, the LCM
can be administered as 3.18 – 15.9 m3 pills
that are added regularly, e.g., every 10 to 30 m,
depending on the drilling operation and the
type of loss zone expected to be encountered.
For permeable and naturally fractured zones,
general prescriptions typically are based on
blends of sized CaCO3 and synthetic graphite.
Prevention
These blends perhaps can be supplemented
with a fiber, but a large number of particulate
types may satisfy the specific requirements.
For whole mud treatment, a total concentration
of LCM on the order of 15 to 70 kg/m3 usually
is sufficient; for pills to be squeezed or used in
sweeps, the concentration may be multiplied by
3 to 5. For severe losses, gunk squeezes, cement,
swellable materials and cross-linkable polymers
may provide some relief.
The LCM product blend should include very
coarse particles to plug or bridge the largest
openings in the formation, whether they are
is most effective when losses are classified as
seepage, where bridging agents are effective
in controlling the losses. The system should be
treated with a low concentration of products
like fine mica, or fine nut hulls, to bridge very
narrow fractures or seal off highly porous sands.
For seepage losses, fine fibrous materials like
M-I-X II are very effective. It is critical that the
concentration be kept low to minimize the
effects on rheology and wettability. Usually, 0
to 20 kg/m3 is effective, but there are instances
where as much as 150 kg/m3 is necessary.
Depending upon the particle size distribution
Table 6-1. Prevention of Lost Circulation (Continuous Addition)
Seepage Losses
Producing
WBM
OBM/
SBM
Non-Producing
Producing
Drill-In Fluid
(with CaCO3)
Cellulosics/Gilsonite/
CaCO3
Drill-In Fluid;
asphaltics
Cellulosics/Gilsonite or Drill-In Fluid /Soltex or
other Asphaltics
Asphaltics/CaCO3
fractures or pores. Bridging is defined as the
structure that is built when the D90 of the LCM is
less than half the aperture. Typically, plugging
is thought to occur when the D90 of the LCM
is greater than the aperture of the formation
openings. Thus, plugging tends to occur at or
near the mouths of the openings, whereas
bridging occurs internally.
Whether the formation openings are plugged
or bridged, finer particles also are necessary to
fill the voids between the coarse particles. Even
finer particles are necessary to generate a tight
filter cake, thus producing a seal to control fluid
loss. However, with normally weighted fluids,
the size and shape of the weighting material
is such that it takes on the role played by fine
LCM. Consequently, in weighted fluids, the
concentration of fine LCM can be reduced or
even eliminated.
Pre-treatment consists of adding certain
types of LCM to the drilling fluid system in
preparation for expected losses. Pre-treatment
May 2011
Catastrophic Loss
Non-Producing
Drill-In Fluid / Asphaltics / Conventional LCM,
Cloud-Point Glycol
e.g. walnut hulls
Conventional LCM,
e.g. walnut hulls
(PSD) of the material, it may be necessary
to install larger mesh screens when using
these products in the fluid system. If the
concentration used is high (0 to 50 kg/m3), it
may be economical to install a separate LCM
recovery unit, which would then recycle the
material back into the circulating system.
The MD-3* multi-deck shaker, which is discussed
in more detail in Chapter 7. is recommended
for LCM recovery. The shaker has three separate
decks: upper deck serves as a scalper for the
coarse cuttings; middle deck screens out the
specified size LCM and the third deck removes
the finer cuttings. Another option might the
use of the MANAGED PARTICLE SIZE RECOVERY SYSTEM*
(MPSRS), which likewise is detailed in the next
chapter.
The “/” represents “and/or”, so that CaCO3
/ asphaltic products means CaCO3 with or
without asphaltic products. Asphaltic products
include materials like Asphasol Supreme (for
OBM/SBM). WBM should use xanthan or welan
gum polymer as the viscosifier, starch for fluid
Prevention
6-13
6-14
May 2011
Preventive Lost Circulation Treatment
For Extensive Loss Zones
PHYSICAL
(Plugging & Sealing)
OPTIBRIDGE*
Size of Openings
Known
MECHANICAL
(Stress Enhancement & Sealing)
Size of Openings
Unknown
Whole Mud
Treatment
OPTI-STRESS*
Background LCM
in Mud or Pills
Repetitive Pills#
Repetitive Pills#
Maintain Background LCM
Non Aqueous
Fluid
Water Base Fluid
General Use Non
CRI
OPTISEAL I*
General Use CRI
OPTISEAL II*
Prevention
General Use N.A.F
OPTISEAL III*
General Use
R.D.F and
Acidizing
OPTISEAL IV*
General Pill#:
(120-200) Kg/m³ CaCO₃ + (30-60) Kg/m³
G-SEAL PLUS + Fiber
#
FORM-A-SQUEEZE*
Maintain Fluid PSD with:
(30-50) Kg/m³ CaCO₃ + 15 Kg/m³
G-SEAL PLUS + Fiber
EMI-1820*
EMS 8420*
Spotted Pills or Sweeps, repeated every Stand
Fig. 6-14. Lost Circulation Prevention Flow Chart
EMS 8320*
loss and CaCO3 particles sized to match the
pore/fracture size distribution of the formation.
OBM/SBM “Drill-In Fluids” may contain CaCO3,
non-aqueous viscosifier and fluid-loss reducing
agent.
Coarser screens should be used to prevent
excessive loss of the LCM at the shakers. The
preferred approach is:
* Install medium-to-coarse screens on the
shakers;
* Continually add the coarser LCM to the
suction to maintain the required Particle
Size Distribution.
Bypass Shakers? Not recommended!
Completely bypassing the shakers for prolonged
periods is to be used as a last resort and should
be undertaken with great caution. This practice
obviously has a very negative impact on drilling
fluid properties and is not recommended.
Bypassing the solids control equipment will:
* Increase drilled solids content
* Increase drilling fluid density
* Increase drilling fluid rheological properties,
including plastic viscosity, yield point and
gel strength
* Increase filter cake thickness
* Degrade the filter cake quality
All of these effects will aggravate the very lost
circulation problem that is being combated.
Along with the above, these fluid property
changes will increase hydrostatic pressure
downhole, increase ECD, increase the pressure
required to break circulation, heighten surge
pressures and precipitate stuck pipe. The
question to be asked is whether the value of
the LCM to be saved is worth the possibility of
worsening the problem and possibly losing the
hole.
Careful consideration should be given to the
addition of LCM if any kicks are to be circulated
out, as this could easily plug the choke. Kicks
associated with losses may be bullheaded.
May 2011
High-Fluid-Loss Treatments
These treatments are especially effective for
sealing exisiting fractures. Thus, the seals are
relatively stable and difficult to dislodge by
normal drilling practices. The seals are even
more difficult to dislodge if the treatment
material can adhere to the walls of the
openings.
High-fluid-loss treatments generally are
based on use of particulates. To promote fluid
loss, the particle size distribution is relatively
narrow (uniform) or the particles have uneven
shapes or open structures. In relative terms,
the particle size of the LCM should be smaller
than the fracture opening. This is necessary
to ensure the material enters the fracture
where it can be deposited by a process of defluidization as the carrier fluid leaks-off. Since
the success of the treatment requires high fluid
loss, contamination by drilling fluid or other
fines-laden fluid can impair its effectiveness
significantly. Therefore, this type of treatment
is better suited to the spotting and squeezing of
pill-based LCMs. Nevertheless, several jobs have
been run successfully with WBM in which the
whole drilling fluid was treated to provide high
fluid loss.
High-fluid-loss treatments may not be effective
for 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 may be required.
Under these circumstances, the high-fluid-loss
treatment may be used to slow the rate of loss
sufficiently, followed by settable materials like
cement or gunk to plug the zone. Generally,
high-fluid-loss treatments are effective only in
high-permeability formations or fractured zones
that exhibit high fluid loss.
Even when using LCM in the whole mud, it
is prudent to have an LCM pill on hand. A
minimum of 16 m3 pumpable volume in a slug
pit should be made available and mixed at the
highest concentration of LCM that the agitators
can handle. Additional LCM (as much as 230 kg/
Prevention
6-15
m3) can be administered by dumping directly
into the top of the pits or via big bags. As a
contingency, it also is critical to have a large
volume of reserve mud prepared. For instance,
concentrated slurries containing as much as
6-16
May 2011
700 kg/m3 LCM have been used successfully
on the Ekofisk development to alleviate the
logistics problems involved with treating
large volumes of whole mud with high
concentrations of LCM.
Prevention
Chapter 7 - Wellbore Strengthening Solutions
A variety of methods can be used to enhance
the integrity of the wellbore and prevent lost
circulation. These treatments are loosely labeled
“wellbore strengthening”. Examples include:
* Imposing a mechanical barrier such as
expandable screens, cross-linkable plugs or
particulates that seal fractures (Fracture Tip
Isolation, also called Fracture Propagation
Resistance)
* Altering downhole stresses, especially
increasing the hoop stress (Fracture Closure
Stress and Stress Cage)
* Hoop Stress Enchancement or Dehydrating
Water-Sensitive Formation, i.e. using lowwater-activity OBM/SBM
* Increasing Formation Temperature by
heating the mud. For example, an increase in
formation temperature of 20°C was shown
to increase the fracture pressure of a South
Texas well by 827.4 Pa.
All of these techniques have been brought
together under the umbrella of the M-I
SWACO package I-BOSS* (Integrated Borehole
Strengthening Solutions). This technology
comprises a comprehensive suite of drilling fluid
products, environmental solutions hardware
and engineering services to design and
implement wellbore strengthening solutions.
The emphasis of I-BOSS is on technizues tgar
involve isolation of the wellbore and fractures,
and “tightening” the wellbore to increase the
circumferential stress (also called “tangential” or
“hoop” stress). Fracture Propagation Resistance
(Fracture Tip Isolation) uses low-fluid-loss
particulates to bridge and seal existing or
developing fractures, thereby halting fracture
propagation and preventing or remediating lost
circulation. This method usually is administered
as a whole mud treatment. Hoop Stress
Enhancement is designed and implemented
similarly as a preventive treatment for the
whole mud system, and also utilizes low-fluidloss particulates. By contrast, the “Fracture
Closure Stress” concept uses high-fluid-loss
May 2011
particulates and can be implemented either
by remedial or preventive treatments, usually
involving the administering pills.
Fracture Propagation Resistance
(FPR)
The FPR concept essentially involves pushing
LCM into a fracture (incipient or existing) to
bridge, seal and isolate the fracture tip. If the
formation is sufficiently permeable, leak-off
occurs behind the seal and the pressure declines
until it quickly falls below the threshold Fracture
Propagation Pressure. Halting the propagation
process also arrests the lost circulation.
Hoop Stress Enhancement
(Stress Cage)
Theoretically, building a Stress Cage entails
changing the stress state of the target
formation near the wellbore, rather than
altering the physical strength of the rock itself.
Wellbore Strengthening Material (WSM) is
added continuously at relatively moderate
concentrations while drilling. Pre-treatment of
the whole mud is preferred, followed by small
maintenance additions during drilling. The
drilling fluid is overbalanced with respect to the
fracture gradient of a target formation, thereby
inducing shallow fractures in the near-wellbore
region. Opening these fractures tightens, or
compresses, the wellbore. Sized WSM particles
are driven into the opening of the emerging
fracture where they prop it open and ultimately
form a hydraulic seal near the mouth of the
fracture. As the seal is formed, fluid within
the fracture leaks off through the fracture
walls, thereby limiting further propagation.
Furthermore, as pressure in the fracture
subsides, the WSM wedged within prevents the
fracture from closing completely.
The propped fractures generate additional
compression of the wellbore that increases the
hoop stress in the vicinity of the fracture. Thus,
for additional fractures to form, the wellbore
pressure has to exceed the fracture gradient plus
Wellbore Strengthening Solutions
7-1
the additional hoop stress. Hence, in theory, it is
possible to drill with mud weights that exceed
the original fracture gradient.
A novel approach calls for cooling the mud to
reduce the hoop stress at the borehole wall
before setting the stress cage and allowing the
mud temperature to increase. This has the effect
of creating a more permanent stress cage and
even higher ECD.
Although the stress cage concept is somewhat
controversial, it has been shown that
incorporating moderate concentrations of
large, granular materials into the whole mud
appears to prevent lost circulation in formations
and circumstances where often severe losses
previously had been noted. The technique
appears to be effective and well proven for
controlling losses in permeable zones. However,
less conclusive evidence suggests it also is
effective in shales and other impermeable
formations. On the other hand, other studies
suggest sealing microfractures in shales can
increase the integrity and apparent strength
of the formations without increasing the hoop
stress. Given that the WSM needs to form a
propped seal in proximity to the mouth of
the fracture, the type and size distribution of
particles is critical.
Various proprietary models describe the
optimum matching of WSM to the fracture
width, which is an area of active research within
the industry. Commonly used models share the
same particle plugging and packing theory as
that used for selecting WSM to generate effective
filter cakes for reservoir drilling fluids. Typically,
these models match the D90 of the WSM particle
size distribution to the maximum size of the
openings. Success in a Stress Cage operation
typically requires somewhat larger particles.
Results from Phases I and II of the M-I SWACOled Fracture Testing Joint Industry Project (JIP)
suggest that a match to the fracture opening
of the D55 to D75 of the WSM blend will provide
optimum sealing. Furthermore, it appears WSM
blends with bimodal size distributions provide
better seals than monomodal (monodisperse, or
single peak) WSM blends.
7-2
May 2011
For stress caging, the WSM also must possess
compressive strength sufficient to resist
the fracture closure stresses involved in the
operation. Thus, suitable WSM generally are
large, granular and tough. However, the marble
and graphite or graphite/coke particles often
used successfully, do not have the fracture
toughness required of typical proppants used in
stimulation treatments. Furthermore, extended
Leak-Off Tests before and after stress cage
treatments indicate no significant change in
the Leak-Off Pressure normally associated with
the Fracture Gradient. Rather, the Formation
Breakdown Pressure (FBP) is elevated, as might
be expected from a standard fracture tip screenout or isolation procedure. Normally, an elevated
FBP is associated with increased resistance to
fracture propagation (widening and elongation).
Stress cage treatments usually require
treatment of the whole mud with at least 45 kg/
m3 WSM. Typical treatments use blends of sized
synthetic graphite and crushed sized marble
(CaCO3). Sizing of the WSM is determined first
by calculating the maximum fracture width that
the desired wellbore pressure would generate.
Propping of these fractures to maintain the
calculated fracture width and then sealing them
with an optimized WSM blend would allow the
drilling operation to proceed under the elevated
wellbore pressure.
One technique for calculating the size
distribution of the WSM is based on the linear
elastic fracture mechanics theory. This approach
allows the fracture width to be calculated for a
given fluid pressure and fixed fracture length.
In many applications, the fracture length is
assumed to be 6 in (150 mm), meaning the
fracture lies within the wellbore stress field. The
input for such models includes:
* The elastic properties of the rock (Young’s
Modulus and Poisson’s Ratio)
* The far-field principal stresses (overburden,
minimum horizontal and maximum
horizontal stresses)
* Hole size
Wellbore Strengthening Solutions
* The deviation and orientation of the
wellbore.
The WSM concentration is determined from
semi-empirical particle packing models that
describe how the particles distribute within the
fracture. The interface for one stress cage design
software package is shown in Fig. 7-1.
Fig. 7-2. Wet Sieve Particle Size Analyzer
Ideally, managing the required concentration
and distribution of WSM is accomplished by
removing the large cuttings and Fines from
the flow line and returning the middle fraction
to the active mud system. While by-passing
the solids-control equipment usually is not
recommended, if the interval to be stress caged
is relatively short ( <100 meters) it may be
possible to circumvent the shakers equipment
entirely and simply rely on dilution to control
the concentration of drilled Fines. If the interval
is longer than 100 meters, it typically is more
economical to employ shale shakers with very
Coarse screens and use only the top level to
remove the cuttings, along with dilution to
control the concentration of drilled Fines. This
method is likely to be used mostly in the smaller
hole sizes ( 31.1 mm, 21.6 mm and 15.2 mm, etc).
Fig. 7-1. Software used to Design WSM for Stress Cage
Application
When either the FPR or Stress Cage technique is
applied cotinuously, it is essential to maintain
the required PSD of the mud. Monitoring of the
PSD or at least the trend in the PSD should be
done on-site, preferably continuously. An inline granulometer based on electrical or optical
techniques can provide this measurement. A
batch method based on wet sieve analysis (Fig.
7-2) is a good cost-effective alternative that
offers the advantage of removing drilled Fines
and weighting material so that they do not
mask the measurements of the WSM.
May 2011
Perhaps the most effective approach is
separating the drilled Fines and cuttings
while simultaneously recovering the majority
of the WSM for recycling through the active
pit. As shown in Fig. 7-3, a number of devices
configured for this purpose or a single apparatus
may be used. The three-level shaker shown
in Fig. 7-3 is configured in a series with three
different screen meshes: cuttings are taken out
at the top level, Fines at the bottom, and WSM is
recovered from the middle level.
Wellbore Strengthening Solutions
7-3
Fig. 7-3. WSM Recovery Devices
Fracture Closure Stress (FCS)
The FCS process involves using high-fluid-loss
pills to create and subsequently plug short
radial fractures in a weak formation once losses
have begun. These plugged fractures will act as
wedges, increasing the hoop stress around the
wellbore and enabling higher mud weights to
be used without additional fracturing. Unlike
the Stress Cage approach (see next section), the
FCS treatment is applied as a pill containing
relatively high quantities of WSM.
FCS is defined as the stress that holds fracture
faces together, or conversely it may be defined
as the fluid pressure required to open the
fracture. If the mud density is decreased to a
point where circulating pressure is less than the
FCS, the fracture will close and losses should
terminate. On the contrary, a pressure exceeding
this stress will cause the fracture to re-open
and losses will continue. The rock stress holding
the fracture closed is composed of two major
elements:
1. minimum principal far-field stress (aka the
minimum horizontal stress, or Shmin) created
by the overburden pressure; and
2. compressive stress developed at the nearwellbore face due to tangential strains as
the wellbore attempts to collapse. The latter
is also known as the “hoop stress riser” or
Stress Cage.
Of these two stresses, the horizontal stress is
the most difficult to overcome. Unlike the Stress
7-4
May 2011
Cage method, whereby fracture propagation
is minimized by sealing the fracture mouth
quickly with material containing a large, broad
PSD and allowing the pore fluid to bleed off into
the surrounding rock, the FCS method entails
widening the fracture by squeezing particulate
material that does not pack well, thereby failing
to create a tight filter cake. Large particles
of similar size and considerable roughness
are ideal. Diatomaceous earth is one of the
commonly used materials. The high-fluid-loss
plug created in the loss zone near the wellbore
becomes immobile as it “de-waters” i.e. as the
carrier fluid drains away into the formation. This
process prevents the transmission of pressure
to the fracture tip, thus halting any further
propagation.
As the fracture width increases, so does its
fracture closure stress. In other words, FCS is
enhanced by increasing the fracture width so as
to compress adjacent rock, instead of plugging
the tip of the fracture. Losses cannot occur if
FCS is less than the ECD. However, if the ECD
exceeds the FCS, the fracture will widen, the
“immobilized” plug will be bypassed, losses will
continue and the fracture will spread. Additional
hesitation squeeze treatments likely would
widen the fractures further to the point that the
FCS will become greater than the calculated ECD
of the whole mud while drilling. As a general
rule, multiple hesitation squeezes are required
in low-permeability rock to maximize fracture
width; fewer hesitation squeezes are required in
high-permeability formations.
Wellbore Strengthening Solutions
Relatively high concentrations of material
-- typically 150 to 300 kg/m3-- are used to
implement the FCS concept. The compressive
strength of the material is unimportant, as most
of the compressive strength of the immobilized
plug derives from the squeeze treatment. On
the other hand, high fluid loss is more critical,
as this accelerates formation of the immobilized
plug. An advantage of the FCS method is that
no attempt is made to control the length of
the fracture. Since the FCS approach requires
less product, some consider it more adaptable
to larger hole sections than the Stress Cage
method, which relies on continuous addition
of WSM. With its use of conventional FCS
materials, this approach is limited to permeable
formations, as are the bridging materials used in
the Stress Cage method.
Cross-linkable polymer plugs can be used to seal
fractures in impermeable formations, thereby
helping to isolate and stabilize the wellbore.
While much debate centers on whether this
stabilization actually is a strengthening
mechanism, it has been used successfully
to stabilize wellbores. In principal, the FCS
approach also may be applied to the whole
mud, but the logistics of maintaining an even
higher concentration of FCS material in the mud
as opposed to the WSM used in the Stress Cage
approach prohibits doing so. Furthermore, Ffine
particulates in the mud tend to lower the fluid
loss and compromise the high fluid loss crucial
to the successful implementation of the FCS
concept.
OPTI-STRESS
The proprietary OPTI-STRESS* model is the
preferred method for calculating the apertures
of fractures that are induced or re-opened
when the wellbore pressure exceeds either
the fracture gradient or fracture re-opening
pressure. It utilizes conventional hydraulic
fracture theory and determines the fracture
aperture caused principally by the overbalance
between the wellbore pressure and the fracture
gradient. The aperture is further defined by the
rock properties and wellbore geometry. Equally
important, the software provides guidance on
May 2011
suitable WSM blends to seal the fracture. The
following input data are required for the model:
Shmin: Far Field Min Horizontal Stress (Pa)
Shmax: Far Field Max Horizontal Stress (Pa)
Pw: Max Desired Wellbore Pressure (Pa)
α: Well Inclination (deg), or hole angle
E: Young’s Modulus (Pa),
ν: Poisson’s Ratio
PO: Overburden Stress (Pa)
φ: Hole Orientation, i.e. azimuth (deg)
θS: Stress Orientation wrt true North (deg)
D: Hole Diameter (mm)
The fracture aperture calculation is most
sensitive to the first five parameters, all of
which the operator can provide. Also, with
regards to the Pw, it should be noted precisely
at what point the desired pressure should be
obtained in relation to the maximum ECD
during operations, such as surge while running
casing.
Furthermore,
* If Shmax is not available, it can be assumed
that Shmax is equal in magnitude to Shmin, and
the parameter θS (azimuth of Shmax relative to
north) is set to zero.
* Poisson’s Ratio generally is between 0.1 and
0.35 for sandstone and 0.3 and 0.5 for shale
and mudstone.
* The calculation requires that a fracture
length is given. For convenience, and also to
account for the wellbore zone of influence,
the fracture length generally is set to 6 in.
(150 mm), unless otherwise indicated.
* In most cases where the Pw cannot be
obtained, assume the Pw is 0.06 sg higher
than the mud weight, or 0.12 sg higher than
the pore pressure.
OPTI-STRESS includes a number of algorithms to
calculate the optimum WSM blend for fracture
sealing. It is assumed there is a distribution of
fracture sizes up to the maximum opening size
OPTI-STRESS calculates. One algorithm utilizes the
D10-D90 range of the largest particles available
that can fit into the maximum opening size,
Wellbore Strengthening Solutions
7-5
and afterwards sequentially adds particles of
decreasing size to cover the entire range of
openings. Another algorithm utilizes the Ideal
Packing Theory incorporated in the companion
OPTIBRIDGE* proprietary software package. The
Ideal Packing Theory generates a packing
solution in which the D90 of the particle blend
matches the maximum opening size of pores
or fractures. Alternatively, the D50 (median size)
of the particles is matched to the average pore/
fracture size.
Experimental work by M-I SWACO on fracture
filling and sealing suggests larger particles
will provide a more efficient filling, propping
and sealing mechanism. The most recent data
suggests matching the D55 to D75 of the particle
blend to the maximum opening size. The
current version of OPTI-STRESS includes a packing
algorithm based on this experimental work.
An enhancement in OPTI-STRESS not present
in other industry models is that the fracture
width is reported as a probability distribution,
while the WSM solutions are reported for the
P10, P50 and P90 values of the fracture width. This
probability distribution arises from a Monte
Carlo analytical technique utilizing lower and
upper bounds and the most likely values of the
input parameters. Most of the other industry
models are deterministic and use only the
mean, median or worst case values for the input
data. Some general observations from modeling
work to date are:
* Fracture aperture correlates directly with the
overbalance between the wellbore pressure
and FG; i.e. by the difference between
Equivalent Mud Weight (EMW) and FG.
* In typical applications to date, fracture
apertures have ranged between 300 and 700
μm.
* Softer rocks (lower Young’s Modulus) result
in larger fracture apertures.
* Fracture aperture is proportional to the
square of the hole diameter.
7-6
May 2011
Wellbore Strengthening Materials
(WSM)
Certain particulate materials have proved to
be especially effective for plugging, bridging
and sealing fractures, and thereby enhancing
formation integrity and the apparent near
wellbore fracture gradient. These WSM are
granular with relatively high fracture toughness
and form a distinct class of high performance
materials within the larger LCM grouping.
Wellbore strengthening and loss prevention
treatments preferably (though not exclusively)
should be based with WSM for increased
probability of a successful treatment.
Classification and Use
Solids Type
Experience and extensive laboratory testing
indicate that blends of SAFE-CARB* (marble, a
metamorphic calcium carbonate), G-SEAL, G-SEAL
PLUS and G-SEAL Fine (carbon-based materials,
or CBM), NUT PLUG Fine and VINSEAL Fine and
Medium provide very effective fracture seals
that can sustain extremely high differential
pressures, e.g. high overbalance between
equivalent mud weight (EMW) and FG while
preventing further fracture propagation.
Ratio of Marble/Carbon-Based Materials
Laboratory tests and field experience suggest
the marble/CBM ratio can be maintained
between 75:25 and 25:75. The ratio is
determined by the PSD of the available marble
and how they have to be blended to obtain
optimum fracture sealing performance. Carbonbased or cellulosic materials are not desirable
for some reservoir applications as they cannot
be removed by conventional acid stimulation
techniques.
Particle Size Distribution (PSD)
The WSM must be large enough to enter and
bridge near the mouth of the fracture, as well
as bridge any pores in the rock matrix (to
enable a filter cake to form after the bridge has
been established) and seal the zone. In most
Wellbore Strengthening Solutions
situations, the fracture width will exceed the
pore throat size, so the WSM blend usually can
be designed around the fracture width. The
OPTI-STRESS software should be used to determine
the probable maximum fracture aperture
and the optimum blend and concentration of
WSM to be used. The software package yields
a fracture width window and a range of WSM
formulations based on rock properties and the
desired mud weight (or wellbore pressure).
Concentration
Effective fracture sealing is very dependent
on WSM concentration. Generally, the higher
the concentration, the better the results.
Experimental evidence suggests that high
differential pressures are sustained more
effectively when high WSM concentrations are
used to seal the fracture. OPTI-STRESS recommends
lower and upper limits to the WSM
concentration. As far as possible, the lower limit
should be used as a minimum requirement.
The most limiting factors with respect to
WSM concentration are rig-site logistics,
transportation, storage, re-circulation, the lowgravity solids content of the drilling fluid, and
disposal challenges. For example, assuming
all the marble is lost over the shaker screens
maintaining 60 kg/m3 of marble translates into
285 tons of marble for drilling 1219 m of hole at
30 m/hr at a flow rate of 1.895 cubic meter per
minute. Accordingly, logistics pose a significant
issue.
All-Purpose Pills
Four standard pre-mixed WSM blends have been
designed for treating partial and severe losses.
The four blends are engineered to plug fracture
apertures up to 1000 or 1200 μm, along with
providing exceptional fluid loss control in high
to extremely-high permeability formations.
The universal design of the blends is intended
for applications where the apparent induced
fracture size is unknown, such as in exploratory
wells. Consequently, these blends also are very
suitable for wellbore strengthening operations
where geo-mechanical information is very poor
or unreliable. In addition, WSM is provided as
a one- sack product, thereby simplifying rig
May 2011
logistics considerably. Product performance has
been confirmed by extensive laboratory and
field testing.
The four standard OPTISEAL products are:
* OPTISEAL I*: carbon-based material and
ground nut shells, plug fractures up to 1000
μm.
* OPTISEAL II*: carbon-based material and
marble, which plug fractures up to 1200 μm.
* OPTISEAL III: marble, carbon-based and
cellulosic material plugs fractures up to 1200
μm.
* OPTISEAL IV: marble plugs fractures up to
1200 μm.
OPTISEAL I is not recommended for use in
operations where WSM recovered from the
shaker screens is later milled and re-injected
with slop and cuttings.
Components of OPTISEAL I can cause clogging
of the cyclones used to mill/crush the solids.
Since OPTISEAL IV is composed only of marble, it
can be removed fully by acid-based treatments.
This material is well-suited for reservoir drilling
where the presence of other WSM may impair
productivity. The OPTISEAL blends can be used in
either water- or oil-based fluids. OPTISEAL III has
been specifically optimized for NAF.
The OPTISEAL blends are supplied in 25-kg sacks.
Alternatively, they can be pre-mixed at the
supply base in a reasonably high volume, highdensity slurry (2.5 sg) before shipping to the rig.
Wellbore Strengthening Solutions
7-7
Chapter 8 - Producing Zones
Effect of Lost Circulation on
Formation Damage Potential
When the loss zone is within or in close
proximity to a potential production horizon, the
use and subsequent removal of lost circulation
or prevention materials (LCM or LPM) could
result in formation damage. Therefore, selecting
the suitable LCM/LPM is critical, particularly
for open-hole completions, open-hole gravel
packing and sand control screens. In these
applications, it is best to incorporate LCM that
have a proven history and can be removed
by downhole treatments, such as with acid,
chelant and/or oxidizers. For example, calcium
carbonate LCM can be removed using acid
(typically 15% HCl).
M-I SWACO also has developed and successfully
applied alternate technologies and wellbore
strengthening materials, such as FORM-A-PLUG
II and new reversible/breakable crosslinkable
materials, that have proven to be effective
solutions for severe lost circulation in reservoir
formations. These products yield solid plugs that
are effective for sealing fractures and vugular
formations. At the time of this writing, these
new products are undergoing field testing.
Additional information can be obtained by
contacting Technical Services.
Acid-Soluble Conventional LCM
Acid-soluble calcium carbonates are the most
common lost circulation materials and should
be the first considered. Calcium carbonates are
found to be particularly effective in curing or
reducing lost circulation in permeable sand and
sandstone productive formations, as well as in
fractured carbonate and chalk reservoirs.
Recipes and Procedures
If maximum pore or fracture size or the
permeability is known, the proprietary
OPTIBRIDGE software package can be used to
design suitable LCM blending to bridge the
target pore or fracture size. However, as a
May 2011
general rule if the information necessary
for employing OPTIBRIDGE is unavailable, the
following recommended guidelines can be
followed. These procedures and subsequent
concentrations are highly dependent on the
reservoir formation and the severity of losses.
Seepage Losses: Up to 1.5 m3/hr
Background (whole mud) treatment
Add SAFE-CARB Fine to active system at 43 to 71
kg/m3
Partial Losses: 1.5 to 3 m3/hr
LCM Pills
SAFE-CARB 20 14 kg/m3
SAFE-CARB 40 100 kg/m3
This should bridge pores or fractures up to 150
μm.
Heavy Losses: 3 to 15 m3/hr
LCM Pills
SAFE-CARB 20 6 kg/m3
SAFE-CARB 40 63 kg/m3
SAFE-CARB 250 43 kg/m3
SAFE-CARB 500 31 kg/m3
This should bridge pores or fractures up to 500
μm.
Severe Losses: > 15 m3/hr
LCM Pills
CaCO3 grit
71 kg/m3
SAFE-CARB 40 71 kg/m3
SAFE-CARB 500 142 kg/m3
This should bridge pores or fractures up to 0.15
in. (4 mm).
An alternative formulation for heavy and severe
losses has been used successfully to manage
fractured North Sea chalks:
SAFE-CARB Fine
SAFE-CARB Medium
SAFE-CARB Coarse
VINSEAL
Producing Zones
57 kg/m3
43 kg/m3
26 kg/m3
5 kg/m3
8-1
The approximate ranges of particle sizes are:
FORM-A-PLUG II generates a solid plug in
the temperature interval of 4 – 140°C. At
temperatures between 140 – 150°C the plug
will set up, but after a couple of hours it starts
to “melt”. In this temperature interval the plug
can be used as a temporary cure. Under all
circumstances, the pill formulation should be
pilot tested on the rig. A reference pill should be
mixed and placed in a heating cabinet under as
equal conditions as possible to verify the set up
of the pumped FORM-A-PLUG pill.
D50 (μm)
2000 – 4000
17 - 23
40 - 50
240 - 260
450 - 525
CaCO3 grit
SAFE-CARB 20
SAFE-CARB 40
SAFE-CARB 250
SAFE-CARB 500
Preparation
Prior to entering the fractured formation,
the LCM pill should be made up. To prevent
agitation from mechanically breaking down the
particle sizes, the medium and coarse grades
should be added just before pumping.
The primary application of a FORM-A-PLUG II
pill is for severe lost circulation in or near the
production or injection formation. It is effective
in both water and oil/synthetic-base fluids. The
FORM-A-PLUG II pill is acid soluble, with more than
90% dissolved on contact with a solution of 15%
HCl.
FORM-A-PLUG II Acid-Soluble Reinforcing Pill
FORM-A-PLUG* II can be used to cure severe losses
in both water- and oil/synthetic-base fluids. The
plug sets up under static conditions by crosslinkable polymers and salt. Generally, for the
pill to heat and set, the plug should be left for a
minimum of 6 hr to set up.
Table 8-1 details the setting time vs.
temperature based on laboratory experience
with the appropriate nomenclature. Table 8-2
shows a typical formulation.
Table 8-1. Setting Time vs Temperature
Temp.°C
Initial
1hr
2 hr
3 hr
4 hr
5 hr
4
1
2
2-3
3
3-4
4
15
1
2
3
3-4
3-4
4
20
1
2
3
3-4
3-4
4
40
1
3
3-4
4
4
4
45
0
1
3
3-4
4
4-5
70
0
1
3-4
4
4-5
5
75
0
2-3
4
4-5
5
5
100
0
3
4
4-5
5
5
120
0
3
3
4
4
4
140
0
3
3-4
4
4-5
5
Nomenclature:
1. Initial
2. Viscous, but pumpable. No signs of setting
3. Intermediate, still pumpable
5. Set soft plug
6. Set plug
The following amount of chemicals should be
added to make 1 m3 of un-weighted FORM-A-PLUG
II:
4. Soft middle, edges set, not pumpable
8-2
May 2011
Producing Zones
Table 8-2: Typical FORM-A-PLUG II Formulation
TEMPERATURE,°C
4-20
20-40
40-70
70-100
100-140
FORM-A-PLUG II, kg
280
168
280
179.2
179.2
FORM-A-PLUG ACC, kg
140
84
140
89.6
89.6
FORM-A-PLUG RET, kg
---
---
20
20
20
cacL2, kg
25
---
---
---
---
Drill Water, kg
795
884
793
864
864
Solution Density, kg
1240
1136
1233
1152
1152
Adding barite to the plug will provide the
desired weight and will not affect the setting
time. The amount of barite needed can be
calculated by the weight of the un-weighted
formulation.
Mixing Procedures
The cross-linkable mechanism is a chemical
reaction. Therefore, it is important to control
the ingredients and mixing conditions carefully
in order to ensure the reaction proceeds
as expected. The following procedure is
recommended:
1. Ensure the pit and mixing lines are flushed
clean and free of salt, brine and/or any
materials that could affect the salinity or
pH of the pill.
2. Add the appropriate volume of drill water
to the pit; pH should be 6-8.
3. If a retarder is required, add it as fast as
practical via the mix hopper.
4. Add the appropriate quantity of plug via
the mix hopper at a rate of 3-4 min. per 25
kg sack (with good mixing equipment).
5. Shear to yield the polymers.
6. Add barite to desired density.
7. Keep the fluid dispersed with mild
agitation.
8. Immediately before pumping add the
appropriate quantity of accelerator. This
May 2011
should be added through the hopper as
quickly as possible, but making sure it is
evenly distributed throughout the mix
9. Displace the FORM-A-PLUG II to the well.
Viscous spacers – If the reservoir drilling fluid
is high in salinity, a minimum 1.5 m3 are
recommended ahead and behind the FORM-APLUG II. The spacer can either be water based or
oil based (synthetic/mineral oil), but should not
contain any salt. It should be weighted to the
same density as the drilling fluid and the FORMA-PLUG II.
Placement Procedures
The following procedures are recommended for
spotting the FORM-A-PLUG II in all hole sections.
Generally, it is recommended to leave the pill to
set up for 6 hr.
Partial Losses:
1. Calculate the volume required to fill 250 m
of open hole. This is the preferred volume to
pump.
2. If the drilling fluid is high in salinity,
viscous spacers (minimum 1.5 m3) are
recommended ahead and behind the FORMA-PLUG II.
3. Displace the FORM-A-PLUG II in the hole.
Depending on the operator’s preference
and any other well particulars, it is
recommended the FORM-A-PLUG II be set
either as a “Balanced Plug” or by “Pump and
Pull”.
Producing Zones
8-3
4. Once displaced, the string should be pulled
clear 50 m above the estimated top of the
plug.
5. Squeeze into the formation a volume equal
to 100 m of open hole and maintain a
backpressure of 1 – 2 MPa for 6 hr.
6. Start pumping the pill at surface until the
entire pill is out of the string. A maximum
of 1.5 hr. is recommended. If longer time is
required it is recommended to bullhead the
pill in place.
7. Time spent waiting on plug, circulating or
squeezing, should be performed with the
string out of the plug. Avoid the ballooning
effect of the plug. Any movement of the pill
will increase the setting time.
Total Losses:
1. Calculate the volume required to fill 250 m
of open hole. This is the preferred volume to
pump.
2. Pull 50 m above the loss zone.
3. Mix up a 5 m3 “Total Loss of Return Pill”
(described earlier) and pump in front of
the FORM-A-PLUG II as a viscous spacer (For
practical reasons this type of viscous spacer
can also be pumped behind the FORM-A-PLUG
II, minimum 1, 5 m3).
4. Bullhead into the formation a volume equal
to 100 m of open hole.
5. Once displaced, the string should be pulled
clear 50 m above the theoretical top of
plug (in case losses are further up the hole).
Afterwards, another volume equal to 50100 m of open hole should then be bullheaded into the formation. (When Total
Losses are experienced, the purpose of bullheading in two steps is to allow time for the
FORM-A-PLUG II to become more viscous and
not just disappear into the formation)
6. If formation integrity allows, maintain a
backpressure for 6 hr before drilling out.
Note: A maximum of 1.5 hr is
recommended from the time pumping the
8-4
May 2011
pill is started at surface to the time it takes
the entire pill to be out of the string. For
instance, if the drilling fluid pumps failed
prematurely, an alternative means should
be used to pump the fluid into place, i.e.
have the cement unit on stand-by as a
contingency.
7. Time spent waiting on plugging, circulating
or squeezing, should be performed with the
string out of the plug. Avoid the ballooning
effect of the plug and any movement of the
pill will increase the setting time.
Additional Information
* Once the accelerator has been added, the
fluid should be regarded as cement, as it will
cross link and set.
* The final composition should be pumped
immediately down hole.
* FORM-A-PLUG II can be pumped through the
BHA.
* Any fluid left in the string will set-up inside.
The fluid should be displaced properly and
spotted as required.
* It is recommended that the plug be left static
in place for a minimum 6 hr before drilling
out/dressing the plug.
* If possible, a sample of the pill should be
left static in a heating oven at the same
temperature as the lost circulation point.
This will confirm the setting time.
* Surplus FORM-A-PLUG II left in the pit should
be dumped while it is still in a fluid state.
Pit, lines and pumps should be flushed
thoroughly with drill water.
* Treat the fluid with care. The addition of
lime or calcium chloride to the system
causes rapid setting.
* Low pH will delay (or in extreme cases
prevent) setting up the FORM-A-PLUG II. Keep
acid out of the fluid. High pH will cause
rapid setting. Since the set-up rate increases
with temperature, avoid situations such as
Producing Zones
prolonged shearing of the fluid, which could
cause heating.
Other Breakable Reinforcing Plugs
M-I SWACO also is developing other polymerbased wellbore strengthening materials as
effective solutions to severe lost circulation in
reservoir formations. Similar to FORM-A-PLUG
II, these products are cross-linked polymers
and when set create a firm gel that effectively
seals off fractures and vugular formations.
However, they are stronger than FORM-A-PLUG
II. Additionally, EMS-8320 is NAF-based, while
EMS-8420 and FORM-A-PLUG II are water-based.
It works well with wellbore strengthening
materials such as G-SEAL PLUS. Since EMS-8320 is
sticky, back-pressure is needed to peel it off.
EMS-8420
EMS-8420 is a high-temperature and highpressure, water-based breakable reinforcing gel
plug. The working temperature range is from 65
to 175°C.
These new products are undergoing field
testing. For further information, contact
M-I SWACO Technical Services.
EMS-8320
EMS-8320 is an NAF-based breakable
reinforcing gel-sealing product. It can seal both
permeable and impermeable formations. The
working temperature range is from 20 to 135°C.
It is a ready-to-use plugging product, and thus
must be pumped as soon as the drum is opened.
May 2011
Producing Zones
8-5
Chapter 9 - Carbonate Formations
Holding nearly 60 per cent of world’s oil and
40 per cent of global gas reserves, carbonate
formations deserve special consideration. These
formations, likewise, pose significant challenges
to drilling and completion operations. Carbonate
formations tend to be more prone to develop
fractures and are more chemically active than
the silica present in sandstone reservoirs.
Much like limestone and dolomite, carbonates
often contain fissures, vugs and caverns full
of normally pressured fluids that cause severe
or total mud losses when penetrated. When
highly permeable carbonate formations are
drilled, sudden and total lost circulation occurs
as the higher density drilling fluid displaces the
normally pressured oil or water.
Several methods currently are used to combat
mud losses and whichever one is selected
should depend on the severity of the losses and
other factors such as the fracture gradient and
formation pressure.
Accordingly, this chapter was prepared as a
user’s guide to controlling massive losses in
carbonate formations.
General Characteristics
Lost circulation in carbonate formations
generally has the following characteristics:
Preventive Measures
Although lost circulation in carbonates is
not easily prevented or remediated, certain
measures can be taken to minimize the severity
of the loss. For more details, refer to Chapter
6 “Prevention”. Some of these preventive
measures include:
Set Casing Seat at the Top of the Formation
Casing should be set as close as possible to
the top of the fractured limestone formations.
This not only cases off any other potentially
troublesome formations, but also allows the
correct mud weight and other properties to be
selected before entering the limestone.
Minimize the Mud Weight
This is difficult to accomplish when formation
pressures are unknown or only estimated. As
such, it may be worthwhile to consider running
Repeat Formation Tests (RFTs) into the top of
the carbonate to obtain pressure data, but only
if this can be accomplished before any massive
losses have occurred.
Minimize Surge/Swab Pressures
1. Losses are sudden, can occur at any point in
the highly fractured limestone formation
and can vary from relatively minor to total
losses.
2. While generally not dependent on external
factors, implementing correct procedures
can, in some cases, control the severity and
consequences.
3. There is no guaranteed single method of
solving the lost circulation.
4. Usually, drilling these highly fractured
limestone formations can be accomplished
with perseverance, but documented
May 2011
experiences show it will be a time
consuming and extremely costly operation.
High surge pressures undoubtedly contribute
to the lost circulation problems experienced in
highly fractured carbonates. Pressure surges
can generate very high ECD in the smaller
hole sizes. For highly fractured formations, the
piston effect and resulting swab pressure can
cause severe washout and/or gas/fluid influx.
The VIRTUAL HYDRAULICS software should be used
for planning the maximum lowering or pulling
speed, acceleration and deceleration.
Some methods of reducing surge/swab
pressures are:
* When tripping in the hole, break circulation
frequently (at the shoe and every 1000 ft
Carbonate Formations
9-1
recommendation carries strong caveats about
avoiding LCM where well control problems, or
the risk of plugging the drill string, bit or even
choke were major issues. Today, it is believed
these concerns can be overcome by paying close
attention to the types of LCM and the limitations
of the hardware, especially downhole tools (more
information is available in Appendix 6 “LCM
Guidelines for Downhole Tools”).
(305 m), circulating for 10 to 15 min.
* Exercise extreme care when breaking
circulation on trips and connections;
rotation may assist in breaking gels.
* Avoid excessive circulation rates; restrict
penetration rates, if possible, to avoid
overloading the annulus.
* Pump and rotate out of hole to the surface
with a pump rate sufficient to prevent
swabbing. Close annular on connections.
Choose Appropriate Drilling Fluid
Select a drilling fluid that intrinsically has
properties to minimize the rate of invasion into
loss zones, particularly crevices and fractures.
The following guidelines can help in selecting
an appropriate fluid:
* WBM are preferred over non-aqueous fluids
* Fluids, such as DRILPLEX, APHRON ICS* and
FLOPRO* that are highly shear thinning, slow
more rapidly as they invade a loss zone.
* Fluids with “flat rheology” (RHELIANT, DRILPLEX).
with a viscosity profile does not change
significantly either with temperature or
mud weight (OB WARP, EMS 4200) will
minimize ECD variations in the mud column.
Maintain Good Drilling Mud Properties and
control ECD
Drill String Design
* Reduce MBT values.
During the design stage, having planned a
bypass system in the BHA, such as the WELL
COMMANDER*, ahead of area-restricted tools (mud
motor, MWD tools) would allow for the spotting
of all manner of treatments to fight severe lost
circulations without POH to change the BHA.
Refer to the ‘Circulating Tools’ in the Wellbore
Productivity Section of the M-I SWACO website.
* Consider using lubricants to reduce drag and
coefficient of friction.
Develop a Plan
* Maintain low gel strengths.
* If CO2 is present, treat mud accordingly to
prevent flocculation.
* Use VIRTUAL HYDRAULICS to monitor ECD and
prevent inducing losses
Use LCM in the Active Mud System
In previous guidelines, the suggested
concentration of LCM was 60 kg/m3, but that
9-2
Generally, it is thought the mud can be treated
with up to 150 kg/m3 of granular LCM that has
D90 < 1500 microns with little risk of plugging
any hardware. These products include marble
like SAFE-CARB (up to SAFE-CARB 1000), G-SEAL
and G-SEAL PLUS, VINSEAL (up to grade Medium)
and NUTPLUG (up to grade Fine). Whole mud
treatments with blends of these materials
especially can be effective for stabilizing long
loss zones. Particulates of other shapes, such as
fibers (M-I-X II) or blends like M-I SEAL, should
be used only in the whole mud at much lower
concentrations than the granular materials
to minimize the risk of plugging hardware.
If very large particles or high concentrations
or non-granular particulates are needed, it is
recommended that these be applied as pills,
although bypass subs, described in the “Drill
String Design” section are available to minimize
the risk of plugging downhole hardware.
May 2011
It is very important to known when to apply
alternative techniques, such as the. Mud Cap
method, if the conventional LCM methods are
unsuccessful. Planning ahead based on offset
well data is highly recommended and may help
minimize mud losses by optimizing the length
of the decision-making process in the critical
Carbonate Formations
situation. Please refer to Chapter 4 for more
information
Diesel-Gel (Gunk) and Diesel-Gel-Cement
Plugs
Treatments
While both gunk and gunk/cement plugs have
been used successfully, the use of cement gives
the gunk/cement plug the added benefit of
forming compressive strength.
Following is a summary of the more common
treatments for combating complete losses:
Standard Lost Circulation Materials
With its easy and fast application, LCM plugs
normally would be the preferred first stage of
treatment. However, where losses are severe or
complete, LCM plugs alone generally have not
been successful without first being combined
with other treatments, such as, sodium silicate
or cement. The size of the pill and proportion
of LCM very much depends on the severity
of the losses. The most consistently effective
LCM pills have been found to be mixtures
of fibrous, granular and flake LCM. Refer to
Chapter 4 “Classification of Lost Circulation
Materials” and Chapter 5 “Remedial Treatments”
for more details on typical formulations and
recommended mixing procedures.
Cross-linkable Polymer Pills
“FORM-A” cross-linkable pills (FORM-A-SET, FORMA-SET AKX) are blends of polymers and fibrous/
granular LCM designed to plug matrix, and
naturally fractured or vugular zones. When
activated with time, temperature and crosslinkable agents, the “FORM-A” products produce
a rubbery, ductile, spongy soft set gel that
effectively prevents fluid loss to the formation.
A new generation of engineered systems is
available for water base applications (EMS-8420)
and non-aqueous applications (EMS-8320).
They offer superior gel strength and formation
adherence and can be removed with specialized
treatment. EMS-8320 has been field-tested and
even blended with barite and granular LCM to
produce a gel that can be broken completely
when desired. EMS-8420 is a high-temperature
water-based pill with a consistency similar
to FORM-A-SET AKX that requires a minimum
temperature of 150°C, but an upper temperature
limit of 230°C.
May 2011
When the diesel/gel mixture, which is readily
pumpable, comes into contact with water
or water-based mud, the bentonite hydrates
rapidly and forms a “gel” plug. Controlling
the ratio of mixing with mud at the bit
theoretically can vary the strength of the gel
plug. Where severe or complete losses have
occurred, adding cement to the plug develops
compressive strength. This can be squeezed into
the formation to develop sufficient strength to
withstand the maximum ECD expected.
Gunk/cement treatments are the “next step”
after conventional LCM pills and “FORM-A” crosslinkable pills have failed to seal off fractures
or vugs. However, in large vugs or caverns
the “FORM-A” cross-linkable squeeze should be
repeated at least a couple of times or until there
is some indication that it is remaining in place.
One common cause of gunk plug failure is
the presence of surfactants in the diesel oil,
which prevents the clay and cement from
becoming water wet, thereby thwarting the
desired “gunking up” of the plug. Pilot testing
is recommended to alleviate any concerns over
surfactant being present in the diesel oil.
“Mud Cap” Drilling (MCD) Methods
As explained in Chapter 6, the “Mud Cap”
drilling (MCD) method is part of Managed
Pressure Drilling (MPD) and can be used to
complete a section where massive losses are
experienced and regaining circulation has
failed continuously. Although a Mud Cap can
be a relatively expensive and complicated
operation, it effectively has allowed drilling into
formations with total loss zones. Further, it has
the added benefits of reduced HSE exposure,
along and reasonable mud and rig time losses
compared to conventional drilling methods
using LCM.
Carbonate Formations
9-3
A Mud Cap is a column of mud on the annulus
side of the drill string designed to completely or
partially hold back the formation pressure. Two
MCD types currently are in use:
* Floating MCD with the density of the fluid
in the annulus slightly higher than the
formation pressure and the well open on
surface. The pressure exerted by formation
fluid and gases serves to balance the
weighted mud column. However, kick
detection is limited, because the empty top
hole annulus prevents direct communication
with the wellbore.
* Pressurized MCD or Closed Hole Circulation
Drilling (CHCD) – the mud column in the
annulus has slightly lighter mud weight
(usually 12 - 36 kg/m3 or 1 - 2 MPa SICP)
compared to the formation pressure
requirements. Accordingly, the well is
controlled by maintaining the surface
pressure on the Rotating Control Device
(RCD) or Rotating BOP head. The CHCD
allows for the greater degree of well control
and kick detection. It is the preferred method
for thicker zones of total losses and sour
formations. The method is also known as a
Light Annular Mud Cap Drilling or LAMCD.
A sacrificial fluid is pumped through the bit.
Usually any available non-damaging fluid
(seawater, production water, waste water)
will do, though it may need to be treated for
corrosion or sour gas inhibition. The drilling
continues in the ‘blind’ mode with no cuttings
returns on surface. If the drilling operation
allows, it normally is recommended that casing
be set just above the loss zone, as this simplifies
MCD applications.
9-4
May 2011
Theory
To understand how the Mud Cap works, it
is important to visualize what is happening
downhole. The carbonate reef has one or both of
the following possibilities:
* High porosity caused by vugs and caverns
interconnected and capable of holding a
large amount of drilling fluid offering little
chance of successfully sealing off with LCM
to enable full circulation
* Fractured formations again interconnected
with possible cavernous networks. These
formations have a higher success rate
of being sealed off primarily with LCM,
followed by squeezing away cement to seal
off permanently. However, this usually is a
short lived remedy and losses return when
any new hole is drilled.
The concept behind MCD is relatively simple.
Sacrificial water (sometimes treated with
corrosion inhibitors) is pumped down the drill
string to clean, cool and lubricate the bit. The
Mud Cap fluid is added on the annulus side. Well
control is maintained either by the column of
the weighted mud (Floating MCD) or surface
pressure at the RCD (pressurized MCD or CHCD).
The drilling continues in the ‘blind’ mode with
cuttings being consumed by the fractured
formations above the bit and below the Mud
Cap fluid.
Floating Mud Cap Drilling uses a column of mud
in the annulus with density heavier than the
formation pressure requires. This establishes
a balance between the mud and formation
pressure at some point below the BOP. The
annular at the surface stays empty. When the
formation pressure equals the mud hydrostatic
pressure, the well is in complete equilibrium.
However, when the seawater is pumped down
the drill string it exerts additional pressure
against the mud column, forcing the weighted
mud back out at the top of the column. This, in
turn, reduces the hydrostatic pressure below
that of the formation pressure, causing the
formation fluids to migrate into the annulus,
resulting in a kick.
Carbonate Formations
If weighted drilling fluids migrate into the
formation, the periodical additions required
as mud is consumed in the loss zone can
be calculated. However, it is the inability to
monitor the fluid level in the annulus directly
that leads to the difficulties in early kick
detection and well control. While the floating
mud cap was the first method of Mud Cap
drilling, it requires precise volume management
and the delay in kick detection makes it an
unsafe technique.
Pressurized Mud Cap Drilling
The development of new generation tools
opened the door for use of the rotating BOP
head, also known as RCD. The RCD allows the
drill string to be rotated with the BOP closed
and pressurized. The Mud Cap fluid used in the
annulus has a density slightly lower than that
required for balancing the formation pressure
(by 12 - 36 kg/m3). This column of lighter mud
maintains well control while creating positive
pressure on the RCD while drilling (about
200-300 psi). By monitoring the pressure at
RCD, the gas migration in the annulus can be
predicted and controlled. When gas migration
and expansion increases the annular pressure
to a pre-determined limit, the Mud Cap fluid is
displaced (bullheaded) through the choke lines
until all of the hydrocarbons are squeezed back
into the formation. Accordingly, reservoirs with
high H2S content can be drilled with no gas
observed on surface.
Before deciding whether to employ MCD, it
is critical the associated safety, economics,
logistical and formation injectivity issues be
evaluated carefully.
* Personnel safety: This must be guaranteed
when using an intrinsically risky MCD
operation. The rig and crew should have
proper tools, resources and training to
control a kick, especially when encountering
sour formations. This is complemented
with suitable capabilities to control
annular pressure and monitor any sour
gas or hydrocarbons. Because of the safety
implications, it is necessary that well-
May 2011
trained and experienced rig crews be used
for this method.
* Operational Economics: The net benefit of
MCD must be demonstrated to the client.
The economical factor is subdivided into
three main factors: Mud Loss Rate, Drilling
Time and Drilled Depth. Mud Loss Rate is
the break-even point between the cost of
losses with both the conventional drilling
and MCD fluids, including hauling base
fluid, mud cap preparation, kill mud and
any additional MCD equipment. Drilling
Time factors estimates the net gains on
drilling time with MCD after eliminating
flat-time associated with lost circulation
incidents. The Drill Depth factor accounts
for any further drilling achievable with MCD
that otherwise would not allowed with
conventional drilling.
* Logistics: Sufficient resources and labor
support must be available to maintain the
rate of required mud delivery. The drilling rig
setup must be able to accommodate enough
capacity to: a) store fluid at the location
(typically 300 - 500 m3); b) mixing
or blending capacity of approximately
16 - 32 m3/hr of fully formulated fluid. In
addition, an inexpensive and reliable water
source capable of supplying 1400 m3/day or
more to the rig site is required.
* Formation injectivity: Prevailing formation
injectivity pressures should be low enough
to enable injection of the sacrificial fluid and
entrained drill cuttings into the fractures at
an acceptable rate. The formation injectivity
pressure is the friction involved in pumping
a fluid into the fracture—the higher the rate
of injection, the higher the friction pressure.
Friction losses of 690 Pa are suitable for
MCD operations, as opposed to pressures
exceeding 5.5 MPa, which could exceed
the circulation pressure of conventional
systems. Before executing MCD operations,
it is advisable to carry out injectivity tests at
different rates or field characterization.
Carbonate Formations
9-5
Drilling Blind
When caverns are encountered that are too
large to effectively fill with mud to seal off
losses, drilling blind until competent beds are
encountered before setting casing has become
an established practice. However, owing to the
considerable mud products required, before
a decision is make to employ this practice,
costs and infrastructure availability must be
evaluated carefully.
Miscellaneous
Sodium Silicate and Cement Treatments
Sodium silicate treatments, with or without
cement, often can control severe to complete
losses in large fractures, vugs and some caverns.
The procedure involves spotting a slug of
sodium silicate solution into the formation,
followed with a spacer and seawater or, more
usually, a calcium chloride brine pill. The
calcium and silicate react on contact to form a
stiff gelatinous mass that may be competent
enough to block fractures and vugs.
With all silicate treatments, great care must
be taken to avoid contact between the silicate
and calcium chloride or the cement inside the
surface lines, drill string or casing. The use of a
suitable spacer is essential.
Foam and Aerated Mud Systems
Foam muds and foam cement can be applied
successfully in massive loss situations. However,
since little fluid pressure exists to support the
wellbore wall, using foam is only advised where
formation pressures are low and the rocks
competent.
High-LSRV Fluid Systems
Fluids with inherently superior low shear rate
viscosity (LSRV) prevent fluid from migrating
through the formation, thereby helping to
control losses. APHRON ICS and DRILPLEX have
proven to be effective LSRV fluid systems
for preventing fluid migration in carbonate
formations.
9-6
May 2011
The rheological profile of the APHRON ICS
system is designed to deliver high viscosity at
shear rates that are low, yet, high enough to
maintain micro-bubbles in solution, which are
non-coalescing and can be recirculated. This
produces an “at-balance” technique and makes
aphrons capable of acting as bridging solids in
the invasion mechanism. The aphron microbubbles bridge and pack off at the formation
openings of a permeable zone, but unlike
conventional solids, also are capable of adjusting
to bridge a fractured or vugular opening.
On the other hand, the effectiveness of
the DRILPLEX system is based on its notable
thixotropic features that provide high gel
strengths at static and fully fluid conditions
under high shear conditions. By delivering
increasing viscosity at low shear rate across
the fracture or vug at a constant hydrostatic
pressure, this feature helps lower invasion rates.
Recommendations
Field experience have demonstrated that
overcoming lost circulation encountered while
drilling fractured/vugular carbonate formations
can be extremely time consuming and costly in
terms of both materials and extended rig time.
Losses likely are to be instantaneous and can be
expected anywhere in the carbonate section.
Consequently, it is considered more prudent to
seal the hole as it is drilled and as losses occur,
as opposed to drilling the whole section and
attempting to cure losses later. Sealing the hole
during the drilling process at least may help
pinpoint any new loss zone encountered while
drilling (i.e., at the bottom of the hole).
If, the standard LCM pills are unsuccessful, the
next step should be pumping a high-fluid-loss
pill or a “FORM-A” or other cross-linkable pill. The
sodium silicate/cement or the gunk squeeze
treatment should be used as the third option, if
necessary.
It is critical to adhere strictly to using drilling
practices that minimize pressure surges and
ECD effects on the formation.
Carbonate Formations
Relying solely on LCM in the active mud system
is unlikely to control losses in large vugs
and caverns. Because of the risk of plugging
problems during well control situations, LCM in
the active system is not recommended.
If this method is selected, it is essential that
a clean dedicated tank be installed on the
rig for mixing and pumping the sodium
silicate treatment. This is critical to prevent
contamination which would have serious
operational and economic consequences.
LCM pills pumped before cement plugs should
exit the bit before the cement is pumped.
Using slick BHA and no bit nozzles helps reduce
the risk of blocking/sticking the string when
pumping LCM or cement.
Reasons for Failure
Planning carefully and familiarizing all
pertinent personnel with the procedures will go
a long way to ensure success.
Techniques and Procedures
When drilling carbonate formations, it is
essential that detailed procedures and written
operational instructions for combating lost
circulation are in place.
Continue filling the annulus through the kill
line until the pre-flush/spacer or LCM reaches
the bit. At that point, stop pumping down the
annulus to minimize contamination of the
treatment.
is in place may cause the treatment to be
disturbed/displaced.
Common reasons for failing to control and cure
the lost circulation in carbonate formations
include:
* Spotting the plugging materials at the
wrong place, i.e., not establishing location of
loss zone correctly
* Materials and technique not matched to the
type and severity of the losses
* Insufficient volume of the applied treatment
* Excessive squeeze pressure applied to the
plug after spotting
* The reluctance to proceed to the required
technique, as dictated by the type and
severity of the losses
Circulating the drill string after the treatment
May 2011
Carbonate Formations
9-7
Chapter 10 - Deep Water
Lost circulation in deep water operations is
basically the same problem that occurs on land
or in conventional non-riser offshore drilling
and that is the loss of whole mud to subsurface
formations. However, there are conditions
inherent to deep water drilling which make the
problem more prevalent and potentially more
serious. For this discussion, lost circulation after
the riser has been installed is considered. Unless
drilling with seawater, a column of mud in the
riser changes the potential for lost circulation
dramatically. Even when drilling with seawater,
incorporating solids into the column of fluid
in the riser increases the density of the fluid
and the hydrostatic pressure on the exposed
formations.
fracture gradient is high enough to allow
drilling with a riser and taking returns to the
surface. In addition, the shallower the water, the
shallower the fracture gradient. For instance,
assuming a minimum 1.14 sg fracture gradient
is required before running the riser to drill with
returns to the surface, the graph below indicates
that in 300 m of water, this point is reached
at about 270 m below the mud line (BML).
Compare this to 3000 m of water where 1100 m
of formation BML is required before reaching
this same 1.14 sg fracture gradient to run the
riser. Another observation is that at 600 m BML,
the fracture gradient in 3000 m of water is
only about 1 sg. In 150 m of water the fracture
gradient is about 1.4 sg.
As the water depth increases, the depth below
the mud line also increases before the formation
DE E P W A T E R F R A C G R A DIE N T S
A ir ga p = 50 ft
F R A C G R A DIE N T ppg
7.0
8.0
9.0
10.0
11.0
12.0
(Estimated)
13.0
14.0
15.0
16.0
17.0
0
1000
2000
3000
WD=500'
TVD Below Mud Line
4000
WD=1000'
WD=2000'
5000
WD=3000'
WD=4000'
6000
WD=5000'
7000
WD=6000'
WD=7000'
8000
WD=8000'
WD=9000'
9000
WD=10000'
10000
11000
12000
13000
Fig. 10-1. Deep water fracture gradients, depicting mud weights that are 90% of the
overburden weight equivalent. In cases, lost returns occur when the mud weight is increased
above 90% of the overburden.
May 2011
Deepwater
10-1
Causes and Effects
In addition to low fracture gradients,
unconsolidated sands, carbonate reefs, salt
fractures, and sub-salt rubble zones make
lost circulation more prevalent in deep water.
Because costs are high, great emphasis is put
on maintaining high average ROP, resulting in
imposed or mechanical stresses from tripping
in or out of the hole too fast, circulating
with excessive pump rates, and overloading
the annulus with drilled cuttings. All these
contribute to lost circulation.
One of the main concerns about lost circulation
in deep water is the potential for gas hydrate
formation. A sudden drop in hydrostatic
pressure due to the losses could allow natural
gas to enter the wellbore quickly. The gas could
then migrate up the wellbore where the cold
temperature at the mudline will allow hydrates
to form in the blowout preventers. Another
concern in deep water is the potential for riser
collapse due to evacuation of mud in complete
loss circulation or an emergency disconnect.
Preventive Measures
Well Planning
Preventive measures should begin in the
planning stages of the well. Potential loss
zones should be identified from offset data,
if available. The casing program should
be designed to minimize close tolerances
between ECD and the fracture gradient. A
seismic evaluation of the drilling site should
be studied for potential shallow gas / water
flows, salt, or any other structural abnormality.
The PRESSPRO RT or VIRTUAL HYDRAULICS program
should be utilized to predict ECD’s and pressure
losses, and determine casing setting depths.
Correspondingly, an appropriate mud, be it
WBM, SBM or a mineral oil-based drilling
fluid (MOBM), should be selected to minimize
potential problems.
• Staging in the hole after extended periods of
being out of the hole (especially with SBM)
• Starting pumps slowly after connections
• Staging pumps up slowly and rotating while
breaking circulation after a trip
• Control-drilling when ECD tolerances are
low.
Additional recommendations include:
• Use an APWD tool to monitor ECD values in
the hole
• Pre-treat with LCM if thief zones are known.
• Use the VIRTUAL HYDRAULICS program to predict
ECD’s while tripping.
• Keep the mud properties in proper ranges.
• Maintain the solids content at optimum
values to control filter cake thickness.
• Drill with minimal mud densities
• Keep fluid loss values as low as economically
feasible.
Running casing
Owing to reduced fracture gradients, deep water
wells generally have more casing strings at
shallow depths. VIRTUAL HYDRAULICS should be used
to determine safe running speeds and break
circulation several times while running casing.
Reduce rheological properties to minimal values
prior to running casing.
Controlling Deep Water Losses
The type and concentration of lost-circulation
material used is determined by the type of
loss zone, compatibility with the mud system,
and the drilling equipment being used. Most
lost circulation materials are compatible with
water–based muds, but some materials are not
compatible with oil-based and synthetic fluids.
It is important to exercise good drilling practices
such as:
10-2
May 2011
Deepwater
May 2011
SWEEP
Seepage Loss
<10 BPH
Seepage
Continues
10-15 lb/bbl CaCO3
10 lb/bbl KWIK SEAL
Resume
Drilling
NO
5-10 lb/bbl MIX II
Stage in Hole
YES
Mud Loss
Mix and Spot
Deepwater
Severe Mud Loss
20 – 30 BPH
OBM & SBM Lost
Circulation
Flowchart
Full Returns
Partial Returns
No Returns
Results
Displace to
Water base mud
If Still No Returns
Fig. 10-2: OBM and SBM Lost Circulation Flow Chart
FORM-A-SET
FORM-A-PLUG
DIASEAL M Squeeze
10-3
Chapter 11 - Ballooning
Ballooning, sometimes referred to as breathing,
is characterized by the combination of continual
mud flow from the wellbore when the pumps
are turned off and a loss of mud when the
pumps are turned on. The volume “lost” to
the formation when the pumps are turned on
typically is similar to the volume “gained” when
the pumps are turned off.
The volume gain on pump shutdown can flow
for upwards of 30 min and involve volumes in
excess of 16 m3. Consequently, the flow is often
mistaken as a kick. If the flow is assumed to be
a kick, and well control procedures are initiated,
lost circulation becomes a considerable risk.
Should ballooning, in fact, be the cause of any
observed flow from the well, increasing the mud
weight should be avoided at all costs. Since the
results of misinterpreting a ballooning scenario
can be severe, it is imperative that ballooning be
understood very clearly.
Typically, ballooning develops because of either
in-situ fractures in the formation being drilled
or induced fractures that have developed while
drilling. Regardless, ballooning is characterized
by mud flowing into fractures that are opened
as a result of the applied pressure of the
circulating fluid (the apparent loss of mud), and
the flow back of the same mud into the wellbore
as the fractures close upon the cessation of
circulation (mud gain on the surface). As drilling
of an interval reaches greater depths, the risk
of developing wellbore ballooning increases. If
mud weight is increased to manage wellbore
pressure, the combined effects of higher density
and ECD may push the wellbore pressure very
close to the fracture initiation pressure of the
weakest point in the interval, which typically
is the casing shoe. If this occurs, the pressure
may be sufficient for a network of fine fractures
to develop, without the fractures opening
sufficiently to cause severe lost circulation.
Alternatively, the increasing pressure may
be enough to open existing fractures. The
fractures then will open and draw fluid from the
wellbore, giving the mistaken impression that
lost circulation is occurring. When circulation is
stopped, the pressure in the wellbore decreases
and the fractures are able to close, displacing
the “lost” mud back into the wellbore and, again
wrongly, suggesting the well is flowing.
Managing to stay within the available pore
pressure-fracture gradient window, without
initiating ballooning, lost circulation, or well
control, is a major challenge, particularly in
deep water. As illustrated in Fig. 11-1, a limit
is approached where the wellbore pressure is
close to the pore pressure at TD and the fracture
gradient at the shoe, thus mandating casing
must be set.
Breathing initiated
High mud weight
Casing shoe
Start drilling
Interval TD
Insufficient mud weight
Well flows
Pore pressure
Fracture gradient
Fig. 11-1. Limitations of pore pressure/fracture gradient window while drilling
May 2011
Ballooning
11-1
Key criteria for identifying ballooning include:
* Monitoring and recording flow-back
volumes on connections
* For a ballooning wellbore, when the pumps
are off, the flow from the well will decrease
over time until the flow ceases. Flow will
continue at a constant or increasing rate if
the well is actually flowing (kick).
Ballooning in the Presence of Gas
One major issue that occurs with wellbore
ballooning, and one that adds tremendously
to the confusion, is the presence of gas in the
mud that is circulated back to the surface. If the
apparent losses occur in sands or at the interface
between sand and shale, the fluid that flows
into the fractures may come in contact with
hydrocarbons, specifically gas. When this occurs,
the entire volume that flows into the fractures
may subsequently contain a significant level
of gas when circulated back to the surface.
While understandable, it is a mistake to assume
this gas is the result of a kick arising from an
underbalanced drilling environment.
Under normal circumstances the drilling fluid
may absorb some gas from the near wellbore
region. Fluid that penetrates the formation
via fractures may adsorb a far greater amount
of gas. When this fluid is forced back into the
wellbore by the closing fractures and circulated
to the surface, it may appear the well is flowing.
To ensure the correct response can be initiated,
it is important to identify the source of any
gas or other hydrocarbons present in the mud
circulated to the surface.
To determine if the gas is due to the well flowing
or adsorbed gas associated with ballooning, the
following procedure can be applied:
After a connection has been made, circulate the
mud at a reduced flow rate for 30 min. before
resuming full circulation. This will allow gasfree mud to pass through the open-hole section
without entering fractures.
Track the strokes required for the mud to
reach the surface. Once the mud reaches the
11-2
May 2011
surface, if there is no gas present in the mud,
it can be assumed the previously recorded
gas is associated with mud entering fractures
(ballooning) and not a kick.
If gas is still present, the well most likely is
underbalanced, and the mud weight should
be increased. The reduced flow rate should
prevent fractures from opening and instigating
ballooning, while ensuring the mud does not
enter and then flow back out of the fractures.
Table 11-1 provides a guide for low
recommended circulation rates. The objective
with the slow flow rates is to pass a minimum
of (152 m) of mud through the annulus without
opening fractures that may be present.
Table 11-1. Recommended Slow Circulation Rates for
Evaluating Wellbore Ballooning
Hole Size (mm)
≥ 444
≥ 311
≥ 152
Circulating Rate
(m3/min)
0.95
0.38
0.095
Wellbore Characterization – Fingerprinting
techniques
In attempting to identify ballooning, it is first
important to characterize the behaviour of
the wellbore prior to the onset of suspected
ballooning. To do so, it is necessary to record the
volume of flow back mud and the time elapsed
for the flow to decrease to zero in an interval
that is not fractured. The best opportunity for
this is while drilling the cement. This provides
a completely sealed well with no chance for
mud flow into the formation via fractures. It
is important that the fluid, the flow rate being
applied, and the configuration of any surface
equipment (solids control units, de-gasser, etc)
be identical to that employed in drilling the
open hole section.
Automated systems are available for tracking
flow back on connections (Sperry-Sun
Connection Flow Monitor). Alternatively,
manual recording by the rig crew using a
Ballooning
stop watch and record sheet has proven to be
effective and reliable on many rigs in the Gulf of
Mexico. Figure 11-2 illustrates the data that can
be recorded with two approaches possible:
1. Record total volume returned and time for
flow to decrease to zero.
2. Record flow back volume every 15 sec. in
order to build a flow back profile.
60.00
50.00
40.00
11659.75 ft
11721.66 ft
30.00
11800.65 ft
11842.09 ft
11874.1 ft
20.00
11893.14 ft
11932.21 ft
10.00
11989.05 ft
0.00
0:00:00
0:01:26
0:02:53
0:04:19
0:05:46
0:07:12
Fig 11-2. Fluid Flowback Monitoring for Fingerprinting Ballooning
While Method 2 is more time consuming, the
ability to differentiate a kick from borehole
ballooning is enhanced greatly. The second
method also provides a clearer indication
that the well is in fact stable (even though
ballooning may be occurring) and that drilling
can recommence safely.
Once ballooning has been initiated, it is
important to realize that even though the
total volume that flows back will increase and
the time required for flow to reach zero may
increase, the shape of the flow back profile will
be similar. If a kick is occurring, the flow will
not decrease to zero and may actually increase.
The following procedure was used on a deep
water Gulf of Mexico well to fingerprint
May 2011
and monitor the wellbore for the onset of
ballooning:
1. Ensure all surface equipment is configured
for drilling ahead.
2. After displacing to a synthetic-based fluid
(SBM), circulate at a drill-ahead flow rate,
shut down the pumps and record the time
required for flow to decrease to zero, along
with the total volume gained in the active
system from the time the pumps are shut
down.
3. Repeat this procedure if an FIT/LOT is
performed after the displacement. If FIT/
LOT was performed prior to displacement,
proceed directly to Step 4. The times and
Ballooning
11-3
• If no gas is present, the previous gas
shows are associated with ballooning. If
gas is present, the well is underbalanced.
volumes recorded in Steps 2 or 3 will serve
as the base-line for a stable, non-ballooning
well.
4. On every subsequent connection and flow
check, record the time required for flow to
decrease and the total volume gained.
Managing Wellbore Ballooning
• Should the time or the volume increase,
the wellbore may be ballooning. The flow
rate from the well must be decreasing
with time.
• Should the flow from the well increase
with time or remain constant, the well is
flowing. Initiate well control procedures.
If gas is observed on bottoms-up after a
connection, and the well appears to be
ballooning, determine if the well is underbalanced using the following procedure.
• Note strokes for bottoms up.
• Apply slow circulating rates for 30 min
and record strokes.
• Resume normal drill ahead flow rates and
continue circulating until bottoms up
cycle is complete
LCM pills can serve as an effective remedy
to bridge off ballooning zones and minimize
the flow, but curing ballooning is a definite
challenge when drilling with SBM. Laboratory
testing on fractured cores indicates that fracture
re-opening pressures can be increased when
G-SEAL, is placed in the fracture (Fig. 11-3). The
resilient nature of G-SEAL is thought to be key to
the success of this LCM. If the material is placed
successfully in a fracture, once it closes it is able
to deform somewhat without breaking down.
That tendency allows it to maintain its ability
to stay in place and continue to bridge once
pressure is re-applied to the fracture.
Alternative methods for reducing or eliminating
ballooning via reduction in wellbore pressure
include:
1. Reducing mud weight if possible
2. Reducing the flow rate in order to lower the
ECD
50
Initial fracture
Re-opening, no LCM
Re-opening, 25 ppb G-Seal
Pressure (MPa)
40
30
20
10
0
0
5
10
15
Volume (ml)
20
25
30
Fig. 11-3: Increase in fracture re-opening pressure when G-SEAL placed in fracture. Re-opening
pressure is approximately 100% higher.
11-4
May 2011
Ballooning
3. Reducing the fluid rheology to lower the
ECD
necessary. Doing so will result in lost circulation.
A flow chart for identifying and managing
ballooning is provided in Fig. 11-4.
4. Reducing the rate of penetration
For options 2-4, consideration must be given to
the effect that changing these parameters will
have on other aspects of the operation. It may
also be necessary to adjust other parameters if
either of these options is applied.
Ballooning can be a sign of imminent lost
circulation. In a ballooning well, it is critical not
to weight-up the mud system unless absolutely
no
After having first established (while drilling cement)
the base-line flow-back volume and time, apply the
following flow-chart while drilling ahead.
Does the well give
back fluid on
connections ?
yes
Is the volume
greater than the
baseline volume ?
yes
no
no
Is the time for flow
to go to zero
longer than the
baseline time ?
Apply LCM sweeps to
seal ballooning zone
(review mud weight
and/or hydraulics)
yes
no
Is gas present
on bottoms up ?
yes
yes
no
Does flow go to
zero within
30 minutes ?
no
Is gas present
on bottoms up ?
Circulate at
reduced flow
for 30 minutes
yes
Drill ahead
Implement well
control procedures
Fig. 11-4. Wellbore Ballooning Flowchart
May 2011
Ballooning
11-5
Chapter 12 - Planning and Preparation
Some industry estimates indicate that up to 50%
of all lost circulation incidents can be prevented.
Consequently, lost circulation contingencies and
prevention procedures should be considered for
all drilling operations. However, it is important
to remember that these remedial treatments
will be most effective if planning is initiated
before the well is spudded.
Wellbore design can have a critical impact on
the risk of lost circulation, especially with regard
to hole cleaning. Some designs of tubulars or
implementation of procedures like reaming
while drilling create situations where it is
dificult to clean the hole properly or adequately
cement the casing. Clearly, the casing plan
exerts the single greatest influence in avoiding
lost circulation. In many cases induced fractures
occur because the intermediate casing string
was set too high and the mud weight required
to control deeper, high-pressure zones fractured
an exposed low-pressure formation. As a
general rule, there should be a minimum of
open hole between the casing shoe and the
expected loss zone. A high-quality casing design,
using all available tools and information to
identify potential problem zones, is critical, as
are information on fracture gradients and the
existence of depleted zones. Often, however, the
fracture gradient of depleted zones is unknown.
If cavernous formations are expected close
to surface, which is common in some land
locations, every effort must be made to set the
conductor pipe as close to the top of the loss
zone as possible. Plans for contingency casing
strings also may be required. If the loss zone
bears hydrocarbons, consideration needs to be
given to possible bull heading operations.
Preparing for Lost Circulation
In recent years the industry initiated a
continuing shift from reactive to more
proactive approaches on dealing with
prevailing lost circulation problems. Today,
concepts of improving the formation stresses
and strengthening the wellbores are widely
distributed, accepted, and in many cases,
May 2011
applied successfully. Early on, drilling fluid
companies were challenged to improve existing
materials and develop new techniques and
engineering strategies that would better fit
Wellbore Strengthening applications. Refer
to Chapter 7 for more detail on Wellbore
Strengthening Solutions and specific well
planning considerations when programming a
wellbore strengthening procedure.
Consideration also must be given to the stock
levels of LCM, base fluid, chemicals and barite,
along with mixing facilities and storage. As a
minimum, the stock list should include 300-400
sacks each of fine, medium and coarse LCM.
This should be a mixture of granular, flake and
fibrous materials. There also should be sufficient
material for at least four reinforcing plugs. If
there is a potential for severe loses, specialized
pills - reactive (crosslink able) and non-reactive
- should be included in the inventory. A detailed
list will depend on the location, the type of mud
and well configuration. As always, personnel
training and awareness is very important, with
action plans agreed upon in advance, if possible.
If severe losses are expected, two drilling fluid
engineers should be assigned to the rig full time
to manage the monitoring and recording of
volumes and preparation of solutions.
A multitude of tools and guidelines are
available for the Planning and Preparation
phase of addressing lost circulation issues. The
“Lost Circulation Assessment and Planning”
document, which was developed specifically
as an M-I SWACO training tool, focuses on
providing a detailed overview and a step-bystep approach to planning, implementing and
executing an efficient fit-for-purpose and wellspecific loss circulation strategy.
Drilling Fluid Design
When lost circulation is expected, selecting
a drilling fluid with minimum impact on the
rate of invasion into either existing fractures or
formation matrix can help mitigate or reduce
the volume of fluid lost.
Planning and Preparation
12-1
Fundamental differences in fracture
propagation pressures exist between waterbased fluids with elevated levels of bentonite,
low-solids-non-dispersed (LSND) fluids, and
non-aqueous fluids (NAF). These differences
are related directly to the nature and thickness,
or ‘quality,’ of the filter cake deposited by the
individual fluid systems. It has been shown that
the pressure applied to a fracture tip generally
is related to the thickness of the filter cake
formed within the fracture. Correspondingly,
this pressure correlates directly with the risk of
fracture propagation. The thicker the filter cake,
the less pressure being applied directly to the
fracture tip, thus making fracture propagation
less likely to occur.
Other properties, such as elevated low-shearrate-viscosity (LSRV), impart the intrinsic
capability of the drilling fluid to instantaneously
slow invasion into fractures. Fluids that
generate ECDs that change little during drilling
can be used in long and even multiple intervals
with less risk of exceeding fracture opening
or propagation pressures. Examples include
WARP* or EMS-4200* micronized barite systems,
which can be weighted up with little or no
effect on viscosity or ECD. Other examples
include the RHELIANT synthetic-based and
the DRILPLEX aqueous-based systems, whose
viscosity profiles are relatively independent of
temperature (flat rheology). These fluids can
provide near-constant ECDs in deep water,
where a very wide temperature range between
the mudline and BHT exists. Thus, these flatrheology systems have advantages over other
drilling fluids in that they generally will produce
lower rates of fluid invasion into fractures.
Chapter 6 “Prevention” has a more detailed
discussion on other fluids that exhibit similar
properties.
Usually, mud programs are determined through
an analysis of the formations to be encountered
during a drilling operation. Pre-spud planning
involves mud selection (water, oil, or synthetic),
as well as the fluid density, chemistry, and
rheology required for adequate hole cleaning,
optimum penetration rate and superior
wellbore integrity. If the fluid density is close
12-2
May 2011
to the fracture gradient, which raises the risk
of lost circulation, the rheological properties of
the fluid (i.e., plastic viscosity, yield point, 6 and
3 rpm dial readings and gel strengths) and the
pump rate should be controlled to minimize ECD
while maintaining adequate solids suspension
and hole cleaning.
Solids control is another important aspect of
drilling fluid maintenance. As drilling progresses,
drilled solids become incorporated into the fluid.
A high concentration of drilled solids affects
the rheology of the fluid. High rheology leads
to excessive annular pressure losses that can
promote induced fracturing. Every effort should
be made to control drilled solids to a maximum
of five percent by volume (5% v/v).
Proper pill placement also is a key to correcting
lost circulation problems. An out-of-gauge hole
can seriously impact accurate placement of lost
circulation pills. Placement of such pills usually
is dependent on measured pumping volumes.
Unless logs have been run and an accurate
knowledge of the hole volume is available,
the wellbore generally is assumed to be ingauge. This can lead to significant errors in the
placement of lost circulation pills, squeezes, and
plugs. Proper drilling fluid selection can help
maintain a stable and in-gauge wellbore, thus
affording the lost circulation material the best
chance to remedy the problem.
While NAF usually are much more expensive
than water-based fluids, they generally provide
the best overall drilling results, because of their
capacity to:
• Control shales
• Provide lubricity
• Resist contaminants.
During well construction, changes in lithology
may make it necessary to displace one system
with another. For instance, an inhibitive system
can be used to drill sensitive formations. Once
these formations are cased, the premium
system can be displaced with a less expensive
alternative for drilling the potential lost
circulation zones. Drilling economically in
Planning and Preparation
known or potentially troublesome areas
requires comprehensive knowledge of the
geology and efficient pre-well planning.
Chapter 6 provides additional details on
how maintaining proper fluid properties
and carrying out good drilling practices can
help minimize the risk of induced losses and
increase the chances of curing or preventing lost
circulation problems.
Chemical Load-Out Listing
It is critical to ensure chemicals are on hand
at the rig site or supply base sufficient to
build large volumes of mud, and multiple lost
circulation treatments.
Following is an example of the minimum
suggested levels of LCM which should be
available at most rig locations:
Standing Instructions
Standing instructions should be posted
to ensure the driller is aware of the crew
responsibilities in the event of losses. Standing
orders also should be prepared for the mud
loggers and the drilling fluids engineer. While
the instructions will be specific to each rig,
they universally must include the line-up of
all surface equipment. This will facilitate rapid
pumping of mud or water/seawater to the
annulus, along with well shut-in procedures and
criteria.
Pre-Spud Meetings
Product
Unit
Number
NUT PLUG (F)
NUT PLUG (M)
NUT PLUG (C)
MICA (F)
MICA (M)
MICA (C)
M-I SEAL (F)
M-I SEAL (M)
M-I SEAL (C)
M-I-X II (F)
M-I-X II (M)
M-I-X II (C)
SAFE-CARB (F)
SAFE-CARB (M)
SAFE-CARB (C)
22.7 kg/sack
22.7 kg/sack
22.7 kg/sack
22.7 kg/sack
22.7 kg/sack
22.7 kg/sack
418 kg/sack
418 kg/sac
418 kg/sac
11.4 kg/sack
11.4 kg/sack
11.4 kg/sack
22.7 kg/sack
22.7 kg/sack
22.7 kg/sack
80
80
80
120
120
80
100
100
100
150
150
150
200
200
200
May 2011
If the potential for severe loses exist, specialized
cross-linkable pills, such as FORM-A-SET, FORM-ASET AK, FORM-A-PLUG II, should be included in the
inventory.
A pre-spud meeting must be held with
all relevant drill-site managers (DSMs),
OIMs, rig managers, rig crews, drilling fluid
engineers, project engineers, and operator’s
representatives. A technical presentation on the
various problems and potential solutions should
be given to increase the understanding of all
personnel.
Notifying Relevant Personnel
Ensure the project engineers, operational
personnel and supply base coordinators are
aware the well is approaching a potential loss
zone.
LCM Logistics
As mentioned, a minimum LCM stock at both
the rig and supply base is highly recommended.
Both the project and rig site drilling fluid
engineers must put a plan in place so they are
fully aware of available stock at all times.
Planning and Preparation
12-3
Reporting System
circulation event review is available at
“Loss Circulation Review and Study Form”)
Lost circulation reporting and tracking
systems should be developed at three different
levels with two main objectives: building a
quantitative/qualitative offset database and the
identification and implementation of best fitfor-purpose cures and solutions.
Following is a hypothetical description of what
could be an effective reporting system and
one aimed at offering the best solutions to
the customer for their lost circulation-related
problems.
1. The drilling fluid engineer is responsible for
the: “When”, “How” and “How Much” data
collection, using the appropriate ONE-TRAX*
modules in the proprietary LOST CIRCULATION
ADVISOR* software. (Comments and Recaps
sections in Tab#5 of ONE-TRAX, and volume
accounting section in Tab #8 of ONE-TRAX).
2. The project engineer will carry out the
following tasks:
• Develop and offer project specific
solutions to the customer for their lost
circulation problems, focusing whenever
possible on a preventive approach under
the umbrella of the I-BOSS* integrated
wellbore strengthening package
• Evaluate the impact and results of the
lost circulation strategy. Document the
successes and failures, capture lessons
learned
• Re-evaluate the lost circulation plan and
communicate same to the client.
3. When applicable, technical service support
provided by the local Regional Technical
Service Manager (RTSM) and/or available
Technical Services Engineer (TSE) will
have the task to promote and implement
conventional and/or new lost circulation
solutions. Table 12-1 provides a checklist for
lost circulation planning and preparation.
• Produce a detailed summary including
relevant project-related data and a
detailed description of the lost circulation
events (an example form for a lost
12-4
May 2011
Planning and Preparation
Table 12-1. Lost Circulation Planning and Preparation Checklist
(source: “Lost Circulation Assessment and Planning Program)
This checklist should be modified and adapted to be project-specific.
Obtain offset
information and
client’s input
• Drilling and completion data (Drilling/completion program, Pore
Pressure/Fracture Gradient),
• Geology and lithology information (Porosity, Permeability, Core
samples),
• Logging and imaging data (FMI, OBMI)
• Identify potential loss zones
• Review previous lost circulation products and treatments used
Develop Lost
Circulation
Assessment Plan
• Analyze client’s input and offset data Link to existing M-I SWACO
products and technologies with potential to solve the problems
• Use the I-BOSS package and existing practices to create a well and
situation-specific program
• Develop and conduct internal and external adapted training and
presentations for the project
Deployment,
implementation
and execution of
the Lost Circulation
Assessment Plan
• Apply the procedures as per the Lost Circulation Assessment Plan
• Create and manage contingency stocks of conventional and
specialized lost circulation materials
• Monitor daily operations and ensure proper execution of the
recommendations included in the plan
• Report all successes and failures of lost circulation procedures
• Capture lessons learned and estimate added value to the client
May 2011
Planning and Preparation
12-5
Glossary/Nomenclature
APWD* - Annular Pressure While Drilling. APWD
data is used to prevent influx of formation
fluids, stabilize the wellbore, and ensure that
the pressure remains inside the pore pressure /
fracture gradient window.
CDR* Tool- Compensated Dual Resistivity Tool.
The CRD tool contains sensors operated by mud
pulses. No data is sent in real time when the
mud pumps are off; the data is stored and sent
to the surface once pumping is re-established.
Depleted Zone Drilling (DZD) – Drilling reservoir
sections with high pressure differentials
between formations. These invariably involve
large pore pressure differentials between
permeable and impermeable formations.
Dxx – The particle size below which xx% of
the particles exist, e.g. for D90 = 200 μm, 90%
of the particles are of a size less than 200 μm
equivalent diameter.
ECD – Equivalent Circulating Density. The
effective density of the fluid at downhole
conditions: ECD (kg/m3) = 19.2 x Ph+a (Pa) / TVD
(ft), where Ph+a is the hydrostatic head plus the
excess annular pressure. The hydrostatic head is
the static mud density (MW + cuttings acquired
at the bit); the excess annular pressure at a
given mud flow rate or velocity is governed by
the viscosity at the shear rate of the mud.
FG – Fracture Gradient. The pressure required
to fracture the rock (Fracture Pressure, Pf),
converted to Equivalent Mud weight at the
depth of interest: FG (kg/m3) = 19.2 x Pf (Pa) /
TVD (m).
Fracture Closure Stress (FCS) – The total
compressive stress holding the mouth of a
fracture closed. It is the sum of the combined
overburden and hoop stress riser stresses. It
has also been defined as the force required to
initiate a fracture.
FPR – Fracture Propagation Resistance. Strength
of the wellbore to limit fracture growth.
Hoop Stress – Induced tangential force around
the wellbore by the wellbore fluid when the
circumference of the wellbore is increased.
Hoop Stress Riser – Linear elastic response of
the near wellbore region of a formation to a
fracture. This is often referred to as a “Stress
Cage.”
LCAP - Lost Circulation Assessment Plan. Drilling
plan to assess lost circulation potential and
control lost circulation occurrances.
LSRV – Low-Shear-Rate Viscosity, usually
measured at about 0.06 sec-1.
LCM – Lost Circulation Materials.
LOP – Leak-Off Pressure. The maximum pressure
or mud weight the wellbore can hold without
new fractures forming or the mud “leaking off”
into the formation.
LPM – Loss Prevention Materials, now often
called WSM (Wellbore Strengthening Materials).
Materials used to prevent lost circulation
through strengthening the wellbore or plugging
fractures.
PP – Pore Pressure. Pressure exerted by
formation fluids in the pore space.
PSD – Particle Size Distribution. The distribution
of particle sizes, generally determined using
laser light scattering and reported in μm.
Shmin – Minimum horizontal stress around the
wellbore.
SICP - Shut-In Casing Pressure
Stress Cage – The increase in near-wellbore
strength (stress). It has been argued this is
identical to the concept of the “Hoop Stress
Riser”.
Wellbore Strengthening – A procedure designed
to increase the shear strength of a formation.
Examples include using a low-water-activity
OBM/SBM, mechanically increasing formation
hoop stresses, and isolating the wellbore and/or
fracture tips.
WSM – Wellbore Strengthening Materials.
Products added to the drilling fluid to
strengthen the wellbore and increase the
apparent fracture gradient, thus avoiding lost
circulation.
* Mark of Schlumberger, Ltd.
Unit Conversion Factors
Multiply This
By
To Obtain
Volume
barrel (bbl)
barrel (bbl)
barrel (bbl)
barrel (bbl)
cubic feet (ft3)
cubic feet (ft3)
gallon, U.S. (gal)
gallon, U.S. (gal)
cubic meter (m3)
cubic meter (m3)
pound (lb)
pound (lb)
kilogram (kg)
metric ton (mt)
feet (ft)
inch (in.)
inch (in.)
meter (m)
miles (mi)
lb/in.2 (psi)
lb/in. 2 (psi)
lb/in. 2 (psi)
kiloPascal (kPa)
bar
lb/bbl
kg/m3
lb/gal
kg/m3
lb/gal
lb/ft3
g/cm3, kg/L or SG
lb/100 ft2
degree Fann (° Fann)
dyne/cm2
centipoise (cP)
5.615
0.159
42
159
0.0283
7.48
0.00379
3.785
6.289
1,000
Mass or Weight
453.6
0.454
2.204
1,000
Length
0.3048
2.54
25.4
3.281
1.609
Pressure
6.895
0.06895
0.0703
0.145
100
Concentration
2.853
0.3505
Density
119.83
0.008345
0.11983
16.02
8.345
Miscellaneous
0.48
1.065
4.8
1.0
cubic ft (ft3)
cubic meter (m3)
gallon, U.S. (gal)
liter (L)
cubic meter (m3)
gallon, U.S. (gal)
cubic meter (m3)
liter (L)
barrel (bbl)
liter (L)
gram (g)
kilogram (kg)
pound (lb)
kilogram (kg)
meter (m)
centimeter (cm)
millimeter (mm)
feet (ft)
kilometers (km)
kiloPascal (kPa)
bar (bar)
kg/cm2
lb/in.2 (psi)
kiloPascal (kPa)
kg/m3
lb/bbl
kg/m3 and g/L
lb/gal
g/cm3, kg/L or SG
kg/m3 and g/L
lb/gal
Pascal (Pa)
lb/100 ft2
lb/100 ft2
mPa-sec
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Perander, m.: “The Perception of HSE
Regulations as ‘Hurdles’ to Implementation
of New Technology,” 2005 IADC/SPE Managed
Pressure Drilling Conf. and Exhib., San Antonio,
TX, April 20-21, 2005.
Rehm, B., Schubert, J., Haghshenas, A., Paknejad,
A. S. and Hughes, J.: “Managed Pressure
Drilling,” Gulf Publishing Company, 2008.
Roes, V.: “Managed Pressure Drilling in a Deep
Water Brown Field Environment,” 2005 IADC/
SPE Managed Pressure Drilling Conf. and Exhib.,
San Antonio, TX, April 20-21, 2005.
Santos, H.: “Prototype Testing Indicate Positive
Results for Secure Drilling Micro-Flux Control
System,” Drilling Contractor, p. 34, July/Aug
2006.
Shaikh, m.: “3-D Managed Pressure Drilling
Around a Salt Dome Using Coiled Tubing:
A Case Study, Challenges and Solutions,”
SPE 102608, 2006 Abu Dhabi International
Petroleum Exhib. and Conf., Abu Dhabi, U.A.E.,
Nov. 5–8, 2006.
Shelton, J.: “Experimental Investigation of
Drilling Fluid Formulations and Processing
Methods for A Riser Dilution Approach to Dual
Density Drilling,” m.S. Thesis, Louisiana State
University, Dec. 2005.
Smith, K.: “MPD Helps to Make Problems
Disappear,” Drilling Contractor, p. 48, Sept/Oct
2006.
Song, J. H. and Rojas, J. C.: “Operational
Considerations for Drilling Fluids for Wellbore
Strengthening,” 2005 IADC/SPE Managed
Pressure Drilling Conf. and Exhib., San Antonio,
TX, April 20-21, 2005.
Stone, C. R. and Medley, G.: “The benefits of
light annular Mud Cap drilling in naturally
fractured formations,” Offshore Magazine Jul 1,
2004.
Tennessen, T., Larsen, B. and Ronneberg, A.:
”Underbalanced Equipment Meets Challenges
in MPD Applications Offshore Norway,” Drilling
Contractor, p. 48, March/April 2006.
Valkó P. and Economides m. J.: “Hydraulic
Fracture Mechanics,” PP 86-87, John Wiley &
Sons Inc. 1995.
Van Oort, E., Friedheim, J., Pierce, T. and Lee, J.:
“Avoiding Losses in Depleted and Weak Zones
by Constantly Strengthening Wellbores,” SPE
125093, 2009 Ann. Tech. Conf and Exhibition,
New Orleans, Oct 4-7, 2009.
Warren, T., Houtchens, B. and Madell, G.:
“Casing Drilling Technology Moves to More
Challenging Applications,” AADE 01-NC-HO-32.
Appendix 1: LCM Products by Name
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
As a weighting
Baroid
Sized CaCO3; Acid Soluble
Granular
Grades
Porous and
ppg. Bridging agent. All mud systems
Temporarily seal lost
fractured
5-10 ppb for brigding
Acid soluble
White powder or
2.8
granules
production zones
circulation zones
- 9.5; #25
- 25; #50
Barofiber
Baroid
Fiberous cellulosic
loss control & diff. pressure
material used to seal
sticking preventive for
Fiber
fracture zones and porous
fractured formations
- 46; #150 170.
Preventative
All mud systems
Sands and
treatment @ 2-10
N/A
density: 31
5-7
lb/ft4
@ 30-50 ppb
WBM- need to treat
Regular- brown-
bulk
fractured zones ppb; Slug treatment
and sands
Filamentous fibers for
Baroid
sweeps or seepabe loss
Synthetic fiber
Fiber
control
Packaging
50 lb/sx
Medium, Coarse
powdered material;
Regular and
Coarse - granulated
Coarse
material
sweeping agent; does All mud systems
not increase viscosity
(1) 15 pound box/ 50
removed at
bbls
shakers
Insoluble
N/A
white fiber
with Algaecide/
Regular 25 lb/
biocide to
sx; Coarse 40
prevent bacterrial
lb/sx
contaminaion; OBM-
sands & limestone
Barolift
Remarks
Ultra fine, Fine,
Micronised Fiber
particulates for seepage
Limitations
D50's = #5
agent up to 14.0
Baracarb
Particle
Size
N/A
N/A
removed by shakers
N/A
15 lb box
Do not use in
Blend of particles which
Baroseal
Baroid
contains high strength
granules, flakes & fibers
Blend
All types of lost
circulation
Most WBM's
All formations
Preventative - 5-20
ppb; Pill - 30-50 ppb
with a definite PSD
by shakers and
OBM due to
Blend of different
Can be removed
N/A
1.1
mud cleaner.
materials; brown
Fine, Medium &
white and gray
Coarse
particles and fibers
May water-wet solids water wetting
in Invert emulsion
of solids; can
mud.
plug downhole
40 lb/sx
tools with small
tolerances.
Environmentally
safe, Bio-
Boysenblue/
Blen-Fyber OM
Celtec
International
Inc.
Preferentially oil wettable,
surface modified
Fiber
Seepage loss control
micronized cellulose fiber
Mainly NAF base Under-pressured,
muds
depleted sands
As slug (15-35 ppb) or
added to the system
degradable,
Light tan, finely
1.1 - 1.3
6.5 - 7.5
(4-10 ppb)
effective
divided cellulose
secondary
fiber
40 lb/sx
emulsifier due
to oleophyllic
properties
Pre-treatment & cure
Blen-Plug OM
Boysenblue/
Mixed, selected cellulose
for Lost Circulation for
Celtec
fibers, surface modified to
oil base muds - Can
International preferentially oil-wet in the
Inc.
Fiber
presence of oil & water
be used alone or with
Highly vugular,
Oil base muds
Blen-Fyber OM, Blen-
dolomite or
limestone
formations
As slug (20-40 ppb) or
added to the system
Dark brown to
1.3 - 1.5
6.5 - 7.5
tan mixed of sized
(4-12 ppb)
cellulose fibers
As slug (20-40 ppb) or
Tan to light brown
Coarse
By-pass shakers
when used
25 lb/sx
Seal WB, CaCO3,…
Blen-Seal WB
Boysenblue/
Micronized cellulose fibers,
Celtec
pre-absorbed with a low-
International
aormatic / low-toxicity
Inc.
lubricant
- Prevent, cure seepage
Fiber
losses, differential
sticking, high torque
& drag
All mud systems
Under-pressured,
depleted sands
added to the system
(4-8 ppb)
1.3 - 1.5
6.5 - 7.5 Micronized cellulose
fibers
Bio-degradable
& non-polluting,
environmentally
safe
50 lb/sx
Name
Company
Bor-Plug
Tanajiib
Description
High Fluid loss squeeze Blend of sized CaCO3
Type
Blend
Applications
Mud Systems
High fluid loss squeeze
Formation
Used
Recommended
Treatment
All formations
or as LCM.
Removal Temperature Specific
Techniques
Limit
Gravity
N/A
N/A
pH in
water
Product Form
N/A
Particle
Size
Grades
Wide
Fine, Medium &
range
Coarse
Limitations
Remarks
Packaging
50 lb/sx
LCM for drilling,
Blend of polymers, calcium
Bridgesal
TBC-Brinadd
lignosulfonate and sized
completion and
Granular
salt
workover into the pay
zone, gravel packing or
Saturated salt
mud
Porous and
fractured
production zones
10-50 ppb of bridgesal Water soluble
to the brine
Free flowing powder
salt
D50 of 18
Mud must be salt
microns
saturated
50 lb/sx
perforating
LCM for drilling,
completion and
Product
workover into the
Bridgesal-A
TBC-Brinadd
Blend of polymers and
sized salt
Granular
pay zone, gravel
Saturated salt
packing or perforating
mud
with low Ca/Mg for
Porous and
Water soluble
fractured
salt
production zones
Mud must be salt
Free flowing powder
saturated
functions as
a neutral or
50 lb/sx
slightly acidic
pH system
formation with calcium
sensitivity
BridgesalSuperfine
TBC-Brinadd
sized salt of particle size
No alkaline
Gravel packing
Blend of polymers and
Granular
range from 1 to 40 microns
applications where
Saturated salt
plugging of the screens
mud
must be avoided
KMC/SCOMI
Shredded cellophane
Flake
plugging channels and All mud systems
void spaces
Prevent mud loss by
Cellophane
M-I SWACO
Shredded cellophane
Flake
60-70 pound per
fractured
barrel of brine
production zones
solution
Water soluble
Free flowing powder
salt
1 to 40
Avoid cross-linkers
microns
and breakers
plugging channels and All mud systems
void spaces
Porous, vugular
Check-Loss
Baker Hughes
loss control and differential
or fractured
Porous, vugular
or fractured
added to the system
sticking preventative for
fracture zones and porous
sands &/limestone
material used to seal
depleted formations
and sands
50 lb/sx
N/A
(5-10 ppb)
As slug (20-30 ppb) or
added to the system
N/A
(5-10 ppb)
Will not water
Fiberous cellulosic
Fiber
needed for
the product to
As slug (20-30 ppb) or
Micronized fiber
particulates for seepage
materials are
function
Prevent mud loss by
Cello-Flake
Porous and
All mud systems
Porous, depleted maintained in system
formations
or in pills
bulk
N/A
N/A
density: 800
3
kg/m
N/A
Light brown, solid
Coarse and
PLUS
wet; bridging
N/A
N/A
microfractured
and permeable
formations
N/A
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
For porous, fractures
and vugular
Chip Seal
Coarsely shredded wood
Fiber
formations, where
Porous and
All mud systems
large particles bridging
fractured
formations
materials are needed
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
concentration for
Packaging
Better succes
0.5 to 1.0 ppb for
seepage, and higher
Remarks
Will be screened at
Not removed
shakers
complete losses
in sealing loss
zones when
40 lb/sx
combined with
smaller fibers
- Cure losses in
depleted sands -
Boysenblue/
Cruseal
Celtec
Graded & sized crustacean
International
flakes
optimum
Reduce torque &
Flake
drag, differential
All mud systems
sticking, bit balling -
Inc.
Depleted, porous
sands
As slug (20-40 ppb) or
added to the system
Acid soluble
(5-10 ppb)
Stable at high
temp.
performance is
White to orange
1.73
Fine & Medium
flakes
obtained when
50 lb/sx
fine & medium
Plug perforations in
blend is used
workovers
50% soluble
Delta "P"
Venture
Chemicals, Inc.
Polysacharide complex
Fiber
Bridge depleted porous
Water mud
Porous, depleted
formations
systems
formations
2 to 8 ppb for whole
Increase
in 15% HCl,
mud and 10 to 50 ppb biodegradable
as pills
6
and low temp.
Light tan to brown
fibrous powder
85% passes
Low temp. stability rheology at high
60 mesh,
- will be removed at concentration -
dry basis
shakers
stability
25 lb/sx
Pilot test if used
in OBM
Mix per tech bulletin,
then pump into
High fluid loss squeeze
Diaseal M
Many
(polymers and non acid
Companies
soluble LCMs, not requiring
High fluid loss squeeze
Blend
for WBM or as LCM in All mud systems All formations zone depth; then pull
WBM and NAF.
an accelerator or retarder).
mix of white/gray
annulus to the loss
N/A
N/A
0.8
N/A
pipe above plug and
particles and black
N/A
and tan granules and
into the loss zone.
Bimodal particle
Mix per tech bulletin,
size distribution
then pump into
Duo-Squeeze H
Baroid
High Fluid loss squeeze Blend of sized CaCO3
Blend
mix of white/gray
annulus to the loss
for WBM or as LCM in All mud systems All formations zone depth; then pull
WBM and NAF.
N/A
N/A
1.8
N/A
pipe above plug and
shows efficient
particles and black
Wide
Fine, Medium &
sealing of 190
and tan granules and
range
Coarse
micron pores
fibers
"squeeze" the plug
slots; Can be
weighted.
Fine:
Works at any
91.6% thru
Drilling
Fiber
Specialties Co
Proprietary Solid Mixture
Fiber
Seepage to complete
loss of circulation
All mud systems
Depleted, porous
zones
As slug (25-35 ppb) or
added to the system
(3-8 ppb)
28.3% soluble in
Stable at high
Brownish red
15% HCl
temp.
powder
200 mesh
- Medium:
37% Coarse:
32.4%
Mix per tech bulletin,
KMC/SCOMI
(polymers and non acid
soluble LCMs, not requiring
an accelerator or retarder).
pH, resistant
Fine, Medium &
to attack by
Coarse
bioorganisms,
25 lb/sx
compatible with
other LCM
then pump into
High fluid loss squeeze
EZ-Squeeze
50 lb/sx
to 1000 micron
into the loss zone.
Dynamite Red
40 lb/sx
fibers
"squeeze" the plug
High fluid loss squeeze
0.5 ppb oil
wetting agent
High fluid loss squeeze
Blend
annulus to the loss
for WBM or as LCM in All mud systems All formations zone depth; then pull
WBM and NAF.
pipe above plug and
"squeeze" the plug
into the loss zone.
N/A
N/A
2.8
12.4
mix of white/gray
particles
25 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Remarks
Packaging
Similar to I-BOSS
Mixture
Micronized fiber
particulates for seepage
Fibro-Seal
KMC/SCOMI
loss control and differential
sticking preventative for
Porous and fractured
Fiber
formations, depleted All mud systems
sands
fracture zones and porous
Depleted, porous
zones
As slug (25-35 ppb) or
Medium and
added to the system
coarse
(3-8 ppb)
sands & limestone
Blend of LCM to provide
FlexPlug
Baroid
Chemical Sealant plug;
Polymer blend
Blend
a stress cage for the
borehole and improve
All mud systems All formations
Preventative or Pills
N/A
N/A
mixed
mixed
2
7-8
mixture
Wide
Fine, Medium &
range
Coarse
frac gradients
Pumpable lost
FORM-A-PLUG II
M-I SWACO
High Fluid loss squeeze Blend of sized CaCO3
Blend
Circulation plug is a
Mix, then pump into
blend of minerals and
annulus to the loss
polymers to create
suspension, fluid-loss
All mud systems All formations
zone depth; then pull 95% Acid soluble
pipe above plug and
control and cross-
"squeeze" the plug
linking to plug the loss
into the loss zone.
in 15% HCl
White to beige
powder
Do not stop pumping Can be adjusted
Fine
while plug is in pipe.
for density.
Pilot test for
Follow
55 lb/sx
zone.
Cross-linkable Polymer
Plug with sized LCMs (flake,
FORM-A-SET (AKX)
M-I SWACO
fiber, granular, etc.) with
Blend
accelerator or retarder.
All types of lost
circulation
Fractures, faults
All mud systems
and vugular
formations
As a pill spotted in
loss zone
Bulk
N/A
0.96
density
Light tan powder
Fine
temperatures above instuctions from
34.5 lb/ft3
250 F
47 lb/sx
FAS software.
These are non-acid soluble.
High fluid loss squeeze
FORM-A-SQUEEZE
M-I SWACO
(polymers and non acid
soluble LCMs, not requiring
Blend
All types of lost
circulation
Fractures, faults
All mud systems
and vugular
formations
and accelerator or retarder).
As a pill spotted in
somewhat acid
loss zone
soluble
450 F
1.7
Not 100 % Acid
Gray powder
soluble
Cures without
time or
50 lb/sx
temperature
Micronized fiber
particulates for seepage
Fracseal Fine
Summit
loss control and differential
sticking preventative for
Porous and fractured
Fiber
formations, depleted All mud systems
sands
fracture zones and porous
Depleted, porous
zones
As slug (25-35 ppb) or
Fine, Medium &
added to the system
Coarse
(3-8 ppb)
sands & limestone
Blend of particles which
Gel Fib
Gumpro
contains high strength
granules, flakes & fibers
with a definite PSD
Blend
All types of lost
circulation
All mud systems All formations
As a pill spotted in
Cannot be
Blend of different
Fine, Medium &
loss zone
removed
materials
Coarse
May water-wet solids
in Invert emulsion
mud.
40 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Remarks
Packaging
High fluid loss squeeze
Gel Seal M
Gumpro
(polymers and non acid
soluble LCMs, not requiring
Blend
All types of lost
As a pill spotted in
circulation
loss zone
and accelerator or retarder).
LCM for bridging and
G-SEAL/G-SEAL
PLUS/G-SEAL
M-I SWACO
PLUS C
Synthetic Graphite; non
acid soluble
Granular
plugging formations.
Also increases lubricity
Can be run in active Can be removed
All mud systems
system or in pill form.
at shakers
500oF
Black powder or
2.19-2.26
granules
in fluids.
Avg.
Can be removed by
size 250
shakers. Not acid
microns
soluble.
Insoluble in
water
50 lb/sx
45 bbls of freshwater
Hydro-Plug
Baroid
Hydrating Polymer Blend;
Hydrating Gel Plug
Blend
All types of lost
circulation
Cavernous
All mud systems
and vugular
formations
+ 80 50 lb bags
of Hydroplug, No
Cannot be
Caustic and ime. Spot
removed
N/A
2
N/A
dark gray to black
granules and flakes
90-120 minute
N/A
N/A
pill across zone, and
Must be mixed
window is required in freshwater if
to mix and pump
used with NAF.
Mud must be salt
brines ranging
saturated
from 12.5 to 19.2
50 lb/sx
squeeze
Added to high density
Blend of sized salt,
Hysal-II
TBC-Brinadd
complexed lignisulfonates
CaCl2, CaBr2 and
Granular
and selected polymers
ZnBr2 brines to provide
bridging and filtration
Saturated salt
brines
Porous and
fractured
production zones
control
100 ppb of base
Can be used in
fluid, and 150 ppb
Water soluble
for densities above
salt
250oF
Free flowing powder
17 ppg
ppg
100 ppb of base
Can be used in
50 lb/sx
Added to high
density CaCl2, CaBr2
Blend of polymers and
Hysal-Superfine
TBC-Brinadd
sized salt of particle size
and ZnBr2 brines to
Granular
range from 1 to 40 microns
provide bridging for
gravel packing where
Saturated salt
brines
Porous and
fractured
production zones
plugging the screens
fluid, and 150 ppb
Water soluble
for densities above
salt
Free flowing powder
Avoid cross-linkers
brines ranging
and breakers
from 12.5 to 18.5
17 ppg
50 lb/sx
ppg
must be avoided
Prevent mud loss by
Jel Flakes
Baroid
Shredded cellophane
Flake
plugging channels and All mud systems
void spaces
Solids free cross-linkable
K-Max
Baroid
HEC polymer gel for
completions
Blend
All types of lost
circulation
Porous, vugular
or fractured
Cavernous
All mud systems
and vugular
formations
As slug (20-30 ppb) or
added to the system
N/A
(5-10 ppb)
as a pill spotted in
Cannot be
loss zone
removed
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Name
Company
Description
Type
Applications
Mud Systems
Prevent mud loss by
KMC-Mica
KMC/SCOMI
Mica flakes
Flake
plugging channels and All mud systems
void spaces
Formation
Used
Porous, vugular
or fractured
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
As slug (20-30 ppb) or
added to the system
Product Form
Particle
Size
White to grey
N/A
Insoluble
2.6-3.2
N/A
(5-10 ppb)
powder or soft
N/A
translucent flakes
Grades
Fine, Medium, &
Coarse
Blend of particles which
Kwik-Seal
Kelco-Rotary
contains high strength
granules, flakes & fibers
Blend
All types of lost
circulation
All mud systems All formations
Cannot be
Blend of different
Fine, Medium &
removed
materials
Coarse
with a definite PSD
LC Lube
Baker Hughes
Synthetic Graphite; non
acid soluble
Granular
LCM for bridging and
plugging formations.
Can be run in active Can be removed
All mud systems
system or in pill form.
at shakers
o
500 F
Black powder or
2.19-2.26
granules
Limitations
Remarks
Packaging
N/A
25 lb/sx
more effective when
mixed with other
types of LCM
May water-wet solids
in Invert emulsion
40 lb/sx
mud.
Avg.
Can be removed by
size 250
shakers. Not acid
microns
soluble.
Insoluble in
water
50 lb/sx
Shear thickening slurry
LCP-2000
EDTI or Impact with graded LCMs; Special
Solutions
Polymer + fiber, granules
Blend
All types of lost
circulation
& flakes
Liquid Casing
Gabriel
Blend of fibrous particles
International,
integrated with their
Inc.
distinctive size distribution
Porous and fractured
Fiber
Depleted, porous As slug (25-65 ppb) or
formations, depleted All mud systems
sands
and fractured
added to the system
formations
(2-8 ppb)
35% soluble in
15% HCl, & the
remainder is
> 400oF
< 2.0
7
biodegradable
< 234
Requires
microns
small addition
upper
of NaOH,
limit and
Non-Toxic &
44microns
environmentally
lower limit
safe
50 lb/sx
D50 of 19
for liteplug
Sized to temporarily
seal lost circulation
Liteplug
TBC-Brinadd
Specially sized borate salt
Granular
zones in porous and
fractured formations,
Used in Litesal
brine systems
Porous and
fractured
production zones
5 to 65 ppb of varying
sizes
fine, 300
Soluble in acid,
fresh and brine
2.0
Free flowing crystals
waters
for liteplug
Fine, liteplug,
and 640
liteplug-X
microns
depleted sands
Liteplug will seal
fractures up to
50 lb/sx
one-third inch
for
liteplug-X
Can be used as
Blend of polymer and
Litesal
TBC-Brinadd
specially sized borate salts
(Ulexite ) hydrated calcium
sodium borate salt
Bridging materials to
Granular
minimize losses in low
density brine (Na or K )
application : 8.7-10 ppg
Sodium or
Porous and
Potassium
fractured
chloride solutions production zones
circulating fluid,
20 - 30 ppb
Water soluble
salt
Free flowing powder
D50 of 20
lost circulation
microns
pill, perforating
or gravel packing
fluid
50 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Remarks
Packaging
pH-6, a
supplemental
Thixotropic system
Blend of XC-Polymer,
Litesal-XCP
TBC-Brinadd
derivatized polymer and
Granular
sized borate salt
designed for
application where max.
suspension is required.
additive is
Sodium or
Porous and
Potassium
fractured
18 - 35 ppb
chloride solutions production zones
necessary to
Water soluble
Free flowing powder
salt
stabilize the
50 lb/sx
system and
avoid crosslinking of the
XC-Polymer
Need to predisperse in
Micronized cellulose fibers,
Lubra-Seal
SUN Drilling
Products Corp.
Depleted,
chemically modidied by
a reaction with surface
Fiber
modifiers. Hydrophobic
Seals depleted sands
and micro-fractures
All mud systems
porous and
micro-fractured
formations
nature.
diesel oil prior
As slug (20-150
450oF
ppb) or added to the
0.4
addition to
Light brown powder
WBM. Effective
system (4-10 ppb)
30 lb/sx
secondary
emulsifier in
OBM
No asbestos,
Extrusion spun mineral
Magma Fiber
Lost Circulation flexible long fiber, coated
Specialists, Inc with a mono nuclear film
Fiber
Losses in fractures,
permeable formations
All mud systems
All types of
formations
of surfactant
As slug (30-40 ppb) or
98.4% in HCl,
added to the system
or 60/40 HCl &
(5-15 ppb).
Acetic Acid
inert, non-
Wide
1800oF
2.6
<8
Powder
range,
fermenting,
Fine & Regular
non-corrosive,
Coarse
40 lb/sx
environmentally
safe
Acid soluble (95%)
Magne-Set
Baker Hughes Crosslink Polymer Gel with
Blend
Retarder and accelerator
All types of lost
Acid soluble
circulation
(95%)
Prevent mud loss by
M-I Flake
Baker Hughes
Shredded cellophane
Flake
plugging channels and All mud systems
void spaces
Prevent mud loss by
MICA
M-I SWACO
Mica flakes
Flake
plugging channels and All mud systems
void spaces
Prevent mud loss by
MicaTex
Baroid
Mica flakes
Flake
plugging channels and All mud systems
void spaces
Porous, vugular
or fractured
Porous, vugular
or fractured
Porous, vugular
or fractured
As slug (20-30 ppb) or
added to the system
N/A
(5-10 ppb)
As slug (20-30 ppb) or
added to the system
White to grey
N/A
Insoluble
2.6-3.2
N/A
(5-10 ppb)
As slug (20-30 ppb) or
added to the system
(5-10 ppb)
powder or soft
N/A
translucent flakes
White to grey
N/A
Insoluble
2.6-3.2
N/A
powder or soft
translucent flakes
N/A
Fine, Medium, &
Coarse
Fine, Medium, &
Coarse
more effective when
mixed with other
N/A
40 lb/sx
N/A
N/A
types of LCM
more effective when
mixed with other
types of LCM
Name
Milcarb
Company
Description
Baker Hughes Sized CaCO3; Acid Soluble
Type
Granular
Applications
Temporarily seal lost
circulation zones
Mud Systems
Baker Hughes
Mica flakes
Flake
All mud systems
plugging channels and All mud systems
Blend of particles which
Mil-Seal
Baker Hughes
granules, flakes & fibers
Blend
All types of lost
circulation
Acid soluble
fractured
Porous, vugular
or fractured
fractures, vugs,
All mud systems and extremely
porous zones.
with a definite PSD
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Remarks
Wide
lb/sx, 110
particle
lb/sx
size.
As slug (20-30 ppb) or
added to the system
White to grey
N/A
Insoluble
2.6-3.2
N/A
(5-10 ppb)
powder or soft
N/A
translucent flakes
Fine, Medium, &
Coarse
Use as a pill spotted
in loss zone or
Cannot be
maintained in the
removed
N/A
N/A
N/A
Blend of different
materials
graded
Packaging
50 lb/sx, 55
range of
2.8
CaCO3
production zones
void spaces
contains high strength
Recommended
Treatment
Porous and
Prevent mud loss by
MIL-Mica
Formation
Used
Fine, Medium &
Coarse
system.
more effective when
mixed with other
N/A
types of LCM
May water-wet solids
in Invert emulsion
N/A
40 lb/sx
mud.
Mixed LCM designed
for the bridging of
M-I-X II
M-I SWACO
Micronised cellulose fiber
highly porous and
particulates for seepage
fractured formations;
loss control & diff. pressure
sticking preventive for
Blend
Each grind size
has a specially
fracture zones and porous
selected particle size
sands & limestone
distribution optimized
All mud systems
Porous and
Maintain desired
fractured
concentrations
formations
throughout system
Can be removed by
bulk
screen up
N/A
density: 22-
5-7
32 lb/ft3
Tan to light brown
Wide
powder
range
Fine, Medium & solids control equip.
Coarse
Subject to bacterial
degradation
Mix in hopper;
At high
concentrations it
25 lb/sx
will absorb some
water.
to seal a wide range of
formations.
Can be added
N-Seal
Baroid
Spun Mineral Fibers;
Mineral
Partially acid soluble (95%)
Blend
Seepage control,
bridging, plugging
through the hopper.
All mud systems All formations
voids, fractures
Recommend 5-8 ppb
Acid soluble
N/A
2.6
N/A
gray white fiber
N/A
N/A
N/A
N/A
30 lb/sx
in system, 15-30 ppb
pills
Biodegradeable,
High fluid loss squeeze
N-Squeeze
Baroid
(polymers and non acid
soluble LCMs, not requiring
Blend
All types of lost
circulation
Used as a pill to cure
Water base muds All formations lost circ or a sweep to
bulk density
N/A
N/A
clean the hole
an accelerator or retarder).
20 - 25 lb/
non-damaging
Beige to brown
7.5 - 8.5
ft4
mixture, mixed
mixed
N/A
N/A
cellulose fibers
to producing
foramtions, will
not flash set in
the drill string
Cross-linkable Polymer
N-Squeeze with
N-Plex
Plug with sized LCMs (flake,
Baroid
fiber, granular, etc.) with
accelerator or retarder.
These are non-acid soluble.
Blend
All types of lost
circulation
Water base muds All formations
Used as a pill to cure
lost circ
bulk density
N/A
N/A
20 - 25 lb/
ft5
Beige to brown
7.5 - 8.6
mixture, mixed
cellulose fibers
mixed
N/A
N/A
N-Plex is a liquid
alkaline salt
25 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Fine, medium,
Coarser grades can
coarse
be screened out
Fine, medium,
Coarser grades can
coarse
be screened out
Fine, medium,
Coarser grades can
coarse
be screened out
Remarks
Packaging
N/A
50 lb/sx
N/A
50 lb/sx
N/A
50 lb/sx
preventative in the
All types of lost
Nut Plug
SCOMI
Nut Shell Particles
Nut shells
circulation, and high All mud systems
filtration squeezes
All formation
types
active, pills across
loss zones, sweeps
screen up
Granular material
screen up
Granular material
screen up
Granular material
to help clean bit and
hole.
preventative in the
All types of lost
Nut Plug
M-I SWACO
Nut Shell Particles
Nut shells
circulation, and high All mud systems
filtration squeezes
All formation
types
active, pills across
loss zones, sweeps
to help clean bit and
hole.
preventative in the
All types of lost
Nutshells
Gumpro
Nut Shell Particles
Nut shells
circulation, and high All mud systems
filtration squeezes
All formation
types
active, pills across
loss zones, sweeps
to help clean bit and
hole.
OM-Seal
Opta-Carb
Gabriel
Blend of fibrous particles
International,
integrated with their
Inc.
distinctive size distribution
KMC/SCOMI
Sized CaCO3; Acid Soluble
Porous and fractured
Fiber
formations, depleted All mud systems
sands
Granular
Temporarily seal lost
circulation zones
Depleted, porous
As slug (15-100
and fractured
ppb) or added to the
formations
system (2-8 ppb)
Requires
Partly acid
microns
small addition
soluble, & the
upper
of NaOH,
limit and
Non-Toxic &
74microns
environmentally
lower limit
safe
remainder is
> 400oF
< 2.0
7
biodegradable
Wide
Porous and
All mud systems
< 2000
Acid soluble
fractured
50 lb/sx, 55
range of
2.8
CaCO3
production zones
25 & 40 lb/sx
lb/sx, 110
particle
lb/sx
size.
Has extrememly
Wide
International
Perfect Seal
Drilling
Products, Inc.
Chemically inert, inorganic
granular material
Granular
Forms a seal and
prevent lost circulation
All mud systems
Porous and
2 ppb for seepage and
fractured
10-15 ppb for partial
formations
to complete losses
range from
Not removed
1000oF
1.5
#6 mesh to
#120 mesh
screens
high
Check Environmental
regulations
compressive
stength &
40 lb/sx
cannot be
squeezed into
the formation
Perfsal is
spotted ahead
Gelled brine
Perfsal
TBC-Brinadd
Blend of polymer and sized
salt
In gravel packing where
Granular
perforations need to be
temporarily sealed.
Used in Bridgesal
systems
Porous and
fractured
production zones
3 sx / barrel of fresh
water or brine.
of Bridgesal to
wash is
circulated to
clean & open the
perforation
Free flowing powder
fill perfs. The
volume should
be limited to
minimize the
coarse salt.
50 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Prevent or overcome
Plug-git
Baroid
Shredded hardwood fiber
Fiber
lost circulation in
All mud systems
porous formation
Formation
Used
Porous
formations
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
N/A
wood shavings
N/A
3 to 30 ppb to be
added to the whole
Not removed
N/A
1.1
mud
Grades
Limitations
Fine, medium,
Can be screened at
coarse
the shakers
Remarks
Packaging
40 lb/sx
D50 for
: Plugsal
of 75,
Sized and treated salt. It
Plugsal
TBC-Brinadd
has a wide distribution of
Granular
finely divided particles
Temporarily seal lost
Saturated salt
circulation zones
mud
Porous and
fractured
production zones
25-50 ppb tobe added
Water soluble
to a bridgesal system
salt
Plugsal-X
2.18
Free flowing crystals of 450 and Plugsal, X, X-C
plugsal-
Mud must be salt
50 lb/sx
saturated
X-C of
3100
microns
Cross-linkable Polymer
Plug with sized LCMs (flake,
Polymesh
KMC/SCOMI
fiber, granular, etc.) with
Blend
accelerator or retarder.
These are non-acid soluble.
-20 >
Angular material produced
Ruf-Plug
Kelco-Rotary
by grinding, sizing and
blending the hard woody
Fine > 60
Effective in
Blend
All types of lost
circulation
All mud systems
ring portion of corn cobs
fractured and
50% soluble in
Blend of different
unconsolidated
15% HCl
materials
formations.
mesh 14 >
Medium >
40mesh 4
Fine, medium,
coarse
May water-wet solids Resists physical
in Invert emulsion breakdown upon
mud.
50 lb/sx
impact.
> Coarse >
40 mesh
SAFE-CARB
M-I SWACO
Sized CaCO3; Acid Soluble
Granular
Temporarily seal lost
circulation zones
Wide
Porous and
All mud systems
Acid soluble
fractured
2.8
CaCO3
production zones
50 lb/sx, 55
range of
lb/sx, 110
particle
lb/sx
size.
Solids free cross-
SAFE-LINK
M-I SWACO
linkable polymer gel for
Blend
completions
Silvanite
Weyerhaeuser
100% red alder wood
Fine :
fiber, chemically treated
D90 of
to produce an oleophilic,
hydrophobic product for
use in OBM
Fiber
To cure seepage losses
in porous formation
Oil mud systems
Porous
2 to 4 ppb to be added
formations
to the whole mud
Not removed
350oF
0.4 - 0.8
Compressed form
200 mesh Fine and Medium
Medium:
D90 of 150
Small shredder/
Will be screened at
feeder is
the shakers
recommended
for mixing
40 lb/sx
Name
Slicke-n-Side
Company
KMC/SCOMI
Description
Synthetic Graphite; non
acid soluble
Type
Granular
Applications
LCM for bridging and
plugging formations.
Mud Systems
Baker Hughes CaCO3; Acid soluble flakes
Flake
Solu-Squeeze
Baker Hughes
Blend of sized CaCO3
Blend
system or in pill form.
moderate to severe
losses
Removal Temperature Specific
Techniques
Limit
Gravity
at shakers
o
500 F
pH in
water
Product Form
Black powder or
2.19-2.26
granules
fractured
vugular and
All mud systems
fractured
formations
Acid soluble
N/A
2.8
N/A
N/A
2.5 - 2.8
8.4 - 10.2 Solid, white, powder
squeeze across a thief
zone
N/A
granular white
material
Steel Seal
Baroid
composition carbon &
graphite material
and fractured zones.
Limitations
Can be removed by
size 250
shakers. Not acid
microns
soluble.
varied
mixed
Super Fine, fine,
medium, coarse
mixed
Remarks
Insoluble in
water
Packaging
50 lb/sx
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
50 lb/sx
100% < 40
prevention in porous
Angular
Grades
Avg.
(5-10 ppb)
Loss circulation
Resilient, angular, dual-
Particle
Size
Depleted, porous As slug (20-30 ppb) or
losses from seepage to All mud systems sands, vugular or added to the system
total
High Fluid loss squeeze -
Recommended
Treatment
Can be run in active Can be removed
All mud systems
Prevent and reduce
Solu-Flakes
Formation
Used
All mud systems
Also for torque & drag
Porous, depleted
As slug (15-100
and fractured
ppb) or added to the
formations
system (2-8 ppb)
mesh(635)
N/A
N/A
1.75
N/A
Black, angular
56% > 85
Fine, medium,
material
mesh (300)
coarse
95% > 200
reduction in WBM
mesh (127)
Polynuclear Aromatic
Hydrocarbon/
Stop-Loss
Conoco
carboneceous material of
Porous and fractured
Blend
both granular & fibrous
Porous and
formations, depleted All mud systems
sands
fractured
40-100 ppb pills
2.2
Black porous powder
formations
D50 of 250
Check Environmental
microns
regulations
50 lb/sx
shape
NonPorous and fractured
Interlocking mineral wool
StrataWool
Rockwool
fiber that provides a strong
Industries
framework for a durable
combustible,
formations, depleted
Fiber
sands; General lost
Porous and
All mud systems
circularion cases,
mud cake
fractured
non-fermenting,
90% soluble in
1 to 5 ppb to be added 10% HCl in 80
formations
1800oF
2.6
7-8
Powder
min.
non-polluting,
non-toxic,
non-corrosive,
drilling and workovers
odorless
inorganic.
Porous and fractured
Super Sweep
Gumpro and
Sun
Filamentous fibers for
sweeps or seepage loss
control
formations, depleted
Fiber
sands; General lost
circularion cases,
drilling and workovers
Porous and
All mud systems
fractured
formations
0.25 ppb
at Shakers
315oF
1
synthetic
monofilament fiber
13 mm in length 15 lb boxes
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
Grades
Limitations
Remarks
Packaging
Solids free cross-
TekPlug (BJ)
Baker Hughes
linkable polymer gel for
Blend
completions
Acid soluble (95%)
Thermatek
Baroid
Crosslink Polymer Gel with
Porous and fractured
Blend
Retarder and accelerator
Micronized fiber
Truseal
Petrochem
sticking preventative for
Ven-Pak
Chemicals, Inc.
Venture
Chemicals, Inc.
formations
formations, depleted
Fiber
sands; General lost
All mud systems
N/A
N/A
N/A
N/A
N/A
N/A
N/A
hydrochloric acid
Fiber
Prevent seepage losses Oil mud mainly
Blend of organic fibers of
Porous and fractured
Fiber
sizes of particles
formations, depleted
sands
Water mud
systems
Fine, medium,
fractured
coarse
Porous, depleted
formations
6 to 10 ppb for whole
Light tan to brown
mud and up to 150
1.54
3-7
ppb as pills
Porous and
As slug (20-50 ppb) or
fractured
added to the system
formations
(3-20 ppb)
finely divided
powder
95% wet
Supplement
washes
emulsifier in
through
Chemicals, Inc.
Fiber
fibers
brought in contact
Water mud
with water, which will
systems
provide high water loss
0.41
OBM
100 mesh
light tan fluffy,
5/16"
Will be screened
voluminous fibrous
grind
out at shakers.
desintegrated
Diameter :
fractured
As slug (20-50 ppb) or
formations,
added to the system
except the
(5-40 ppb)
5/16 inch,
Not removed
0.74
Dark brown pellets
Length :
less than
before pumped
Not used in OBM or
Venture
Chemicals, Inc.
polymers & fibrous
cellulose bridging agents.
temporary plugging
Water mud
agent in severe cases of
systems
lost circulation
40 lb/sx
fermenting
0.5"
products
included
Highly viscous,
Fiber
to prevent bit
in production zones plugging - Non
large voids spaces
Ven-Plug
25 lb/sx
solid
production zones
bridging properties in
Blend of water soluble
40 lb/sx
Dark brown to
Severely
times its volume when
Blend of both long & short
cellulose base organic
N/A
- Should be fully
to expand up to 5
Ven-Pel
approach to lost
circulation.
Fibrous LCM designed
Venture
systematic
drilling and workovers
derivative
wide variety of types and
(95%) in 15-28%
formations
Micronized, surface
modified, cellulose
mixes below the BHA
This is a
Acid soluble
Porous and
circularion cases,
sands & limestone
Venture
fractured
15-25 ppb treatments,
Porous and fractured
fracture zones and porous
Ven-Fyber 201
formations, depleted All mud systems
sands
particulates for seepage
loss control and differential
Porous and
Ven-Plex
Porous and
fractured
formations
20 - 40 ppb
0.4
5-7
Light brown fibrous
Avoid mixing with
cross-link and
material
Aluminum
strengthen VenPlug pill
25 lb/sx
Name
Company
Description
Type
Applications
Mud Systems
Formation
Used
Recommended
Treatment
Removal Temperature Specific
Techniques
Limit
Gravity
pH in
water
Product Form
Particle
Size
N/A
Granular material
N/A
Grades
Limitations
Fine, medium,
Coarser grades can
coarse
be screened out
Remarks
Packaging
N/A
50 lb/sx
preventative in the
Walnut
Baroid and
Baker Hughes
All types of lost
Nut Shell Particles
Nut shells
circulation, and high All mud systems
filtration squeezes
All formation
types
active, pills across
loss zones, sweeps
to help clean bit and
hole.
Cross-linkable Polymer
Plug with sized LCMs (flake,
X-Link
Baker Hughes
fiber, granular, etc.) with
accelerator or retarder.
These are non-acid soluble.
Blend
screen up
N/A
Appendix 2: Nominal* Particle Sizes of LCM
Product Name
D10 (mm)
D50 (mm)
CELL-U-SEAL Fine
BLOK-R-750
D90 (mm)
Notes
< 900
b
500
700
1000
C-SEAL F
5
30
100
C-SEAL
70
130
190
FED-SEAL
< 900
FORM-A-PLUG II
50
150
a
FORM-A-SET
300
1200
a
FORM-A-SET AK
200
400
a
FORM-A-SET AKX
200
400
a
FORM-A-SQUEEZE
50
500
G-SEAL Fine
10
30
100
G-SEAL
200
400
700
G-SEAL HRG Fine
10
40
90
G-SEAL HRG
300
500
850
G-SEAL PLUS
40
200
800
G-SEAL PLUS Coarse
60
500
900
600
1000
MICA
MIX II Fine
20
90
200
b
MIX II Medium
30
200
450
b
450
1500
b
MIX II Coarse
NUTPLUG Fine
300
600
1000
NUTPLUG Medium
1100
1500
1900
NUTPLUG Coarse
2400
OPTISEAL I
60
500
1000
OPTISEAL II
50
500
1100
OPTISEAL III
50
450
1000
OPTISEAL IV
20
550
1050
SAFE-CARB 2 (Very Fine)
1
2
10
SAFE-CARB 10 (Fine)
1
10
25
SAFE-CARB 20
1
20
100
SAFE-CARB 40 (Medium)
2
40
200
SAFE-CARB 250 (Coarse)
60
250
450
SAFE-CARB 500 (Extra Coarse)
240
500
750
SAFE-CARB 1000 (Extra Coarse)
650
1000
1500
SAFE-CARB 2000
1700
2000
3000
VINSEAL Fine
10
70
300
VINSEAL Medium
40
300
650
400
950
VINSEAL Coarse
a Cross-Linkable Product
b Fiber or Composite with variable Aspect Ratio
c Cross-Linked Swellable Product
* The values of these parameters are not specifications and should not be used for design purposes.
Uncertainty in these values is at least +/- 20% due to variations in manufacturing and grinding processes.
These parameters were measured using laser light-scattering and/or dry sieve analyses of representative
samples of the product. Nevertheless, if the PSD of a product is critical to a drilling operation, it should be
determined on a representative sample from the drilling location.
Appendix 3: OPTIBRIDGE – Design of Particulate Blends to
Stop Lost Circulation
What is OPTIBRIDGE?
The proprietary OPTIBRIDGE* software, which
is used in the design of fluid loss control pills,
delivers formulations for the optimum blends of
particulate bridging agents. Once engineered,
these blends form a tighter and less invading
filter cake to seal pores, fractures, or completion
screens. The software is based on the Ideal
Packing Theory or D1/2-rule, which states ideal
packing, occurs when the percent of cumulative
volume vs. the D1/2 forms a straight-line
relationship, where D is the particle diameter.
The output from OPTIBRIDGE are the optimum
blends or portions of the selected bridging
agents that result in a tighter and less invading
or damaging filter cake to seal the given pore
size or fracture width.
This software tool is particularly useful for drillin fluids and other systems used to drill and seal
producing formations that require optimum
Sealing and minimal reservoir damage. Figure 1
is a screen shot of the OPTIBRIDGE output.
OPTIBRIDGE User Guide and Applications
The primary application of OPTIBRIDGE is
designing a tighter and less damaging seal
over a formation or screen. The first step in
the process of forming an optimum seal is
defining the pore size, fracture width or screen
type from a screen-type dropdown to be
sealed with a tight filter cake with minimum
invasion damage. The maximum or average
pore size in microns can be obtained from
thin section analysis, a scanning electron
microscope (SEM) or the maximum threshold
entry radius that is determined from capillary
pressure measurement. If no pore size data is
available, the permeability option can be used
by inputting the maximum permeability in
millidarcies (mD). The average pore size (in
microns) can be estimated from permeability
by taking the square root of the permeability
(in millidarcies). However, permeability should
only be selected as the last resort.
The second step is to select possible bridging
agents and their particle size distribution
(PSD) data from the bridging products PSD file.
Products that do not appear in your PSD data
file, can be found either in the “Product Service
Offering” link on the M-I SWACO Intranet,
or, can be requested from an M-I SWACO
Technical Service Engineer or the RDF Product
Line Manager in Houston. Another option is to
analyze the bridging agent sample and create
an individual PSD file.
After the optimum blend option is selected, the
output provides the optimum portions of the
recommended bridging agents for the given
pore size, fracture width or screen.
The secondary application of OPTIBRIDGE is
generating the PSD data for a blend of selected
bridging agents or fluids. Again, these blends
are based on the PSD and concentration of each
selected bridging agent or fluid.
A3-1 - Screen capture of the OPTIBRIDGE software
Appendix 4: OPTI-STRESS Design of Particulate Blends for
Wellbore Strengthening
What is OPTI-STRESS
OPTI-STRESS* is a practical software tool for use
in designing effective wellbore strengthening.
The proprietary software comprises two
basic building blocks: a reasonably accurate
prediction of fracture width; the appropriate
blending of granular wellbore strengthening
materials (WSM) to plug the predicted fracture
width. The primary challenges in predicting
fracture width surround the uncertainties of
rock properties and down-hole conditions, along
with difficulties in modeling. Once the fracture
width is predicted, the wide variety of both
standard and locally-sourced WSM requires the
blending algorithms and design software is
flexible and adaptive.
The software is built on a spreadsheet
framework that promotes usability and
simplicity. The closed-form solution for
predicting fracture aperture allows Monte Carlo
simulations to be implemented, permitting
more than 10,000 simulations in less than a
minute. Users can customize choices for WSM
loss by uploading PSD and other properties into
the program database.
OPTI-STRESS User Guide
Figure A-4-1 is a snapshot of the software,
illustrating the two basic building blocks.
Fracture Width Prediction
This discussion addresses fracture aperture for a
wellbore of any deviation and orientation under
anisotropic stress conditions. The closed-form
solution for the fracture aperture is based on
linear fracture mechanics. The model depends
on well deviation and orientation, fracture
length, wellbore radius, in-situ stresses (SV, SH
and Sh), bottom hole pressure and rock elastic
properties (Young’s modulus and Poisson’s ratio).
However, the inputs required for fracture
aperture prediction can include considerable
uncertainties, especially when the inputs are
based on information from offset wells. Among
the many sources of uncertainties are data
obtained from logging and well testing analyses
of offsets. For example, it may be impossible
to determine exactly the maximum horizontal
stress in the well. It could range, for example.,
from 5,400 to 5,600 psi, but an exact value
within this range is unknown. The uncertainty
in the input variables is shown in the top left
corner (section I-1) of Fig. A-4-1.
One method of addressing these uncertainties
is to employ a Monte Carlo simulation, which
is a computational method that repeatedly and
randomly samples possible input values and
computes results based on these samplings. The
output provides a broader spectrum of possible
outcomes and can rank the inputs that most
affect the output, also known as a sensitivity
analysis. Each input with uncertainty is
quantified by transforming it into a statistical
distribution that relates to the possible range
and distribution of values. The larger the
samplings, the more accurate the prediction.
Generally, a typical simulation consists of
several thousand iterations. Each input value
can be modeled by a “most likely,” which reflects
a minimum and a maximum value with an
appropriate distribution. These can be based on
the results of logging analysis, laboratory or well
testing, or other databases. The Monte Carlo
simulation samples each of these distributions,
performs fracture-width calculations, and
generates a fracture width distribution.
The primary output from the simulation is the
probability or risk of results, such as the P10,
P50 and P90 values of fracture aperture (plot I-2
in Fig. A-4-1), thus indicating the probability of
having apertures less than the corresponding
values. The sensitivity analysis fills a
complementary role by ranking the importance
and relevance of the inputs in determining the
variation in the output. The sensitivity graph in
Fig. A-4-1 (Section I-3) highlights the importance
of minimizing the uncertainty in the minimum
horizontal stress inherent from leak-off or other
tests. In this example, uncertainty in the rock
properties of Young’s modulus and Poisson’s
ratio is shown to have little impact on final
results.
the optimum P90 blend. A seal formed at the
entrance of the aperture, along with fracture
filling and Sealing with the finer fractions,
provide the ideal fracture sealing. Section II of
the figure also shows the bridging quality of the
final blend and product coverage.
Formulation of WSM
Conventional WSM blends based on the Ideal
Packing Theory (IPT) often ignore the presence
of barite in the drilling fluid. Barite particles
can fill the voids between larger WSM and form
an effective seal behind the plug and close to
the wellbore wall. Experimental data suggest
the PSD of the finer fractions of the WSM affect
fluid-loss characteristics and seal pressure
integrity (Kaageson-Loe et al. 2008). This data
highlights the importance of optimizing the
WSM blend design by utilizing the barite
already present in the mud. Barite loading in
weighted mud is much higher than the WSM
concentration used in wellbore-strengthening
applications. More information can be found in
the OPTIBRIDGE discussion (Appendix 3).
Typical wellbore-strengthening applications
use some combination of (a) sized synthetic
graphite, (b) crushed, sized marble (CaCO3)
and (c) crushed nutshells (Growcock et al.
2009). The choice of WSM blend for a given
fracture width strongly depends on the PSD
of the WSM. Providing the PSD for the given
WSM are available, the software tool is flexible
enough to use locally-sourced products. Figure
A-4-1 (Section II) shows the available WSM
used for this example simulation, along with
the inputs required to specify the presence and
type of barite in the drilling fluid. The user can
select from a collection of PSD files that can be
customized to suit individual needs and WSM
availability.
Monte Carlo simulation generates P10, P50,
and P90 fracture widths that indicate the
probabilities of fracture widths less than those
calculated values. The blending algorithm (Fig.
A-4-1- Section II) generates the optimum WSM
blend required to plug and seal a fracture width
for each probabilistic value. The choice of WSM
for P10 and P50 fracture widths are a sub-set of
The three plots marked as Section III in the
figure illustrate the cumulative PSD of a WSM
blend that provides an effective sealing pressure
for a sample fracture width distribution P10,
P50, and P90 values of 361, 583, and 731
microns, respectively. By switching PSD files and
WSM choices, the tool can be used to objectively
compare concentration requirements for various
types of WSM, such as Calcium Carbonate, sized
synthetic graphite, or crushed nutshells.
Finally, an inversion technique is used to
generate the gain in net fracture pressure as a
result of a successful wellbore-strengthening
application. Assuming a fracture can be
bridged and sealed as perfectly as possible, the
tool generates the net fracture pressure for the
P10, P50, and P90 fracture widths as shown in
Fig. A-4-1 Section III.
OPTI-STRESS Benefits
This practical software is a fast and user-friendly
tool for wellbore strengthening applications.
The incorporated Monte Carlo simulation also
permits the user to estimate the probability of
a certain-sized fracture given the uncertainties
of the various parameters that affect fracture
growth. It helps to comparatively evaluate the
effect of each input parameter on the final
result.
The tool generates results that allow for either
a conservative P10 or more aggressive P90
value. In addition, it considers the variety of
local WSM sources and is flexible, adaptive
and incorporates barite and drilling solids into
the blending algorithm. Doing so provides an
accurate estimation for both weighted and
non-weighted fluids. Moreover, the successful
application of this wellbore strengthening
technique also generates a probabilistic
estimation of the net fracture pressure gain.
Fig A-4-1. Screen capture of the wellbore strengthening design software. (Colored rectangles
are superimposed for demonstration purposes only and distinguish software sections based on
discussions in text: orange for Section I, blue for Section II, and green for Section III).
Appendix 5: FASware – Design of FORM-A Pills
Introduction
1. The proprietary Excel-based FASware* software is integrated in the ECCP software suite under
System Toolbox module.
2. The software representes the package of programs covering the formulation, mixing, spotting
and squeezing procedures for different cross linking pills i.e. FORM-A-SET, FORM-A-SET AK, FORM-ASET AKX, and FORM-A-PLUG II.
Running the Program
1. From the main page (file FASware.xls) run the Decision Worksheet or directly choose the desired
“FORM-A” product to run.
2. If the Decision Electronic Form is run, answer each question by clicking Yes or No.
Decision Worksheet
“FORM-A” products
mixing tables
PDF files for
Product Bulletins
and MSDS
This Decision Worksheet
Form shows the score of “YES”
and “NO” answer for each
question.
For Decision Worksheet Form,
the score for each question
has to be added manually in
the TOTAL column.
3. From either the Main Page or the Decision Electronic Form (if it was run) click on the
appropriate field for the chosen “FORM-A” product.
4. The program will hyper-link to the Mixing Chart (Excel file).
Note: FORM-A-SET, FORM-A-SET AK and FORM-A-SET AKX have the same mixing table format. However,
FORM-A-PLUG II has a different mixing table format and requires an additional set up.
Example: If the FORM-A-SET AK is the recommended product for that particular application, click
on the either FORM-A-SET AK (only for 47 lb/sx) or FORM-A-SET AK (only for 25 lb/sx) Check first with
the warehouse or the inventory to see whether 47 lb/sx or 25 lb/sx is available. After clicking the
“Mixing Formulation,” the following page will be displayed.
The program comes with the
standard products packing.
Do not change this numbers
unless necessary. The most
likely number to be changed
is Weight Material (the pre-set
value is 100 lb/sx).
The green-colored fields are
displaying calculated data,
either the products (as sacks
or pails) for mixing the desired
volume or the products (as
grams or ml) for mixing one
bbl equivalent (pilot test).
Pilot test formulation
Components of FORM-A-Product
Summary of “FORM-A” product components
Product
FORM-A-SET
FORM-A-SET-AK
FORM-A-SET-AKX
Polymer
22.5%
74.5%
94.6%
Mix-II
77.5%
25.5%
-
CaCO3
5.4%
Check the TOOLS pull-down menu to
see if SOLVER function is displayed
and active. If not, on the same menu
(TOOLS) click on the ADD-INS and
scroll through the menu to the
SOLVER function. Click install! The
computer will prompt for inserting
the Microsoft Office installation CD.
Step 1: Click on Office
Button
Step 2: Click on Excel
options
5. In order to run the FORM-A-PLUG II Mixing Formulation, make sure the Excel version running on
your computer has the SOLVER function installed and active.
Step 3: Click on Add-ins
Step 4: Click on Manage
Excel Add-ins and then
click Go.
For Excel 2003
For Excel 2007
Step 5: Check on
Solver Add-ins and
then click OK.
The Solver AddIns will be on
Data-Analysis
Tab.
When the SOLVER function has been installed, from the Main Page (FAS-ware.xls) click on FORM-APLUG II Mixing Formulation (orange-colored field). The page below will be displayed.
Choose the appropriate density
range for the FORM-A-PLUG II pill by
clicking on the grey-colored field
that displays the density range
(ppg).
After selecting the appropriate density range, the page below will be displayed.
Input the required data in the
orange-colored fields:
• FORM-A-PLUG II slurry weight
• Weight Material SG
• BHT
Input the desired volume to be
mixed in the orange-colored field.
The next step will be to run the SOLVER function.
For Excel 2003, pull-down the TOOLS menu, click on
SOLVER, click on SOLVE and OK the solver solution.
No data input in required during this sequence
The Solver is required to calculate the concentration
of Fresh Water and other chemicals to get the
following concentration of FORM-A-PLUG ACC
Density
For 10.21-12.25 ppg
For 12.5 – 14.5 ppg
For 14.5 - 15.5 ppg
For 15.5 – 16.5 ppg
For 16.5 – 18.0 ppg
FORM-A-PLUG ACC
50 lb/bbl
45 lb/bbl
40 lb/bbl
30 lb/bbl
25 lb/bbl
The green-colored fields represent
calculated values for mixing either 1
bbl, the desired volume as defined on
the step 5, or 1 bbl equivalent (350 ml
– Pilot Test Formulation).
The FAP RET concentration is
“recommended” only and it is not
considered among the products
shown on the Mixing Formulation.
If it is decided to use the retarder
(see the Product Bulletin and
Mixing & Squeezing Procedures) the
recommended concentration from the
green field has to be considered for
the final mixing formulation.
The same rule applies for the Pilot Test
Formulation.
STEP 4 for Excel 2007
Step 1: Click
on Solver
Step 2: Click
Solve
Step 2: Click ononSolve
Step 3: Click OK
Step 3: Click OK
Troubleshooting Guide for Solver add-ins
Sometime the Solver
Add-ins disappear.
Step 1: Click on Excel
option
Step 2: Click on Excel
Add-ins and Go
Step 3: Un-Check
Solver Add-Ins and
click OK
Step 4: Repeat Step 1
and 2 then Check Solver
Add-Ins and click OK
Solver Add-Ins will
appear
6. Volume calculation and pumping schedule.
This work sheet can be used to calculate volume and pumping schedule for all type of pills and is
not limited to only the “FORM-A” product.
7. After running the Mixing Chart and Volume Calculation and Pumping Schedule, click on
Spotting & Squeezing Procedures (at the bottom of the Mixing Formulation sequence of the
chart). The program will hyper-link a template word document for each individual “FORM-A”
product.
8. Fill in the blanks the Spotting & Squeezing Procedures with the information provided by the
Mixing Chart. The document should be tailored in order to match each specific application (rig
mixing equipment details and pits lay-out, operator company logo, etc.)
Fill in the blanks with the
appropriate information
(as used in the input
sequence of the Mixing
Formulation or provided by
the program – calculated
values).
The document provides
all the necessary data as
mixing order, surfactant
sweeps for either WBM
or OBM, high-viscosity
spacers formulation
and pumping/spotting/
squeezing procedures.
9. Input the required data in the Price List before running the Total Cost Evaluation.
Input the unit cost
(USD) in the orangecolored fields. The
program comes
with the standard
packaging for the
FORM-A and all the
related products.
Click on the Total Cost Evaluation tab and the screen below will be displayed.
Use the values generated
by Mixing Formulation
chart to input the number
of units required for
mixing the FORM-A pill and
all the additional sweeps/
spacers (in the orangecolored fields).
Use the pull-down menu for
selecting the appropriate products
for each pill (i.e., FORM-A pill,
surfactant sweep, high-viscosity
spacer)
The green-colored field will display
the Total Cost (USD) for the FORM-A
pill and associated sweeps/spacers.
Saving the files
1. At the end of each work session, save the file (Excel or Word) with the “save as” function and
choose a file name different than the original template file name; these individual files can be
saved in the computer hard drive.
2. It is recommended to create a folder in the computer hard drive where to save all the work
sessions related to different runs/wells.
Appendix 6: LCM Guidelines for Downhole Tools
Introduction
High-concentration LCM drilling fluid systems
are considered harsh drilling environments for
MWD and steerable tools. Accordingly, nearly all
of the MWD suppliers provide a maximum LCM
concentration in their specification bulletins
for each tool. Most MWD manufacturers have
designed a test method for specifying the
maximum amount of LCM allowed to pass
through a tool.
For these tests, NUTPLUG is the commonly
accepted standard for measuring the capacity
of an LCM to pass through a particular MWD
tool. NUTPLUG is ground walnut or pecan hulls
used for treatment of lost circulation or as a
granular type lubricant to reduce torque and
drag. NUTPLUG is available in Fine (D90 = 880 μm),
medium (D90 = 1800 μm) and Coarse (D90 = 3700
μm) particle sizes. Typical treatments are from 5
to 15 kg/m3 for preventative measures and from
15 to 75 kg/m3 for more severe losses.
The testing system consists of a test tool of
a pre-determined size incorporated in a flow
loop where a triplex pump provides different
flow rates. The standard tests are performed
on 10.0 lb/gal NaCl brine mixed with different
concentrations of either NUTPLUG Fine or NUTPLUG
Medium. The exact concentrations are based on
the size of the tool being tested.
The MWD tested can be either a collar or probebased tool. Collar- based tools have proven less
susceptible to blockage or turbine jams, as they
have been modified with filter screens over
the turbine power section of the transmitter
immediately above mud SEAL. Also, the rotor
blades have been cut back to allow for more
clearance between the rotor and the inside
of the turbine housing. With Schlumberger’s
PowerSteering and similar steerable tools, the
internal components are isolated from the
drilling fluid and, as such, the use of LCM is not a
limiting factor in their performance.
At the time of this writing, a brief search of
MWD and steerable tool bulletins revealed
all major MWD service companies report
the maximum LCM concentration for their
respective tools as 100 kg/m3 NUTPLUG Fine
to 180 kg/m3 NUTPLUG Medium. Table A-6-1
presents examples of the LCM limitations of
MWD and steerable tools.
Table A-6-1 - Example of MWD and steerable tool specification
Manufacturer
Schlumberger
Schlumberger
Baker Hughes
Weatherford
System
SlimPulse
PowerDrive X5 475
AutoTrak
TrendSET
While NUTPLUG is being used as a quick
reference, this appendix is intended to provide
general guidelines on using LCM through the
MWD and steerable downhole tools. The proper
selection of the LCM allowable for passing
through the MWD and steerable downhole tools
should be based on:
• Particle Size
• Type
• Concentration
LCM Limitation
150 kg/m3 NUTPLUG Medium
100 kg/m3 NUTPLUG Fine
120 kg/m3 NUTPLUG Fine
180 kg/m3 NUTPLUG Medium
LCM Particle Size
Traditionally, LCM treatments are formulated
based on particle size. On the basis of the
particle sizes making up a pill, the LCM is
graded as Fine, medium, Coarse and extraCoarse. However, this scale is very misleading.
For example, a Fine Calcium CARBonate has the
consistency of talcum powder, while a Fine
pecan shell LCM has texture similar to ground
coffee. To complicate matters further, a Fine-
blended LCM will incorporate paper, CELLophane
and wood splinters as large as the Coarsegraded pecan shell LCM. In order to address the
variances in definitions of sizes used by the
industry, the standard detailed in Table A-6-2
has been adopted.
Table A-6-2 - Size classification of LCM
LCM
Grade
Fine
Size (μm)
Mesh Size
D90 < 75
Medium
D90 = 75 -250
Coarse
D90 = 250 -1000
Extra
Coarse
D90 > 1000
At least 90%
passes through
200-mesh screen
At least 90% is
retained by 200
mesh screen and
passes through
60- mesh screen
At least 90% is
retained by 60mesh screen and
passes through
18- mesh screen
At least 90% is
retained by 18mesh screen
**Note that particle sizes are best measured
using sieve analysis, especially for the larger
particles, and wet sieve analysis probably
simulates downhole conditions better than
dry sieve analysis. This will better reflect their
plugging ability and to some extent allow for
different particle shapes (aspect ratio). Laserlight scattering particle sizes tend to give an
average spherical diameter even for needleshaped particles, which may inaccurately reflect
their Sealing ability.
The D90 is a measure of the large particles
present and is defined as follows:
D90 value = 90% of the particles are less than this
size
For example, in Table A-6-2 a material with a D90
of 300 microns would be classified as “Coarse.”
The D90 would approximate the minimum
opening through a downhole tool that can
be plugged. It suggests there is a reasonable
concentration (10% of the particles) large
enough to plug that opening, thus increasing
the chance for tool failure.
Abrams’ Rule “the median particle size, or D50,
of the bridging material should be equal to or
slightly greater than 1/3 the median pore size
of the formation.” To avoid plugging of pores or
openings in downhole tools, the corollary to this
rule is that the median particle size should be
smaller than 1/3 of any opening size within the
tool. An alternative theory and one espoused by
M-I SWACO and incorporated into OPTIBRIDGE, is
the Ideal Packing Theory. It concludes that the
D90 of bridging materials should approximate
the largest pores or openings in a formation.
By way of illustration, it may be appropriate to
work through an example using both of these
theories. For this exercise, the information
provided by the MWD company is that the
smallest passage (opening) inside the BHA is
10/32-in, or 7.94 mm. Applying Abrams’ Rule,
this value is divided by three, yielding 2.65 mm.
To ensure that LCM blends designed for this
application do not plug the tool, the LCM blend
must have D50 < 2.65 mm. In the Ideal Packing
Theory, the LCM blend must have D90 < 7.94 mm.
The two theories effectively predict the same
result, providing D90 ~ 3 x D50, which is often
the case, as show in Fig. A-6-1. Regardless of
the theory chosen, it is imperative that all LCM
be inspected before they are added to the mud
system.
Plugging is as much a function of concentration
as it is of particle shape and size. The theory of
Abrams goes on to state that the concentration
of bridging particle size solids must be at least
5 vol% to produce an effective SEAL. On the
other hand, Ideal Packing Theory suggests
3 vol% is sufficient. Although the effects of
particulates on standard mud properties depend
on the nature and size of the particulates, most
bridging particulates begin to significantly
impact viscosity and fluid loss when the
concentration exceeds 3 to 5 vol%. In addition,
the size requirement for bridging begins to
decrease at concentrations above this range.
Thus, in the field, full mud treatment generally
is restricted below this concentration range.
Since pills and sweep treatments can exceed
this concentration several fold, it is imperative
such treatments be investigated thoroughly and,
if necessary, tested to minimize the potential of
plugging downhole tools.
Fig. A-6-1 – OPTIBRIDGE Output, showing D90 ~ 3 x D50 of Recommended LCM Blend
LCM Type
Generally, LCM can be classified as Fibrous or
CELLulosic, Granular, Flaked or Platelet, Blended,
High Fluid-Loss SQUEEZEs, and Reinforcing Plugs.
Table 3 summarizes the range of M-I SWACO
LCM products that can be used with MWD
probes.
Fibrous and CELLulosic LCM
• M-I-X II, M-I CEDAR FIBER, Saw Dust, Drilling
paper, VINSEAL, and MAGMA Fiber
MWD companies recommend that most longfiber or string-like materials be avoided. These
materials will plug the inlet ports of the main
valve assembly and the restrictor area on the
outside of the main valve, interrupting real-time
mud pulse telemetry.
Granular LCM
• NUT PLUG, G-SEAL, G-SEAL PLUS, C-SEAL, C-SEAL F,
SAFE-CARB and sized salt.
MWD companies’ recommendations for
granular LCM are:
• High concentrations of granular LCM
materials should preferably be finer than
D90= 250 µm (typical bridging- or seepageloss-control LCM).
• Concentrations should start at 9 kg/m3 with
good mixing, increasing the concentration of
the LCM as needed.
• Calcium CARBonate tends to form a hard
filter cake on the main valve inlet screen
effectively blocking flow through the main
valve. This problem can be remedied by
removing the inlet screen on the main valve.
• For the probe tools, the MWD mud pulse
signal should be monitored carefully during
this process. If the tool starts to skip pulses
or pulses increase in size, concentrations of
LCM should not be increased without further
discussions with the operator and MWD-tool
supplier. As a rule of thumb, if the tool starts
to skip pulses, the main valve is plugging. If
the pulses increase in size, the restrictor area
is plugging, causing a greater than normal
pressure drop across the pulser.
Flaked LCM
• Avoid any slugging of the LCM.
• For 4 ¾-in. tools where restrictor to probe
barrel clearances become very small in
deeper holes, the amount and size of LCM
that will pass by the tool will decrease.
• Always run the inlet screen on the main
MWD-tool valve.
• Always visually inspect the LCM. If it doesn’t
look like it will pass by the tool, it probably
will not do so.
A general recommendation that comes from operators
and service companies is that for granular materials
the total concentration of LCM in the whole mud
should be limited to 50 lb/bbl, and maximum particle
size should be on the order of what is obtained for
100% VINSEAL Med (D90 ~ 750 µm), NUTPLUG Fine (D90 ~
950 µm), or NUTPLUG Med (D90 ~ 1900 µm), depending
on the client. Note that these size parameters are
not specifications and were obtained for individual
samples (see Chap 4). Thus, maximum D90 for the LCM
blend should not exceed 750 to 1900 µm.
• Mica, PHENOSEAL and CELLophane.
It is NOT recommended practice to use flaked
material as LCM.
Blended LCM
• OPTISEAL I - IV product range, KWIKSEAL, and
M-I SEAL.
Blends containing particles sized greater
than 1500 µm (D90 or D95) should be avoided
when using MWD tools and the concentration
should be limited to 50 lb/bbl, similar to the
recommendation for granular materials.
Reinforcing plugs
These are classified as either soft or hard plugs:
• Soft plugs have a solid mass, but tend to have
little, if any, compressive strength and form a
rubbery consistency; Examples are: FORM-A-
Table A-6-3 - Summary of M-I SWACO products that can be used with MWD tools
Product Name
Product Description
OPTISEAL I
Graphitic material & ground nut shells
LCM D90
< 1500 μm
Yes
OPTISEAL II
Graphitic material & calcium carbonate
Yes
OPTISEAL III
CaCO3, graphitic & cellulosic material
Yes
OPTISEAL IV
Calcium carbonate
Yes
NUT PLUG
Ground Pecan or Walnut shells
Yes
SAFE-CARB (CaCO3)
Sized calcium carbonate
Yes
G-SEAL, G-SEAL PLUS,
C-SEAL, C-SEAL F
Blends of graphite, industrial carbons
Yes
M-I SEAL
Blended LCM
VINSEAL, M-I-X II,
M-I CEDAR FIBER
Cellulosic fibers
Yes
Yes
FORM-A-SQUEEZE
High solids, high fluid loss squeeze
FORM-A-SET
FORM-A-SET AK
Cross-linked polymer plug
FORM-A-PLUG II
Borate salt cross-linked polymer plug
VERSAPAC
Oil-based shear activated plug
Uncrosslinked,
Yes
Note: Always visually inspect the LCM and check it with MWD operators; if in doubt, discuss it with the
M-I SWACO project engineer and MWD-tool supplier.
SET, FORM-A-PLUG II, VERSAPAC, and Gunk.
• Hard plugs have a much higher compressive
strength. Examples are barite plugs, cement.
• Since their mechanism of plugging is
different than that for conventional LCM
materials that rely on both bridging and
plugging, most of these plugs do not contain
large particles.
However; for a Diesel Oil-Bentonite and/or
Cement Gunk SQUEEZE, it is advisable to plan to
POH and install large nozzles and lay down the
MWD/mud motor prior to tagging the loss zone.
This will enable pumping of the Gunk. Also, it is
important to note that a Reverse Gunk Pill is not
compatible with MWD tools.
LCM Concentration
The amount of the LCM added to a mud system
is a function of the material type. Calculating
the amount of LCM by volume rather than
by weight is more efficient for preventing
MWD plugging, as the lower the density of the
material the more time required to SETtle as the
slurry is pumped through the tool. Typically,
all MWD tools successfully can handle 5 vol%
of LCM (i.e. up to 150 kg/m3 each of SAFE-CARB
or G-SEAL) in the whole mud. Actually, most
MWD tools can handle as much as 10 vol %
intermittently. Hence, the recommended
maximum combined concentration for a single
pill is 10 to 12 vol% granular LCM..
Operational Guidelines
Pre-planning can reduce any MWD tool
problems significantly at the wellsite. It is
important to determine ahead of time the
compatibility between the MWD tool and
LCM or mud additives to be used. .As such, it is
recommended that the Drilling Fluids Project
Engineer review planned services with MWD
personnel before tools or chemicals are delivered
to the wellsite.
The following procedures should be reviewed
and followed prior to and during all MWD jobs:
• Visually inspect the LCM to determine its
compatibility i.e. size and length of particles,
stringiness, and determine the likelihood of
the “balling-up” when mixing.
• Ensure the LCM is being added to the hopper
properly. At least one hour circulation
through the hopper may be required to
provide homogeneous slurry.
• The use of oil-wetting agents will aid mixing
of LCM when used with OBM/ SBM and
should minimize the chances of the LCM
“balling-up”.
• Always run uphole filter screens. These
screens will prevent any large particles from
being pumped downhole and will plug off
if LCM is not being mixed properly into the
system.
Fig. A-6-4: Reporting form for effect of LCM on MWD/steerable tools
• Visually inspect the drillpipe for pipe scale or
cement. Make provision to clean the pipe if
any scale or cement is present.
• If pipe scale is prevalent and loose, run
downhole screens to immobilize it.
Other Downhole Hardware
While the Guidelines presented in this Appendix
provide general prescriptions for avoiding
plugging of downhole MWD and other BHA
tools, there may be additional limitations
imposed by other hardware. Turbo-Drill motors,
in particular, have very tight clearances and
low tolerances to solids. These mud-driven
turbines, which are designed to rotate the
bit independent of the rest of the drill string,
can have somewhat different sensitivities
to particulates than we might see in other
downhole tools. Indeed, the guidelines for
particle sizing when using Turbo-Drill motors
really apply only to pills; it is not recommended
to pass any particulate material continuously
through the motors.
Regarding the sizing guidelines for Turbo-Drill
motors, most granular but fragile materials are
acceptable, even grades that are Coarser than
those approved for MWD tools, though the
upper concentration limit might be 120 kg/m3
for the Fine and medium grades and only 60 kg/
m3 for the Coarse grades. Fibers are a mixed bag.
It appears that Fine fibers are ok, but Coarse
fibers are not allowed. So M-I-X II is acceptable,
but M-I CEDAR FIBER is not. Finally, products like
NUTPLUG, though granular, are not recommended
at all, though VINSEAL is ok. If a drilling operation
is expected to use a TURBODRILL, it is prudent
to consult Smith Technologies or the Neyrfor
engineer for specific recommendations.
WELL COMMANDER
When drilling into a loss circulation zone with
LCM that is considered incompatible with
downhole tools, the WELL COMMANDER should
be included in the BHA. This by-pass tool can
perform many functions, including spotting LCM
pills, boosting annular flow velocities, pulling
dry pipe, and flow-splitting during drilling.
When spotting Coarse LCM, a lower ball seat is
installed in the tool, which enables shutting off
the flow to the bit by dropping a special “shutoff” ball to this seat after opening the tool. This
process can prevent Coarse LCM from entering
sensitive BHA elements, such as MWD and LWD.
Appendix 7: Lost Circulation Rigsite Tests
Several rigsite procedures are described here for
the testing of lost circulation materials (LCMs).
These include
• Granulometry, or Particle Size Distribution
(PSD) measurements
• Performance - Sealing or Plugging
Effectiveness
• Thickening Rate of Crosslinkable LCM, e.g.
FORM-A-SET AK
To determine how efficiently a particulate-based
wellbore stabilization is being implemented, it
is important to monitor both the particle size
distribution (PSD) of particles in the mud and
the ability of the LCM to SEAL simulated pores or
fractures. To verify how rapidly a crosslinkable
LCM sets, it is important to measure how rapidly
it thickens at bottomhole temperature.
Laboratory procedures are available that
can provide more accurate and precise
measurements of these measurements, but
generally they require more sophisticated
equipment, training and time:
Granulometry - laser light-scattering or
reflectance, dry air jet sieve analysis and
microscopic image analysis
Performance – Simulated Fracture Sealing
Apparatus
Thickening Rate – Consistometry
Additional laboratory tests are available,
including particle hardness using oedometry
and particle shape analysis using microscopic
image analysis.
Granulometry
A primary objective of PSD measurements is
to identify the D10, D50 and D90 of the particles
or particulate fraction in a drilling fluid. These
parameters are obtained from a cumulative
PSD curve. The subscript represents the % of
particles that are less than this diameter, e.g.
90% of the particles are less than D90. The three
parameters characterize the PSD fairly well by
providing the median particle size (D50) along
with the breadth of the PSD (D10/D90).
PSD can be measured many different ways. The
two most common techniques in the drilling
fluid industry are light -based measurement
techniques and sieve analysis. Laboratory PSD
measurements are generally made using a laser
light scattering device of the diluted drilling
fluid or of the product diluted in a carrier fluid
(oil or water), whereas suppliers of the LCM
typically use dry sieve analysis of the individual
products to size them for delivery. In the field,
it is necessary to measure the PSD of the mud
itself, and it is not very practical to use laser
light scattering.
Each particle size analytical method has
advantages and disadvantages:
Light-Based Analysis
• Requires only a small sample (a few grams)
to perform an analysis and analysis is
performed quickly (usually about 2 to 5
minutes);
• Method generally uses a laboratory-based
instrument, common types: Malvern
Mastersizer 2000, Beckman Coulter LS-series
and Beckman Coulter Multisizer Coulter
Counter - not all mud laboratories are
equipped with these instruments;
• Due to the small sample size and rapidity
of test many repeat measurements can be
taken on sub-samples from a larger sample;
• Particles in the range < 1µm to 2000µm can
be measured by most machines and there
is generally a very high resolution in the
results;
• Results are generally given as volume % of
material analyzed;
• Instruments come with software that
analyses and presents the data in an easy-toread hard copy or as digital files;
• Method can be performed on dry samples of
LCM (LCM is suspended in air or clear fluid
for analysis) or on whole mud samples (LCM
and mud including weighting material)
• Extreme care is required when sampling
weighted fluids containing LCM – the very
high number of barite particles can easily
mask the LCM particles such that the LCM is
underrepresented in the analysis;
• This masking problem can give the false
impression that the method is inaccurate;
• Problem can be avoided by wet sieving
whole mud over a 100-µm sieve and testing
the retained material – majority of barite
and Fine LGS will be removed;
• Care is required to ensure that particles are
properly separated – may require use of
dispersing agents.
In-line laser light-based instruments are
available that can measure the particle size
distribution, in real-time, of whole mud passing
in a flow line. M-I SWACO uses the MettlerToledo FBRM (Focused Beam Reflectance
Measurement) instrument for this purpose with
good success.
Sieve Analysis
• Requires minimum of 4 sieves that span the
size range of the material to be analyzed;
• Particles in the range 75 µm - >> 2 mm can
be easily measured, depending on selected
sieve size;
• Relatively large, representative samples can
be analyzed;
• Method is simple and robust but can be time
consuming;
• Requires weighing of material retained on
individual sieves, which is then entered in to
a spreadsheet for analysis;
• The results are generally given as weight %
of material retained or passing sieve sizes;
• Method allows analysis of dry samples of
LCM – whole LCM blend can be measured as
a base-line;
• Method allows analysis of whole mud
sample (wet sieving): LCM and mud
including weighting material;
• Method allows clear separation of barite,
Fine LGS and LCM
• Wet sieving is more demanding than dry
sieving owing to the liquid nature of the
sample;
• Wet sieving requires flushing of sample with
base fluid;
• Care is required to ensure particles retained
on sieves are individual particles and not
conglomerates held together for example by
polymers.
The M-I SWACO procedure is based on the sieve
analysis procedure described in ASTM D6913-04
for PSD of soils.
Given the above, the method of choice for
PSD determination at the rigsite is Wet Sieve
Analysis.
Wet Sieve Analysis
In a typical Wet Sieve Analysis, a volatile organic
solvent is used to wash the particulates on each
screen, the particles retained on each sieve are
washed onto a watch glass with the solvent,
and the amount of solid is weighed after
evaporation of the solvent.
An example of a 4-sieve apparatus is shown in
Fig. A-7-1.
Fig. A-7-1. Photograph of Wet Sieve Analysis
apparatus used on BP Tubular Bells #3
The sieve sizes used should span the PSD of the
LCM in order to give good resolution; e.g. for
G-SEAL PLUS or G-SEAL the following sieves sizes
can be used: 75, 250, 500 and 710μm (200, 60,
35 and 25 mesh, respectively). The sieve size
range specified by ASTM D6913-04 is as follows:
75, 106, 150, 250, 425 and 850 μm (200, 140, 100,
60, 40 and 20 mesh, respectively).
It is assumed that primary shakers remove all
large solids > 1000μm in size, and that solids
which drop through the 75-μm sieve are barite
and other Fines, which are not counted.
The following procedure is very simple and
flexible:
• Identify the maximum particle size (D90) of
LCM that needs to be in the mud, e.g. 600µm.
• Select a set of at least 4 sieves with a wide
range of openings – including a 75µm sieve
as the smallest – and stack them from
Coarsest on top to Finest on the bottom, and
arrange the stack to discharge the effluent
from the 75µm sieve. If sieves are not
available to generate a full PSD, monitor the
trend in the concentration of the material
that possesses the largest average particle
size.
• Pour a known volume of mud from the
active system or underflow from the shakers,
i.e. without cuttings, over the top sieve; care
should be taken not to overload the top sieve
– a layer of no more than 2 mm.
• Observe the particles retained on the sieve
(usually graphite and marble)
• Wash with solvent, e.g. toluene/acetone
mixture.
• Allow to air-dry, and weigh the amount of
LCM retained on each sieve. If flammable
solvents are not permissible, follow
the procedure below to estimate the
concentrations of solids recovered on each
sieve.
Wet Sieve Analysis Without Solvents
On many rigs, volatile organic solvents are
discouraged because of safety concerns. If the
drilling fluid is a WBM, the standard Wet Sieve
Analysis procedure described above can still be
used but with water as the washing agent. This,
of course, requires a longer evaporation time for
the wet fractions captured by each sieve, but
elevated temperature can be used to drive the
water off in a reasonable amount of time.
If the drilling fluid is a NAF, however, using the
standard Wet Sieve Analysis procedure with
base fluid as the washing agent is unacceptable,
because of the fluid’s extremely low rate of
evaporation. Consequently, a method has been
devised for NAFs that can be used with base
fluid as the washing agent for the cuttings and
which does not require evaporation. With this
technique, the wet, clean solids are washed into
volumetric tubes using the base oil or synthetic
fluid, the volume of the sediment is measured
and, through an estimate of the bulk density of
the wet sediment, the quantity of sediment is
converted to kg/m3.
Equipment Required
• Set of stackable sieves of various sizes
covering micron range from 75 to 1000.
• Hand crank centrifuge with glass measuring
tubes scribed to 100 mL in 1 mL units.
• Funnel to assist washing material retained
on sieve into glass measuring tube
Test Procedure
• Select sieve sizes required in the stack to
qualify the specific LCM material applied for
this project (recommend five or six sieves).
• Fill one measuring tube with a known
amount of drilling fluid being tested
(recommend 100 mL).
• Pour the fluid thru the stack of sieves and
wash with base NAF.
For each sieve:
• Flush retained material from each sieve
separately to a glass tube, and after
balancing the centrifuge with another
similar tube, hand crank for one minute at
one revolution per second.
• Visually observe mL of retained material
and report as v/v % (mL observed after
centrifuging / initial mL of sample = % v/v to
be recorded).
• Convert v/v% to lb/bbl: 3.85* x % v/v = lb/
bbl. Fig. A-7-2 is an example spreadsheet of
the results.
*Assumes bulk density = 1.1. See following pages
for methods you can employ to verify or correct this
number.
Recommended but OPTIonal: Retain a limited
set of samples to be dried and weighed. Use
these data to re-calibrate the bulk density.
Make sure the project database retains all % v/v
information so that retroactive adjustments can
be made to lb/bbl calculations if required.
The measurement technique is validated by
Tubular Bells #3 / Ocean Confidence / BP
Engineer Names
Clay Brecheen
Adjusting The Bulk Density Factor
Our procedure for determining LCM
concentration employs wet-sieve equipment
and adds accelerated G’s in the form of a hand-
Validation Of Test Procedure
Well Name & Operator
density in the fluid is 1.1 g/cc, we would expect
to measure 2.6 % v/v recovered. If this is not the
case, the PSD of the product may be different, or
the bulk density may need adjustment.
1.1
80%
ActivePit2/120107/2030hrs
90%
4
ActivePit2/120107/2030hrs
Enter Bulk Density Factor to
be used in the cell Above.
Enter sample size in the
header (blue lettering) for
each sample analysed. Enter
experimental data (visual ml)
in the Green-shaded cells at
right. Depress the red macro
button to update that data set.
3
ActivePit2/120107/0115hrs
Cumulative PSD
(of material > smallest sieve in stack)
2
ActivePit2/120107/0115hrs
100%
1
70%
Daily Activity
December 1, 2007
Text autowraps, centers vertically, and aligns to the left…just keep typing
This fluid contains LPM
Larger than
Conc of material larger than
Conc of material larger than
Conc of material larger than
Conc of material larger than
Conc of material larger than
Conc of material larger than
13
50.1 ppb
75 microns
microns
ppb
75
50.1
0
0.0
0
0.0
0
0.0
0
0.0
0
0.0
3.2
3
LBS/BBL
100
0.0
0.0
4.6
0.0
4.6
1.2
100.0 ml
0%
1.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
50.1
LBS/BBL
10%
425
355
300
250
212
180
150
125
106
90
75
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1
0.0
0.0
3.9
0.0
10.0
0.0
0.0
0.0
12.3
0.0
0.0
11.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
52.0
33.1 ppb
150 microns
microns
ppb
710
4.6
500
9.2
250
21.6
150
33.1
0
0.0
0
0.0
100.0 ml
20%
40
45
50
60
70
80
100
120
140
170
Microns
200
LBS/BBL
30%
(US Mesh) Theoretical Sieve Opening
1000
841
ActivePit2/120107/0115hrs 707
595
500
ActivePit2/120107/0115hrs
420
354
ActivePit2/120107/2030hrs 297
250
210
ActivePit2/120107/2030hrs 177
149
125
5
105
88
1000
74
100.0 ml
40%
Sieve Size No.
18
20
25
30
35
LBS/BBL
(µm)Sieve Opening
ASTME II
1000
850
710
600
500
50%
100.0 ml
60%
13.5
52.0 ppb
75 microns
microns
ppb
75
52.0
0
0.0
0
0.0
0
0.0
0
0.0
0
0.0
2.6
4
4.9
0.0
0.0
0.0
15.4
0.0
0.0
18.9
0.0
0.0
0.0
0.0
48.1 ppb
150 microns
microns
ppb
710
3.9
500
13.9
250
29.3
150
48.1
0
0.0
0
0.0
Fig. A-7-2. Example of Wet Sieve Analysis output from BP Tubular Bells #3
analyzing 60 kg/m3 G-SEAL PLUS in a clean NAF.
G-SEAL PLUS has been measured to have a bulk
density of 1.1 g/cc in the RHELIANT base
fluid after compaction with the hand crank
centrifuge. We can verify that number during
this test.
First we must determine how much product we
should expect to recover with a given sieve size.
If the sample of G-SEAL PLUS has a D50 ~ 200
μm, 50% of the product in the treated fluid is
expected to be larger than a 200-micron sieve;
therefore, 30 kg/m3 of the 60 kg/m3 dosage
should be retained on the screen. If the bulk
crank centrifuge to “compact” the material
recovered by the screen before visually
estimating volume on the scribed tube.
Previous estimates of the bulk density of the
material recovered by Wet Sieve Analysis
suggested it have a mean value of 1.1 g/cc.
However, most of this work was done with
G-SEAL and G-SEAL PLUS, which have an SG of
about 2.0. Not all of the LCM used in wellbore
strengthening applications is G-SEAL or G-SEAL
PLUS. Most likely it will be a blend of materials
with SG that varies from as low as 1.4 (NUTPLUG)
to as high as 2.6 (SAFE-CARB). Consequently, the
average bulk density obtained for a particular
wellbore strengthening application may be
significantly different from 1.1 g/cc.
In addition, not only can the LCM blend vary, but
also each screen cut is likely to have a different
proportion of each LCM. Consequently, the bulk
density obtained from each screen cut may be
significantly different from 1.1 g/cc. Although
an average bulk density usually suffices for
the purpose of trend analysis, if there is some
issue about the absolute concentrations of LCM
obtained from the Wet Sieve Analysis, it may
be necessary to measure a bulk density of the
material coming off each screen and use each
of those values in the calculation of the LCM
concentrations.
In the example with 60 kg/m3 G-SEAL PLUS, we
expected to recover 2.6% v/v using a 200-μm
sieve. If however, the measured value was 2%
v/v, the Bulk Density that should be used in the
calculations is:
10 / (0.02 x 350) = 1.43
To adjust the factor used in the calculation
provided in this Procedure to convert the
observed volume % to kg/m3:
New factor = (1.43 x 350) / 100 = 5.0
Thus, instead of % v/v x 3.85 = lb/bbl, the
conversion to be used is % v/v x 5.0 = lb/bbl,
which in this case gives 2 x 5.0 = 10 lb/bbl, the
expected amount of recovered G-SEAL PLUS. In
terms of kg/m3, the conversion is % v/v x 14.25
instead of % v/v x 11.0.
An even better method is to mix a sample of the
LCM blend into base fluid. Calculate the D50 of
the blend with OPTIBRIDGE and run the 200-mesh
screen test as described above and compare the
amount recovered with what is expected. This
will provide a fairly median bulk density figure
to use in the Wet Sieve Analysis calculations.
Finally, the client may request use of bulk
densities for material captured by each screen.
This is best done by running calibration
tests using the standard dry weight method
described earlier, wherein the material captured
by each screen is washed with a powerful
volatile solvent and then air dried.
LCM Performance Tests
Permeability Plugging Tests are the only
standard performance tests recommended
for LCM, and these are only applicable for
simulating Sealing or plugging of formations
that are not fractured. These tests are run using
one of three types of Permeability Plugging
Apparatus (PPA), and all employ as the filter
medium permeable Aloxite (Al2O3) disks that
possess fixed average pore entry diameters. For
performance tests designed to simulate Sealing
and/or plugging of fractured formations, Slot
Tests are a popular choice. Common apparati
used for Slot Tests include Production Screen
Testers, modified HTHP Fluid Loss cells and
modified PPA.
Trends in the results will demonstrate not only
how well the treated fluid or pill can SEAL or
plug openings similar to those encountered
downhole, but also provide some guidance
about the character of the filter cake that is
formed atop the bridging plug. These trends
can also indicate the extent of LCM depletion or
degradation during a drilling operation.
Equipment Specifications
The Permeability Plugging Apparatus (PPA) is
the preferred apparatus for running Slot Tests. It
was originally designed for use with permeable
Aloxite disks, and, by inference, particles no
larger than a couple hundred microns. For
testing of slotted media, several modifications
to the apparatus are required. First, the exit
valve must be replaced to allow particles several
hundred microns in size to pass through; for this
purpose, the connecting tube must be replaced
with one that is 5 to 12 mm ID and the needle
valve replaced with a ball valve having an orifice
of several mm.
The filter medium consists of a ¼” to 1” thick
stainless steel disk through which a 1” long slot
with a width approximating the maximum
natural or induced fracture width that might be
expected, e.g. 500 μm. It is also possible to use a
permeable filter medium like Aloxite and carve
a slot into it with a Dremmel tool or other device
that can produce a slot of the required width.
It is helpful to add a Catch Vessel to the outlet
of the ball valve to accommodate sudden surges
of flow through the exit of the PPA cell; this can
be a low-pressure steel cell, baffled to minimize
splashing and vented away from the operator to
permit operation at ambient pressure. Finally,
it is helpful to replace the PPA hand pump with
a syringe pump capable of providing the high
flow rate of mud that often accompanies such
tests. An advantage of this modification is
that the pump provides digital output of the
pressure, total flow and flow rate.
Fig. A-7-3. Schematic of Modified PPA Slot Tester
temperature and very little by pressure, though
viscosity (which is affected by temperature and
pressure) can be expected to affect Spurt Loss.
However, the role of the Performance Tests is
trend analysis. Since this test procedure needs
to be simple, quick and minimally disruptive of
other tasks, it is recommended that the PPT be
run at ambient temperature with 1000 psi inlet
pressure and no back pressure.
If a PPA is not available, an HTHP Fluid Loss
Tester can be used, using a cell that can
accommodate the slotted disks and modifying
Fig. A-7-4. Photograph of Modified PPA Slot Tester
Permeability
Plugging Cell in
Heater Jacket
Syringe
Pump
Catch
Vessel
A schematic and photograph of the modified
PPA are shown in Figs. A-7-3 and A-7-4.
Permeability Plugging Tests (PPTs) can be carried
out as described in the API Recommended
Procedures 13 A and B, using the procedure
that is appropriate for the type of fluid (WBM
or NAF) and the type of cell. The results should
be reported as described in the API procedure,
which essentially provides the Spurt Loss when
the fluid loss is extrapolated to 0 time:
PPT Value = 2 x EV30
Spurt Loss = 2 x [EV7.5 - (EV30 - EV7.5)]
Static Filtration Rate, RS = 2 x [(EV30 - EV7.5)] /
2.739
Where volumes are in mL and
EV is the filtrate vol using a 3.5 in2 disk.
EV7.5 is the filtrate vol after 7.5 min
EV30 is the filtrate vol after 30 min
Since particle plugging is a physical
phenomenon, it is not directly affected by
the Tester in the manner described above for the
PPA. In both types of test cells, the fluid is static,
but the PPA can be run at higher pressure and
temperature than the modified HTHP fluid loss
test cell. The PPA test cell is used in an inverted
configuration, so that flow of fluid is directed
upward and, if particle suspension is not
sufficient, bridging particles will tend to settle
away from the disk. Under these circumstances,
the PPA yields an erroneous high spurt loss,
whereas the HTHP Fluid Loss test cell generates
an erroneous low spurt loss. However, if settling
is not an issue, for the same ∆P both devices
yield similar trends in bridging results. See API
RP 13l, 6th edition, May 2000.
Test Specifications
The slotted disks to be used should reflect the
expected size of the fracture aperture. Useful
slot sizes range from 100 to 1500 μm (0.1 to 1.5
mm); sets of steel disks are available from the
Houston and Stavanger technical centers. For
fractures or permeable zones with openings
less than 200 μm, an Aloxite disk with the same
average pore opening should be used. Ceramic
filter disks are available from OFITE with
nominal pore throat openings of 150 or 190 μm
(Part # 170-53-5 and # 170-53-6, respectively).
NOTE: fluid loss values measured on Aloxite
disks and slotted steel disks should not be
expected to be equivalent (for equivalent
nominal opening size). The bridging and Sealing
mechanism on a porous surface is different
from that through a slot.
A series of pilot Slot Tests should be run as part
of the LCM design process, as follows:
• Selected LCM blends should be tested
for their performance against a series of
slot sizes; these should span the range of
anticipated fracture apertures predicted by
OPTIBRIDGE or OPTI-STRESS.
• New LCM is added to the mud where this
is equivalent to the maintenance LCM to
be used at the rig site (refer to Preventative
Treatment Design) and the mud and LCM
again tested against the same slotted
disks. The maintenance LCM blend can be
OPTImized as necessary.
The results of these tests should be used as
a base line for the monitoring tests to be
performed at the rigsite.
All but FAS-XL are added and mixed with a
Hamilton Beach or similar mixer at room
temperature using the normal mixing
procedure. Then follow this procedure:
1. Mix the sample for an additional 20 min
before adding the FAS-XL;
2. Mix the FAS-XL into the sample for 5 min
while scraping the side of the mixing cup to
ensure that all the FAS-XL is incorporated in
the sample;
3. Transfer the sample into the heating
cup, and mount that cup onto a Fann 35
viscometer;
4. Begin heating the sample to the test
temperature (100 °F in this example) while
adjusting the speed to 100 rpm. Do not
exceed the test temperature, for doing so
will invalidate the test;
5. Check the sample every 30 min. When the
Fann dial reading reaches 300 deg, adjust
the speed to 6 rpm. When the dial reading
again reaches 300 deg, lower the heating
cup and note the thickness of the sample
adhering to the cylinder.
6. If the sample on the cylinder looks like that
in Fig. A-7-5, note the time and temperature.
If the sample is not sufficiently gelled, raise
the heating cup immediately and after 1
min lower it again. Repeat until gelation is
considered sufficient. This concludes the
experiment.
Thickening Rate of Crosslinkable
LCM
To confirm the temperature and time required
for a crosslinkable LCM to set up, it is advisable
to perform a pilot test at the rig. If the
crosslinker is a separate component of the
LCM formulation, all of ingredients except the
crosslinker are mixed first. For example, for an
11.1 ppg FORM-A-SET AK sample designed to set
at 100 °F, the ingredients calculated using the
software FASWare are as follows:
Water, bbl
FAS AK, lb/bbl
DUOVIS, lb/bbl
Barite, lb/bbl
FAS-XL, lb/bbl
0.83
9.6
2.1
153
4.2
(27.4 kg/m3)
(6.0 kg/m3)
(436 kg/m3)
(12 kg/m3)
Fig. A-7-5. Photograph of Fann 35 Viscometer after a
Thickening Rate Test
If the LCM is a one-sack product, such as FORMA-SET, all of the ingredients are mixed at once
and the test procedure is begun with Step 3.
Appendix 8: Product Bulletins
C-SEAL
C-SEAL F
FORM-A-BLOK
FORM-A-PLUG ACC
FORM-A-PLUG II
FORM-A-PLUG RET
FORM-A-SET ACC
FORM-A-SET AK
FORM-A-SET RET
FORM-A-SQUEEZE
G-SEAL
G-SEAL PLUS
G-SEAL PLUS C
G-SEAL HRG
G-SEAL HRG FINE
I-BOSS
LUBE-100
MD-3
M-I CEDAR FIBER
M-I-X II
MICA
NUT PLUG
OPTI-SEAL
POLYSWELL
SAFE-CARB
SAFE-LINK
SUPRASEAL
VERSAPAC
VINSEAL
Please use the PDF bookmarks to navigate to these product bulletins
C-Seal
C-Seal Fine
ADVANTAGES
■■
Effective bridging and sealing agent
for a wide range of formations and
loss severity
■■
Reduces the possibility of differential
sticking by controlling seepage losses
■■
Reduces torque and drag in all mud
systems by decreasing the coefficient
of friction (CoF)
■■
Inert material with no adverse effects
on mud rheology and compatible with
all mud systems
■■
One-sack product with no other
additive requirements; easily mixed
and dispersed into the system
■■
Easily maintained in the entire
circulating system due to its particle
size distribution
■■
The C-SEAL* and the finer grade C-SEAL* FINE
industrial carbon products are sized plugging
agents used to bridge and seal permeable
formations in water-, oil-, and synthetic-based
drilling fluid systems.
When used while drilling depleted zones, C-SEAL and C-SEAL FINE reduce differentialpressure sticking tendencies by bridging and plugging formations with high differential
pressures. They also can be used to control seepage-to-partial-to-severe lost
circulation zones. C-SEAL and C-SEAL FINE are completely inert and will not affect
the rheological properties of drilling fluid systems. They reduce torque and drag by
decreasing the coefficient of friction (CoF) and can lower the spurt and total PPT filtrate
loss values. Owing to their ability to remain in the entire circulating system using proper
solids control, C-SEAL and C-SEAL FINE can be cost-effective solutions.
Typical Physical Properties
Physical appearance ................................................................................. Gray-to-black powder
Temperature stable to >500˚F (260˚C)
Specific gravity................................................................................................................................1.9
LIMITATIONS
■■
■■
Requires close monitoring of the shale
shakers if fine-mesh screens are
utilized
Non-acid soluble material may not be
suited for open-hole completions
where acid solubility is required
Solubility in water @ 20˚C.................................................................................................. Insoluble
Product Name
Median Particle Size
d50 (μm)**
C-SEAL
100 - 150
Dry sieve analysis
C-SEAL FINE
20 - 40
Laser light scattering
Recommended Test Procedure
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications
C-SEAL and C-SEAL FINE are designed to bridge and seal permeable formations, reducing
the risks of differential sticking and lost circulation, and decreasing the coefficient of
friction (CoF).
The recommended treatment for seepage losses (< 10 bbl/hr or 1.6 m3/hr) is 15 to 20 lb/
bbl (43 to 57 kg/m3) in spotted pills. Their relatively small size and chemical inertness,
also allows C-SEAL and C-SEAL FINE to be incorporated into the entire system at a total
concentration of 5 to 20 lb/bbl (15 to 58 kg/m3).
The recommended treatment for partial losses (10 to 100 bbl/hr or 1.6 to 16 m3/hr) is 20
to 50 lb/bbl (57 to 143 kg/m3) in spotted pills. Both materials can be used in combination
with other lost circulation materials to control partial-to-severe losses. Fractured
carbonates, conglomerates and other very high-permeability formations may require
additional pills in tandem with lost circulation materials of appropriate particle size
distribution. Alternatively, either or both products can be incorporated into the entire
system at a total concentration of 10 to 30 lb/bbl (29 to 85 kg/m3).
Torque and drag may be reduced by incorporating C-SEAL and/or C-SEAL FINE sweeps
into the active system up to a total concentration of 20 lb/bbl (57 kg/m3). Initial
treatments for the active system may be added at 4 lb/bbl (11.4 kg/m3) increments while
monitoring torque and drag.
C-SEAL/C-SEAL FINE may require additional wetting agent when used in an oil- or
synthetic-based drilling fluid system.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions as described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
C-SEAL and C-SEAL FINE are packaged in 50-lb (22.7 kg), multi-wall, paper sacks.
Store in a dry location away from sources of heat or ignition, and minimize dust.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.0307.1103.R1 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
Form-a-Blok
FORM-A-BLOK* high-performance, high-strength additive is a single-sack
proprietary blend designed for wellbore strengthening applications and
a wide variety of lost circulation scenarios, including, but not limited to,
fractures and matrix permeability.
This product is applied in the form of a squeeze pill which, depending on the application, de-waters or de-oils rapidly to form a high
shear-strength plug.
Typical Physical Properties
Physical appearance ........................................................................................................................................................................................... Gray powder
Specific gravity ....................................................................................................................................................................................................................... 1.98
Odor ............................................................................................................................................................................... Odorless or non-characteristic odor
Applications
FORM-A-BLOK additive can be used in water-based or non-aqueous drilling fluids (NAF) for wellbore strengthening applications and to
cure losses extending from partial to a wide range of severe lost circulation scenarios, at temperatures up to at least 350°F (177°C).
FORM-A-BLOK product is designed to be used for:
■■
Wellbore strengthening applications
■■
Curing partial to wide ranging severe loss situations
■■
Open hole remedial and/or preventive lost circulation squeeze
■■
Improving casing shoe integrity
■■
Cased-hole squeeze for sealing perforations and casing leaks
The recommended concentration of FORM-A-BLOK additive is 40 lb/bbl (114 kg/m3), for fluid densities up to 16lb/gal (1.92 SG) in freshwater,
seawater or base oil/synthetic (NAF) systems. Fluid densities of 16lb/gal or higher require less FORM-A-BLOK; 30lb/bbl (86 kg/m3) for waterbased pills and 20 lb/bbl (57 kg/m3) for NAF-based pills. While FORM-A-BLOK additive can be mixed with oil or synthetic base fluids, mixing
a water based pill will provide the maximum strength. The slurry can be weighted with barite, calcium carbonate or heavy brine. It is
recommended to continuously agitate the pill until pumped and to pull pump screens prior to pumping.
Density, lb/gal (s.g)
Fresh-water, bbl
FORM-A-BLOK, lb/bbl
M-I BAR*, lb/bbl
9 (1.08)
0.94
40
11
Thinner, lb/bbl
-
10 (1.20)
0.90
40
66
-
12 (1.44)
0.82
40
176
-
14 (1.68)
0.75
40
286
-
16 (1.92)
0.67
30
396
18 (2.16)
0.59
30
506
Density, lb/gal (s.g)
NAF, bbl sg 0.8l
FORM-A-BLOK, lb/bbl
M-I BAR, lb/bbl
Thinner, lb/bbll
8 (0.96)
0.91
40
40
-
As needed
10 (1.20)
0.84
40
144
-
12 (1.44)
0.77
40
247
-
14 (1.68)
0.70
40
351
16 (1.92)
0.65
20
455
18 (2.16)
0.57
20
558
As needed
Advantages
■■
Quick-acting plug for wellbore strengthening and lost circulation applications
■■
Single-sack system, though higher densities may require the addition of a thinner
■■
Compatible with freshwater, seawater, brines and NAF
■■
Temperature stable to at least 350˚F (~177°C)
■■
High-performance, High-shear strength pill
■■
Can be mixed as a pill at densities of up to 18.0 lb/gal (2.16 SG)
■■
Easy to mix and pump with standard rig equipment
■■
Does not require an activator or retarder
■■
Does not depend on time or temperature to form a rigid plug
■■
Can be pre-mixed well in advance of pumping provided pill is agitated continuously
Limitations
Approximately 35% acid soluble
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
FORM-A-BLOK product is packaged in 20 lb (9 kg), multi-wall, paper sacks.
Store in a dry, well-ventilated area. Keep container closed. Store away from incompatibles. Follow safe warehousing practices
regarding palletizing, banding, shrink-wrapping and/or stacking.
This document is supplied solely for informational purposes and M-I L.L.C. makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0508.1103.R3 (E)
ALPINE SPECIALTY CHEMICALS,
A business unit of M-I. LLC
P.O. Box 42842
Houston, Texas 77242-2842
www.alpinemud.com
E-mail: info@alpinemud.com
Form-a-Plug aCC
FORM-A-PLUG* ACC additive is a blend of inorganic compounds designed
for the pH and salinity adjustments necessary to control the crosslinking
reaction in a FORM-A-PLUG lost circulation pill.
Typical Physical Properties
Physical appearance .............................................................................................................................................................................................. Off-white powder
Specific gravity .................................................................................................................................................................................................................................... 2.0
pH (1% solution) ................................................................................................................................................................................................................................. 10.5
Applications
FORM-A-PLUG ACC accelerator is used together with a FORM-A-PLUG II pill to reduce the set-up time of the lost circulation slurry. It should be
added to the lost circulation slurry immediately before pumping the mixture down the well. The accelerator will create a chemical reaction
with the FORM-A-PLUG pill to form a rigid cross-linked gel structure. It is important to carefully control the product concentrations and mixing
conditions in order to ensure that the reaction proceeds as expected. The formulation can be adjusted for density by adding barite or other
appropriate weighting materials up to 18 lb/gal (2.16 s.g.).
Recommended concentrations are 3.5-10.5 lb/bbl (10-30 kg/m3) depending on the temperature and the desired setting time. Pilot testing is
recommended before use to estimate the time to create a well-set plug. Refer to the FORM-A-PLUG II additive technical bulletin or utilize the M-I
SWACO software, FASWARE, for specific pill design.
Advantages
■■
Increases the set rate for low-temperature applications
■■
Creates a firmer plug in a shorter time at a given temperature
Limitations
■■
Pilot testing is essential to obtain optimum formulation
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions as described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
FORM-A-PLUG ACC agent is packaged in 50 lb (22.7 kg), multi-wall, paper sacks.
Store at moderate temperatures in dry a, well ventilated area.
This document is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale.
©2004 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0612.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-Plug II
FORM-A-PLUG* II pumpable lost circulation plug is a blend of borate mineral
and polymers designed for suspension, fluid-loss control and crosslinking
technology.
When activated with time and temperature, FORM-A-PLUG II plug develops a rigid crosslinked gel structure that effectively prevents loss of fluid
to the formation. The FORM-A-PLUG II material is acid soluble, more than 95% being dissolved on contact with a solution of 15% HCl.
Typical Physical Properties
Physical appearance .....................................................................................................................................................................................White to beige powder
Solubility in water ...................................................................................................................................................................................................................... Slightly
Specific gravity .................................................................................................................................................................................................................................... 2.0
pH (1% solution) .................................................................................................................................................................................................................................. 7-8
Applications
FORM-A-PLUG II fluid-loss-control plug is the main additive used to form an acid-soluble, lost-circulation plug, which can be used in any
application where a squeeze plug would be beneficial. It is particularly advantageous in areas where loss of whole mud is prevalent. FORM-APLUG II product can be used to stop losses occurring with any water-base and non-aqueous-base fluid system. FORM-A-PLUG II plug is used for
suspension, fluid-loss control and crosslinking in the lost-circulation plug.
FORM-A-PLUG II material can be used in combination with FORM-A-PLUG ACC accelerator and FORM-A-PLUG RET retarder. Together they will make a
chemical reaction to form a rigid crosslinked gel structure. It is therefore important to carefully control the product concentrations and mixing
conditions in order to ensure that the reaction proceeds as expected.
The formulation can be adjusted for density by adding barite or other appropriate weighting materials up to 18 lb/bbl (2.16 s.g.). Pilot testing is
recommended before use to estimate the time to create a well-set plug. Recommended FORM-A-PLUG II material concentrations are 60 to 100
lb/bbl (170 to 285 kg/m3) depending on the final slurry density.
The plug should be pumped to the annulus at the depth of loss. The drillstring is then pulled above the FORM-A-PLUG II plug. The plug can be
squeezed into the loss zone. Be careful not to leave the plug in the pipe even if the losses have stopped or slowed. Do not shut down pumping
while the plug is in the drillstring.
Advantages
■■
Provides suspension, fluid-loss control and crosslinking
■■
Forms a rigid gel structure
FORM-A-PLUG II Ret
FORM-A-PLUG Ret retarder is a grade of soluble magnesium chloride which delays the crosslinking reaction in the FORM-A-PLUG II lostcirculation plug to avoid premature setting during the mixing stage
■■
■■
FORM-A-PLUG Ret retarder should be added to the drill water before adding FORM-A-PLUG II material and/or FORM-A-PLUG Acc accelerator
■■
Pilot testing is recommended before use to estimate the time to create a well-set plug
FORM-A-PLUG II Acc
■■ FORM-A-PLUG Acc accelerator is a blend of inorganic compounds designed for pH and salinity adjustment necessary to control the
crosslinking reaction in the lost-circulation plug.
■■
FORM-A-PLUG Acc accelerator should be added to the lost-circulation slurry immediately before pumping the mixture down the well. The
accelerator will make a chemical reaction with the FORM-A-PLUG II material to form a rigid crosslinked gel structure.
■■
Pilot testing is recommended before use to estimate the time to create a well-set plug.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions as described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
FORM-A-PLUG II material is packaged in 55.1 lb (25 kg) multi-wall, paper sacks. Other package units are available upon request.
Store at moderate temperatures in a dry, well-ventilated area. Keep in original container.
This document is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale.
©2004 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0609.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-Plug reT
FORM-A-PLUG* RET additive is a grade of soluble magnesium chloride
formulated for delaying the cross-linking reaction of the FORM-A-PLUG II
lost circulation pill to avoid premature setting during the mixing stage.
Typical Physical Properties
Physical appearance ...........................................................................................................................................................................White powder/crystals
Specific gravity ........................................................................................................................................................................................................................1.57
Applications
FORM-A-PLUG RET agent is used in FORM-A-PLUG II pills to increase the set-up time of the lost circulation slurry. It should be added to the
drill water before adding Form-A-Plug II and/or FORM-A-PLUG* ACC agent.
FORM-A-PLUG RET retarder will delay chemical reaction which forms a rigid cross-linked gel structure. It is therefore important to carefully
control the product concentrations and mixing conditions in order to ensure that the reaction proceeds as expected. The formulation
can be adjusted for density up to 2.16 s.g. (18 lb/gal) by adding barite or other appropriate weighting materials. Barite may also act as a
retarder.
Recommended concentrations are 3.5-17.5 lb/bbl (10-50 kg/m3) depending on the temperature and the desired setting time. Pilot testing is
recommended before mixing to estimate the time to create a well-set plug.
Advantages
■■
Delays cross-linking to avoid premature setting during mixing and displacement
Limitations
■■
Must be added to the drill water before the FORM-A-PLUG II additive
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions as described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
FORM-A-PLUG RET additive is packaged in 50 lb (22.7 kg), multi-wall, paper sacks.
Store at moderate temperatures in dry, well ventilated area.
This document is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale.
©2004 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0613.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-SeT aCC
FORM-A-SET* ACC additive is a blend of inorganic compounds used to
reduce the setting times of the FORM-A-SET family of products.
FORM-A-SET ACC accelerator is used when lower mixing or application temperatures slow the cross-linking process. FORM-A-SET ACC
should be considered when the temperature of the application is less than 60° F (16 ° C).
Typical Physical Properties
Physical appearance ..............................................................................................................................................................................................Green Liquid
Solubility in water ............................................................................................................................................................................................................. Soluble
Specific gravity...........................................................................................................................................................................................................................1.4
pH (2% solution) .........................................................................................................................................................................................................................< 2
Boiling point ...........................................................................................................................................................................................................226° F (108° C)
Applications
FORM-A-SET ACC accelerator is used to reduce the setting time of the FORM-A-SET family of products. It is used when ambient
temperatures or make-up water are below 60° F (16° C). To avoid over-treatment, caution must be exercised when adding the
accelerator. The treatment level of FORM-A-SET ACC accelerator is proportional to the volume of water in the slurry. Typically 0.3 lb/bbl of
water (0.9 kg/m3 of water) is used. Pilot testing is recommended.
FORM-A-SET ACC accelerator rapidly reacts with the slurry to form a rigid, cross-linked gel structure. It is important to carefully control
the product concentrations and mixing conditions to ensure the reaction proceeds as expected. To ensure full polymer hydration, the
FORM-A-SET product should be fully mixed into water before adding FORM-A-SET ACC accelerator. It is recommended that the accelerator
be diluted in 5 to 10 gal (20-40 l) of water before adding to guarantee it is well dispersed. Because it reacts quickly, FORM-A-SET ACC
accelerator should be added to the lost circulation slurry immediately before pumping the mixture down the well.
Advantages
■■
Reduces setting times
■■
Creates a firmer plug in a shorter time at a given temperature
Limitations
Can cause “flash” setting of the slurry if temperature is greater than 85° F (30° C)
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
FORM-A-SET ACC accelerator is packaged in 1 quart (0.95 l) cans containing 3 lb (1.4 kg) of product.
Store in a dry, well-ventilated area. Keep container closed. Keep away from heat, sparks and flames. Store away from incompatibles.
Follow safe warehousing practices regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2010 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0618.1010.R2 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-SeT ak
FORM-A-SET* AK lost-circulation-control material is a blend of polymers and
fibrous materials designed to plug matrix and fractured zones.
When combined with Duo-Vis* biopolymer and activated with a combination of FORM-A-SET XL crosslinking agent along with time and
temperature, FORM-A-SET AK produces a firm, rubbery, ductile plug that effectively prevents loss of fluid to the formation. The fibrous material
in the FORM-A-SET AK package is a mixture of particle sizes designed to plug fine-to-medium sized, deep fractures and faults.
Typical Physical Properties
Physical appearance ................................................................................................................................................................................................ Light tan powder
Specific gravity..................................................................................................................................................................................................................................... 1.2
Bulk density ..............................................................................................................................................................................................................35 lb/ft3 (550 kg/m3)
Applications
FORM-A-SET AK fluid-loss-control plug can be used to stop partial and matrix losses in any water, oil or synthetic-base drilling fluid system.
FORM-A-SET AK can be mixed in freshwater, seawater or saltwater up to saturation, though mixing in saltwater will retard set times. FORM-A-SET
AK can be used in any application where a squeeze plug is beneficial and needs a smaller particle-size distribution of bridging material than
does FORM-A-SET. The smaller particles enhance the ability of the material to penetrate a porous or fractured zone.
FORM-A-SET AK lost-circulation material does not contain a crosslinking agent, thus allowing for more control than the FORM-A-SET product. The
plug can be mixed and stored on location as a contingency, significantly reducing response time.
Once losses are encountered, the plug is activated by adding FORM-A-SET XL crosslinker (see enclosed tables for mixing concentration).
The FORM-A-SET AK plug subsequently is spotted across and above the loss zone, and squeezed into place. Depending on the loss rate and
whether the losses are to fractures, vugs, etc., sufficient FORM-A-SET AK should be applied to completely cover the expected loss zone, along
with a 100% excess to squeeze into the borehole breech.
Retarder/Accelerator
FORM-A-SET Ret retarder should be used with applications above 105°F (38°C) or when pill temperature exceeds 105 °F (38°C) when mixing.
FORM-A-SET Ret must be added to the plug before adding FORM-A-SET XL crosslinking agent. If the plug is to be used immediately, FORM-A-SET Ret
may be added to the water prior to the addition of FORM-A-SET AK. Otherwise, it should be mixed into the plug just before adding FORM-A-SET XL.
Use FASWARE* to determine the FORM-A-SET RET required. Table 1 provides the typical concentrations. For best results, pilot test for sufficient
retarder concentration.
Table 1 – FORM-A-SET retarder concentration for FORM-A-SET AK
Bottomhole Temperature
°F
Up to 105
105-123
123-140
140-155
155-190
190-250
250+
°C
Up to 38
38 - 50
50 - 55
55 - 68
68 - 88
88 - 120
122+
FORM-A-SET RET
lb/bbl of water
kg/m3 of water
----2
6
4
12
6
17
10
29
16
46
FASWARE and lab testing recommended
Note: FORM-A-SET RET retarder concentration is proportionate to the water volume.
FORM-A-SET ACC accelerator crosslinks and speeds up the setting of the plug. It is used when placement temperatures are below 60°F (15.6°C).
To avoid over treatment, exercise caution when adding the accelerator. Use 0.3 lb/bbl (0.9 kg/m3) FORM-A-SET ACC accelerator, proportional to
the water volume. FORM-A-SET ACC accelerator should be added after adding FORM-A-SET XL. Diluting the FORM-A-SET ACC in 5 to 10 gal (20-40 L)
of water makes it easier to blend in the FORM-A-SET XL.
Unweighted Slurry Mixing Instructions
To mix an unweighted pill of FORM-A-SET AK plug, use a clean pit or blending tank.
1. Fill the pit with 0.93 bbl (0.93 m3) of fresh water for each barrel (cubic meter) of pill.
2. Add 1.4 lb/bbl (0.7 kg/m3), one-half of the total DUO-VIS
3. Add 23 lb/bbl (11.6 kg/m3) FORM-A-SET AK material
4. Add the remaining DUO-VIS biopolymer
5. If the plug is to be held for more than 1 day, treat with 0.1 gal/bbl (2 L/m3) 25% glutaraldehyde biocide and 0.1 lb/bbl (3 kg/m3) X-Cide 207
or other isothiazalone product. Failure to include biocides can affect performance of the plug. If biocides are unavailable, consider using
FORM-A-SET AKX.
6. When ready to pump, add FORM-A-SET Ret if required.
7. Add FORM-A-SET XL and mix 5 min. If needed, add FORM-A-SET ACC after FORM-A-SET XL.
Weighted Slurry Mixing Instructions
Use FASware to determine the optimum formulation of FORM-A-SET AK slurries with barite weighting agent. Table 2 presents the typical blends.
Mixing order should be:
1. Add one-half of the DUO-VIS biopolymer
2. Add one-half the FORM-A-SET AK material
3. Add the M-I Bar barite
4. Add the remaining FORM-A-SET AK material
5. Add the remaining Duo-Vis biopolymer
6. If the plug is to be held for more than one day, treat with 0.1 gal/bbl (2 L/m3) 25% glutaraldehyde biocide and 0.1 lb/bbl (3 kg/m3) X-Cide 207.
Failure to include biocides can affect performance of the plug. If biocides are unavailable, consider using FORM-A-SET AKX.
7. When ready to pump, add FORM-A-SET Ret, if required
8. Add FORM-A-SET XL and mix 5 min. In cold applications, add FORM-A-SET ACC after FORM-A-SET XL.
Note: Use only ester or alcohol-base defoamer such as DEFOAM-A*. Aluminum-stearate based defoamers may interfere with set time.
Pumping Instructions
Once losses are encountered, add FORM-A-SET Ret retarder, if required, and mix thoroughly for 5 min. Add the proper amount of FORM-A-SET XL
crosslinker to the pill, mix thoroughly for 5 min., and pump immediately afterwards.
When used in a non-aqueous drilling fluid, pump approximately 20 to 30 bbl (3 to 5 m3) of viscous water or water-based mud as spacers in front
of and behind the pill. A 2 lb/bbl (5.7 kg/m3) DUO-VIS slurry weighted up to the same density makes a good spacer. Aqueous fluids may require
spacers if they have high pH or are otherwise incompatible.
Depending on loss rate, spot the pill across and above the loss zone while pulling out of the hole to a safe location. Keep the pill below the bit
to avoid it mixing with wellbore fluids. This pill crosslinks and sets up as a flexible plug. Even if losses have stopped, it is important not to leave
any pill in the pipe. Do not stop pumping while the pill is in the drillstring. It is important to pump at least 10 bbl (2 m3) of spacer or water-based
mud to clear the drillstring.
Watch for any sign of the pill reaching the loss zone, such as increased pressure or improved return flow. To begin squeezing, pull above the
pill and close the annular preventer. Typically two-thirds to three-quarters of the pill is squeezed away. If pressure is noted, hold for at least
three hours to obtain a firm set of the pill.
Table 2 – Mixing Concentrations
Density
lb/gal
8.34
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
14.5
15.0
15.5
16.0
16.5
17.0
17.5
18.0
s.g.
1.00
1.08
1.14
1.20
1.26
1.32
1.38
1.44
1.50
1.56
1.62
1.68
1.74
1.80
1.86
1.92
1.98
2.04
2.10
2.16
Water
bbl/bbl
0.93
0.90
0.89
0.87
0.85
0.83
0.82
0.80
0.78
0.765
0.748
0.730
0.713
0.696
0.679
0.661
0.644
0.627
0.611
0.594
m3
0.93
0.90
0.89
0.87
0.85
0.83
0.82
0.80
0.78
0.77
0.75
0.73
0.71
0.70
0.68
0.66
0.64
0.63
0.61
0.59
DUO-VISTM
lb/bbl
2.77
2.71
2.65
2.60
2.55
2.10
1.80
1.60
1.34
1.13
0.95
0.78
0.64
0.51
0.00
0.00
0.00
0.00
0.00
0.00
kg/m3
7.89
7.72
7.55
7.41
7.27
5.99
5.13
4.56
3.82
3.22
2.71
2.22
1.82
1.45
0.00
0.00
0.00
0.00
0.00
0.00
FORM-A-SET AKTM
lb/bbl
23.12
22.55
22.11
21.68
21.25
20.85
20.40
19.97
19.55
19.12
18.69
18.26
17.83
17.40
16.97
16.54
16.10
15.67
15.24
14.80
kg/m3
65.89
64.27
63.01
61.79
60.56
59.42
58.14
56.91
55.72
54.49
53.27
52.04
50.82
49.59
48.36
47.14
45.89
44.66
43.43
42.18
NOTE: FASWARE can provide more precise formulations.
FORM-A-SET XLTM
lb/bbl
5.0
4.75
4.75
4.50
4.50
4.25
4.25
4.00
4.00
3.75
3.75
3.50
3.50
3.25
3.25
3.00
3.00
2.75
2.75
2.50
kg/m3
14.25
13.54
13.54
12.83
12.83
12.11
12.11
11.40
11.40
10.69
10.69
9.98
9.98
9.26
9.26
8.55
8.55
7.84
7.84
7.13
M-I Bar®
lb/bbl
0
37.2
64.8
92.3
119.9
147.6
175.3
202.9
230.6
258.2
285.8
313.4
341.0
368.6
396.2
423.8
451.3
478.9
506.4
534.0
kg/m3
0.0
106.0
184.7
263.1
341.7
420.7
499.6
578.3
657.2
735.9
814.5
893.2
971.9
1050.5
1129.2
1207.8
1286.2
1364.9
1443.2
1521.9
FORM-A-SET AK Mixing Example
Two hundred barrels (32 m3) of a 14 lb/gal (1680 kg/m3) FORM-a-SET AK plug is needed to seal a fracture in a 190°F (88° C) formation.
As shown in Table 1, for the formation temperature of 190° F (88° C), the FORM-A-SET RET concentration should be 10 lb/bbl (29 kg/m3). Using
the Mixing Concentrations in Table 2, the formulation and mixing order is as follows:
1. Water: 0.730 barrel/bbl x 200 = 146 bbl (23 m3)
2. DUO-VIS biopolymer: 0.39 lb/bbl (half of the total required) x 200 = 78 lb (35 kg)
3. FORM-A-SET AK material: 9.13 lb/bbl (half of the total required) x 200 = 1826 lb (828 kg)
4. M-I BAR barite: 313.4 lb/bbl x 200 = 62,680 lb (28.4 tonne)
5. FORM-A-SET AK material: (the second half of the total required) = 1826 lb (828 kg)
6. DUO-VIS biopolymer: (the second half of the total required) = 78 lb (35 kg)
7. FORM-A-SET Ret retarder: 10 lb/bbl (29 kg/m3) proportioned to water volume:
(10 lb/bbl of water X 0.73 bbl water/bbl of pill = 7.3 lb/bbl of pill) x 200 = 146 lb (66 kg)
8. FORM-A-SET XL crosslinker: 3.5 lb/bbl x 200 = 70 lb (32 kg)
Note: FASWARE* provides more exact formulations.
Advantages
• FORM-A-SET AK additive contains only the polymer and lost-circulation material. It can be mixed and stored on location before losses are
encountered to reduce response time. Proper biocidal treatments are required.
• Because of its increased polymer loading and the smaller size of the fibrous material, the FORM-A-SET AK fluid loss control plug has a much
firmer set than the conventional FORM-A-SET plug
• Because of the firmer set, FORM-A-SET AK plug has a wider range of applications. These applications range from matrix to partial losses of
20-100 bbl/hr (3 to 16 m3/hr).
• The material also can be used to shut off water in non-productive zones and in gravel consolidation
Limitations
• Static conditions are required for the pill to completely set up, so FORM-A-SET AKX is best used to cure matrix and partial losses or as part of
a tandem pill to cure severe losses
• A FORM-A-SET AK plug does not degrade in the well bore even at extended times. It is not acid soluble and caution should be exercised when
it is used in or near the production zone
• Pilot testing is recommended to assure set time/temperature under field conditions, especially when made up in brine. Contact Technical
Services for procedures.
• Lab testing for set time and thermal stability is recommended when temperatures exceed 250° F (120° C)
• Pilot/lab testing is recommended when density exceeds 16.0 lb/gal (1.9 s.g.)
• For all plugs to be held for 24 hours or longer, include 0.1 lb/bbl (0.3 kg/m3) of X-Cide 207 or other isothiazalone biocide and 0.1 gal/bbl (2 l/m3)
25% glutaraldehyde biocide
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data Sheet
(MSDS).
Packaging and Storage
FORM-A-SET AK material is packaged in 47 lb (21.3 kg) sacks or 25 lb (11.3 kg) sacks.
FORM-A-SET Ret retarder is packaged in 5 gal (18.9 l) cans containing 55-lb (24.6 kg) of product.
FORM-A-SET ACC accelerator is packaged in 1 qt (0.946 l) containers containing 3-lb (1.4-kg) of product.
FORM-A-SET XL crosslinker is packaged in a 50-lb (22.7 kg) sack enclosed in a 12 gal (45.4 l) cardboard can.
Store these products in a dry, well-ventilated area. Keep container closed. Store away from incompatibles. Follow safe warehousing practices
regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2010 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0611.1010.R2 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-SeT reT
FORM-A-SET* RET retarder should be used in situations when the FORM-ASET system is mixed or spotted at temperatures higher than 80° F (27° C).
FORM-A-SET RET retarder often is required by other FORM-A-SET systems, such as FORM-A-SET AK and FORM-A-SET AKX. The concentration
required depends on both mixing and down-hole temperatures. When used with FORM-A-SET, it is essential that FORM-A-SET RET retarder
be added to the water before adding FORM-A-SET. It may be added to the water before or after FORM-A-SET AK or FORM-A-SET AKX, but must
always be added before FORM-A-SET XL.
Typical Physical Properties
Physical appearance ................................................................................................................................................................................................ Clear liquid
Odor .........................................................................................................................................................................................................................................None
Solubility in water ............................................................................................................................................................................................................. Soluble
Specific gravity................................................................................................................................................................................. 1.31 – 1.34 @ 68° F (20° C)
Flash point ..............................................................................................................................................................................................................>200° F (93° C)
Applications
FORM-A-SET RET retarder delays the setting time of the FORM-A-SET family of cross-linked pills. It is used where the pills must be mixed in
hot water or spotted at high downhole temperatures.
Since FORM-A-SET contains a crosslinking additive, it is essential that FORM-A-SET RET retarder be added to the water before adding FORMA-SET. When using FORM-A-SET products, such as FORM-A-SET AK and Form-A-SET AKX that do not contain a crosslinker, FORM-A-SET RET
must be added before FORM-A-SET XL.
The following table should be used as a guide to the concentrations needed for higher bottomhole temperatures. It is important to pilot
test the formulation to assure adequate retarder is available.
Table 1 Bottomhole Temperature vs. Concentration of FORM-A-SET Ret Retarder
Bottomhole Temperature
kg/m3 of FORM-A-SET RET
Retarder in water
°F
°C
lb/bbl of FORM-A-SET RET
Retarder in water
Up to 80
Up to 27
–
–
80 – 120
27 – 49
4
11
120 – 150
49 – 66
6
17
150 – 200
66 – 93
10
29
200 – 250
93 – 120
16
46
>250
>120
Advantages
■■
Allows FORM-A-SET products to set in four hours under a wide range of temperatures
■■
Mixes easily
Contact Technical Services
Limitations
■■
Required in all applications where bottomhole temperatures exceed 80° F (27° C)
■■
May be required when mixing at temperatures above 80° F (27° C) or when set times must be delayed beyond four hours
■■
May biodegrade when added too far in advance
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data Sheet
(MSDS).
Packaging and Storage
FORM-A-SET RET retarder is packaged in 5 gal (18.9 l) cans containing 55-lb (25 kg).
Store in a dry, well-ventilated area. Keep container closed. Keep away from heat, sparks and flames. Store away from incompatibles. Follow
safe warehousing practices regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2010 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.0616.1010.R2 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Form-a-Squeeze
FORM-A-SQUEEZE* high-fluid loss/high-solids slurry is a cost-effective
solution to lost circulation in all types of fractures, vugular formations,
matrix and underground blowout events.
When placed in and/or across a loss zone, the liquid phase squeezes from the slurry, rapidly leaving a solid plug behind. This process
can cure losses instantly, without time or temperature dependency.
Typical Physical Properties
Physical appearance ............................................................................................................................................................................................Gray powder
Specific gravity.............................................................................................................................................................................................................. 1.70–1.76
Solubility in water ................................................................................................................................................................................................................Slight
Odor .......................................................................................................................................................................................................................................None
Applications
FORM-A-SQUEEZE lost-circulation (LC) plug can be used to stop losses occurring in any water-base and non-aqueous base fluid and can be
easily mixed in freshwater, seawater or base oil/synthetic. It was designed to be used as:
• Open-hole remedial and/or preventive lost circulation squeeze
• Plug to run in front of cement squeezes
• Plug to improve casing shoe integrity
• Preventive LC material for seepage losses, up to 20 lb/bbl (57 kg/m3) in the whole active system
• Cased-hole squeeze for sealing perforations and casing leaks
The recommended concentration of FORM-A-SQUEEZE slurry is 80 lb/bbl (228 kg/m³) in either water or base oil/synthetic. The slurry can be
weighted to the desired density with barite or calcium carbonate.
The slurry should be pumped to the annulus, covering at least 50% in excess of the loss zone. The drill string is then pulled slowly 90 ft (27 m)
above the pill. The slurry should be gently squeezed in the range of 100-300 psi (6.9 to 20.7 bar) to the maximum of anticipated mud weight
required for the interval, holding the pressure for 10 to 20 min.
.
g-Seal
ADVANTAGES
■■
Effective bridging and sealing agent
for a wide range of formations and
severity of losses
■■
Controls seepage losses, thereby
reducing the possibility of differential
sticking
■■
Decreases the CoF to reduce torque
and drag in all mud systems
■■
Inert material with no adverse effects
on mud rheology and compatible with
all mud systems
■■
Temperature-stable to more than 500° F
(260° C)
■■
One-sack product that is easily mixed
and dispersed into any fluid system
■■
May be used in combination with
other additives, particularly lost
circulation materials.
G-SEAL* graphite is a coarse-sized plugging
agent used in water-, oil- or synthetic-based
drilling fluids to bridge and seal permeable and
fractured formations.
When drilling depleted zones exposed to high differential pressures, the bridging and
plugging capabilities of G-SEAL additive can reduce the potential for stuck pipe. G-SEAL
is chemically inert and thermally stable, and will not affect rheological properties when
used at recommended concentrations. It can lower the potential for lost circulation
and reduce torque and drag in many drilling applications.
Typical Physical Properties
Physical appearance ........................................................................Dark gray-to-black powder
Specific gravity..................................................................................................................... 2.19-2.26
Solubility in water @ 68° F (20° C) ................................................................................... Insoluble
Median Particle Size (d50)**....................................................................................... 300 – 350 µm
Applications
LIMITATIONS
■■
Can be removed from the circulating
system by shale shakers and other
solids-control equipment. Requires
close monitoring of the shale shakers.
■■
Non-acid-soluble material may not be
suited for open-hole completions in
which acid solubility is required.
G-SEAL additive is designed to be used in any type of drilling fluid to bridge and seal
permeable and fractured formations, thus controlling lost circulation and reducing the
possibility of differential sticking. G-SEAL can also be used to decrease the coefficient
of friction (CoF) of drilling fluids.
The recommended treatment for seepage losses (< 10 bbl/hr or 1.6 m3/hr) is 15 to 20
lb/bbl (43 to 57 kg/m3) in spotted pills or sweeps. G-SEAL can be incorporated into the
entire system at a total concentration of 5 to 10 lb/bbl (14 to 29 kg/m3). However, this
may require using coarser shaker screens. If changing screens is impractical, pills
returning to the surface can be diverted to a standby pit, reconditioned and re-used as
spots or sweeps.
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications (Cont)
The recommended treatment for partial losses (10 to 100 bbl/hr or 1.6 to 16 m3/hr) is 20
to 50 lb/bbl (57 to 143 kg/m3) in spotted pills. Very high permeability formations such as
fractured carbonates and conglomerates may require additional pills in combination
with other lost circulation materials of appropriate particle size distribution.
Torque and drag may be reduced by incorporating G-SEAL spots and sweeps into the
active system up to a total concentration of 10 lb/bbl (29 kg/m3). Initial treatments for the
active system may be applied in 2 lb/bbl (5.7 kg/m3) increments while monitoring torque
and drag.
G-SEAL may require additional wetting agent when used in an oil- or synthetic-based
mud system.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
G-SEAL additive is packaged in 25 kg (55.1 lb) multi-wall, paper sacks and does not
require special storage.
Store in a dry, well-ventilated area. Keep container closed. Follow safe warehousing
practices regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.0765.1103.R4 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
g-Seal PluS
g-Seal PluS CoarSe
ADVANTAGES
■■
Effective bridging and sealing agent
for a wide range of formations and
severity of losses
■■
Increases fracture propagation
pressures of test samples exposed to
non-aqueous fluids
■■
Reduces the possibility of differential
sticking by controlling seepage losses
■■
Reduces torque and drag in all mud
systems by decreasing the coefficient
of friction (CoF)
■■
Inert material with no significant
effects on mud rheology; compatible
with all mud systems
■■
One-sack product with no other
additive requirements; easily mixed
and dispersed into the system
■■
Its particle size distribution makes it
easy to maintain in the entire
circulating system
■■
Can be pumped easily through downhole tools at concentrations up to 100
lb/bbl (285 kg/m3)
■■
Temperature-stable to >500° F (260° C)
G-SEAL*PLUS and G-SEAL PLUS COARSE* graphite/
industrial carbon blends are sized plugging
agents used to bridge and seal porous and
fractured formations in water-, oil-, and
synthetic-based drilling fluid systems.
When used to drill depleted zones with high differential pressures, the products’
bridging and plugging capabilities reduce differential-pressure sticking tendencies.
Both products also can be used to control seepage, partial and severe lost circulation,
as well as reduce torque and drag. G-SEAL PLUS and G-SEAL PLUS COARSE blends are
chemically inert and will not affect the rheological properties of drilling fluid systems
when used at the recommended concentrations.
Typical Physical Properties
Physical appearance ................................................................................. Gray-to-black powder
Specific gravity....................................................................................................................... 1.9 - 2.1
Solubility in water @ 20°C ................................................................................................. Insoluble
Product Name
Median Particle Size
d50 (μm)**
Recommended Test Procedure
G-SEAL PLUS
200 - 500
Dry sieve analysis
G-SEAL PLUS COARSE
600 - 1000
Dry sieve analysis
LIMITATIONS
■■
Can be removed from the circulating
system by shale shakers and solids
control equipment. Requires close
monitoring of the shale shakers.
■■
Non-acid-soluble material may not be
suited for open-hole completions
where acid solubility is required.
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications
G-SEAL PLUS and G-SEAL PLUS COARSE are carbon-based blends designed to stop losses
in porous and fractured formations while drilling with non-aqueous fluids. They also
are effective in water-based fluids, reducing the possibility of differential sticking and
lost circulation, as well as minimizing torque and drag by decreasing the coefficient of
friction (CoF).
Both of these products, when used alone or in blends with other lost circulation
materials, facilitate fracture bridging, effectively dissipating fracture energy and
preventing fracture propagation. The products deform under compression, thus
providing resistance to fracture re-opening.
The recommended treatment for seepage losses (up to 10 bbl/hr or 1.6 m3/hr) is 15 to 20
lb/bbl (43 to 57 kg/m3) of G-SEAL PLUS / G-SEAL PLUS COARSE in spotted pills. The pills can be
incorporated into the entire system for a total concentration of 10 to 20 lb/bbl (29 to 58
kg/m3), but close monitoring of the shakers is required.
The recommended treatment for partial losses (10 to 100 bbl/hr or 1.6 to 16 m3/hr) is 20
to 50 lb/bbl (57 to 143 kg/m3) of G-SEAL PLUS / G-SEAL PLUS COARSE in spotted pills. Very
high-permeability formations such as fractured carbonates and conglomerates may
require higher concentrations of G-SEAL PLUS or G-SEAL PLUS COARSE in conjunction with
other lost circulation materials of varied appropriate size distribution.
G-SEAL PLUS / G-SEAL PLUS COARSE can also be used dry-blended with cement to effectively
seal off induced fractures and inhibit further propagation while cementing casing.
Torque and drag may be reduced by incorporating sweeps of G-SEAL PLUS or G-SEAL
PLUS COARSE into the active system up to a total concentration of 20 lb/bbl (57 kg/m3).
Initial treatments for the active system may be added in 4-lb/bbl (11.4-kg/m3) increments
while monitoring torque and drag.
G-SEAL PLUS or G-SEAL PLUS COARSE may require additional wetting agent when used in an
oil- or synthetic-based drilling fluid system.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
G-SEAL PLUS and G-SEAL PLUS COARSE are packaged in 25-lb (11.3-kg), multi-wall, paper sacks.
Store in dry, well-ventilated area. Keep container closed. Store away from
incompatibles.
Store in a dry, well-ventilated area. Keep container closed. Store away from
incompatibles. Follow safe warehousing practices regarding palletizing, banding,
shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.0772.1103.R1 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
g-Seal Hrg
g-Seal Hrg Fine
ADVANTAGES
■■
Effective bridging and sealing agent
for a wide range of formations and
severity of losses
■■
Improved performance in comparison
to G-SEAL materials
■■
Controls seepage losses, thereby
reducing the possibility of differential
sticking
■■
Decreases the CoF to reduce torque
and drag in all mud systems
■■
Inert material with no adverse effects
on mud rheology and compatible with
all mud systems
■■
One-sack product with no other
additive requirements; easy to mix and
disperse into the system
■■
Temperature-stable to more than 500° F
(260° C)
G-SEAL*HRG and its finer grade alternative
G-SEAL HRG FINE* are high-resiliency graphites
that provide enhanced bridging and sealing of
induced fractures.
Owing to their higher resiliency, G-SEAL HRG and G-SEAL HRG FINE deliver more
deformability than conventional G-SEAL, making them suitable for either replacing or
supplementing G-SEAL. Both grades of the product are compatible with water-, oil- and
synthetic-based drilling fluid systems and are effective bridging and sealing materials
for natural or induced fractures and for drilling permeable formations. The bridging
ability of these products makes them effective additives when drilling depleted zones,
where high differential pressure increases sticking tendency. They also can be used
to control seepage in partial-to-severe lost circulation zones. G-SEAL HRG additives are
completely inert and do not affect the rheological properties of the fluid. They have
the capacity to increase lubricity, thereby reducing torque and drag. Furthermore, in
Permeability Plugging Tests (PPT) and sand bed laboratory studies, G-SEAL HRG has
been shown to exhibit lower spurt and total filtrate loss values.
Typical Physical Properties
Physical appearance ........................................................................Dark gray-to-black powder
LIMITATIONS
■■
■■
Can be removed from the circulating
system by shale shakers and other
solids-control equipment. Requires
close monitoring of the shale shakers.
Non-acid-soluble material may not be
suitable for open hole completions.
Solubility in water @ 20° C (68° F) ................................................................................... Insoluble
Specific gravity (lb/gal) ...............................................................2.19 - 2.26 sg (18.2 - 18.8 lb/gal)
Product Name
Median Particle Size
d50 (μm)**
G-SEAL HRG
450 - 550
Dry sieve analysis
G-SEAL HRG FINE
25 - 55
Laser light scattering
Recommended Test Procedure
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications
G-SEAL HRG and G-SEAL HRG FINE are designed to bridge and seal fractures, particularly
drilling-induced fractures and permeable formations. This makes them effective for
controlling lost circulation and increasing lubricity while reducing the possibility of
differential sticking.
The recommended treatment for seepage losses (< 10 bbl/hr or 1.6 m3/hr) is 15 to 20
lb/bbl (43 to 57 kg/m3) of G-SEAL HRG/G-SEAL HRG FINE in spotted pills or sweeps. The
pills can be incorporated into the entire system for a total concentration of 5 to 10 lb/
bbl (14 to 29 kg/m3). However, when the pill returns to the surface, the shaker screens
must be monitored for losses and changed if necessary. If changing shaker screens
is impractical, once the pill returns to surface, it can be diverted to a standby pit,
reconditioned and re-used as a spot or sweep.
The recommended treatment for partial losses (10 to 100 bbl/hr or 1.5 to 15 m3/hr) is
20 to 50 lb/bbl (57 to 143 kg/m3) of G-SEAL HRG/G-SEAL HRG FINE in spotted pills. Highly
permeable formations such as fractured carbonates and conglomerates may require
additional pills in conjunction with lost circulation materials of various sizes. The
product(s) also can be incorporated into the entire system for a total concentration of 5
to 25 lb/bbl (29 to 70 kg/m3).
Torque and drag can be reduced by incorporating G-SEAL HRG/G-SEAL HRG FINE spots
and sweeps into the active system up to a total concentration of 10 lb/bbl (29 kg/m3).
Initial treatments for the active system may be applied in 2 lb/bbl (5.7 kg/m3) increments
while monitoring torque and drag.
G-SEAL HRG/G-SEAL HRG FINE may require additional wetting agent when used in an oilor synthetic-based drilling fluid system.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
G-SEAL HRG AND G-SEAL HRG FINE are packaged in 50 lb(22.7 kg), multi-wall, paper sacks
and do not require special storage.
Store in a dry, well-ventilated area. Keep container closed. Store away from
incompatibles. Follow safe warehousing practices regarding palletizing, banding,
shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.0771.1103.R1 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
I-BOSS Strengthening While Drilling
The suite of integrated solutions
that prevents lost circulation
D R I L L I N G
S O L U T I O N S
Onsite particle-size
distribution and
performance
LPM recovery
Custom-designed
LPM blend
Particulate-based LPM
Chemistry-based LPM
Note: This is a very low-quality
image. Is a better version
available?
Fracture, filling, bridging
and plugging tests
Features
Benefits
• Flexible solution can be tailored
for specific wells
• Computer optimization
• Rigsite testing apparatus
• Applicable for permeable matrices
• Novel solution for shale
application
• Ability to recover bridging
particles
• Real-time, in-line particle-size
measurement
• Reduced downhole fluid loss
• Lower NPT
• Potential to drill difficult plays
• Brown field applications
• Reduced stuck pipe incidences
• Potentially saves one or more
casing strings
Going up against fragile formations?
You need the I-BOSS strategy.
Wellbore instability and the resulting
While conventional treatments
lost circulation continue to be the cost-
can decrease drilling-fluid losses,
in zones with low fracture gradients,
liest problems encountered during
increasingly challenging drilling
resulting in significantly reduced
wellbore construction. Historically,
environments severely limit the rate
drilling costs, less non-productive
standard remedial treatments for
of success of these measures. This is
time and, possibly, the elimination
stemming losses in drilling-induced
especially true if losses are inevitable,
of an entire casing string.
fractures have not been that successful
such as: drilling mature fields,
largely because they are reactionary in
extended-reach wells, complex well
I-BOSS strategies
nature. Other strengthening methods,
configurations, zones with narrow
When opting to drill above the fracture-
including casing and cementing, are
pore-pressure/fracture-gradient
initiation pressure, operators have a
effective but very expensive.
drilling windows and deepwater
variety of techniques available, and
wells when drilling through fragile
I-BOSS solutions draw from the most
or depleted zones above the target.
effective of these for your application:
The I-BOSS solutions
• Increasing the near-wellbore
Now operators have a way of reducing
losses incurred through drillinginduced fractures: the I-BOSS* suite
of integrated solutions. The I-BOSS
approach actually uses these fractures
Operators can construct wellbores
strength and the fracture
initiation pressure
• Isolating the tip of the existing
fractures and increasing fracture
reopening pressure
as part of the strengthening strategy
• Isolating the wellbore from the well-
and employs services, chemicals and
bore fluid and/or pressure with casing
equipment specifically designed to
The common element within all of
stabilize and strengthen wellbores
these is the use of specifically sized
while drilling.
and specially designed particulates
Just as there is no universal cure
added to the drilling fluid in a care-
for any given drilling problem, the
fully controlled manner, as well as
I-BOSS solutions draw upon a range
specialized chemical applications.
of proven tools and integrates the
elements needed for a successful
outcome on a well-by-well basis.
The mechanics of I-BOSS
wellbore strengthening
There are various theories that
describe the mechanisms for
strengthening the wellbore. The
methods used overlap one another
as well as some of the approaches
Induced fractures:
during drilling, lossprevention material
is driven into
fractures as they
are induced. The
LPM acts similar
to a keystone in
an arch.
used to stop lost circulation.
The fundamental difference
between simple lost-circulation cures
Outward compression of
formation: where the LPM
wedges into the induced
fractures, it generates
compression in the wellbore
wall as it forces aside the formation.
and wellbore-strengthening solutions
is that lost-circulation remedies deal
only with mitigating losses of whole
mud. Wellbore strengthening, on the
other hand, focuses on avoiding losses
and increasing the apparent fracture
gradient through a combination of
“stressing” the wellbore and isolating
the fracture tip from further elonga-
When drilling-fluid pressure induces a
fracture, fluid fills the void, wedging it
open until properly sized LPM is forced
into the opening. This wedging process
“squeezes” the formation outward,
around the perimeter of the wellbore.
tion and consequent reopening.
This stress environment is created
in much the same way that one would
shore up an arch with a keystone and
thus in a similar fashion, the “wedge”
generated while fracturing is propped
open by particulate or by chemical
Outward compression and
strengthening of the wellbore
means and thus creating a “stressed”
or strengthened wellbore. Again, by
isolating the fracture tip or imparting
a degree of “stress” (or both), certain
wellbores can be strengthened, allowing drilling to continue without costly
losses, potential stuck pipe or side-
Once the drilling fluid is trapped in the fracture
behind the LPM bridge, the filtrate bleeds off
into the porous formations, and the fracture
closes. In impermeable formations where the
filtrate cannot bleed off, the LPM bridge must
completely seal the fracture.
track incidents.
The drop in fluid pressure
within the fracture transfers
high compressive stress to the
LPM bridge, thus maintaining
wellbore compression.
– Water-setting compressive
cost effectiveness of the wellbore-
chemistry for shales and
strengthening treatment. The
permeable formations
MPSRS savings are two-fold: first,
• Wet Sieve Analysis monitors particle-
increased drilling performance
size distribution of the I-BOSS addi-
because of lost-circulation avoid-
tives at the rig for maintenance of
ance and second, reduced con-
the correct size and concentration
sumption of valuable product,
of the materials in the drilling fluid
including graphitic materials.
Particle recovery
• MD-3*triple-deck shale shaker
provides three decks of auto-
The M-I SWACO I-BOSS approach
mated, effective solids control
relies on the presence of precisely
in a small-footprint unit
sized and optimally distributed
• Focused-Beam-Reflectance
LPM in the drilling-fluid system;
Measurement (FBRM) – Real time
this absolutely essential for success.
particle-size-distribution data at
To ensure the proper concentration
the rigsite of loss-prevention
of LPM, M-I SWACO has developed
materials directly at the flowline
and/or incorporated specialized
Your M-I SWACO representative
equipment and instrumentation:
will be glad to give you more infor-
• The M-I SWACO MANAGED
mation about the I-BOSS suite of
PARTICLE-SIZE RECOVERY SYSTEM*
(MPSRS) significantly improves the
solutions. Call today.
Wellbore stability viewed by VIRTUAL HYDRAULICS NAVIGATOR
Planning
Before beginning an I-BOSS project, the
M-I SWACO* specialist gathers information about the proposed well and uses
M-I SWACO laboratory equipment,
Stress Field
procedures and software to determine
the exact particulate needed:
Breakout
• OPTI-STRESS* software for designing
particulate-based solutions uses
accepted and recognized predictive
approaches to determine the fracture width for various rocks under
various conditions, concentrations
of particulate to effectively bridge
and seal predicted fracture widths
and the recommended particles
suited to plug various fracture
sizes and provide maximum
strengthening effect
• Laboratory testing equipment
specifically designed for validation
and preplanning include:
– High-pressure matrix loss tester
conditions at hand. The solutions
inclusive as a single-sack additive
can include:
for use when all the technical
• VIRTUAL WELLBORE STABILITY* soft-
data is not available for the
ware identifies potential problems
with wellbore stability
• VIRTUAL HYDRAULICS*, featuring the
NAVIGATOR* downhole visualization
OPTI-STRESS software
– BLOK-R-750*— Proprietary material designed for use in propping
open large fractures
– Low-pressure matrix loss tester
software provides a virtual snapshot
– Fracture tester
of downhole fluid behavior, before
SAFE-CARB* series of sized, graded,
– Cylindrical fracture cell
drilling begins and while the well
ground marble for use with
is in progress.
OPTI-STRESS software
Drilling and monitoring
• Specially formulated loss-prevention
– Sized CaCO3 — The M-I SWACO
• Three types of wellbore-strengthening
Throughout the well-construction
materials:
pills based on advanced chemical
process, M-I SWACO uses proprietary
– G-SEAL PLUS* — Graphitic coke blend
design:
– VINSEAL* — A granular cellulosic
– High-compressive-strength
software, products, testing equipment
and procedures to identify the most
cost-effective solution for your well.
As drilling progresses, real-time sampling, monitoring and adjustments
keep the wellbore-strengthening
process optimized for the drilling
LPM material that is preferentially
oil wet. For use in invert emulsions
as both a proppant and sealant.
– OPTISEAL — Proprietary blend of
Loss-Prevention Material (LPM) all
dewatering pill
– Oil-setting-gel chemistry for
shales and permeable formations
I-BOSS Technology: Success stories from around the world
Offshore Gulf of Mexico
I-BOSS STRATEGY SAVES
OPERATOR $1,950,000
The operating company has adopted
the technique on all wells, having drilled
11 to date. There has been an overall
70% reduction in fluid losses, and up
to 600 psi (41.4 bar) strengthening
has been measured.
Offshore Gulf of Mexico
ON A SINGLE WELL
Mud losses and wellbore stability while
drilling offset wells in this area were identified as major challenges to drilling a sand
section above the salt in this 30,000+ ft
(9,144+ m) well. This 2,600 ft+ (792+ m),
18- x 21-in. interval was drilled with
no mud losses or downtime related
to hole stability.
More than 19,000 ft (5,791 m) were
drilled using 20-mesh screens, which
greatly reduced cost in materials and rig
time. A total cost for the LPM in the sections
that were strengthened was approximately
$700,000. Downhole mud losses in those
sections on previous wells had amounted
to approximately $2,650,000, for a net cost
savings of $1,950,000 in materials alone.
North Sea
Offshore Gulf of Mexico
I-BOSS LPM STRATEGY
SAVES OPERATOR
17,000-BBL FLUID LOSS
After the operator experienced a 14,000-bbl
fluid loss while trying to drill through
depleted sands on a deepwater injector
well, a sidetrack was the next option.
Using a single-LPM approach, the sidetrack
lost an additional 17,000 bbl of fluid; the
sidetrack was plugged and abandoned.
M-I SWACO recommended a blended
LPM (graphite, cellulose and carbonate)
on a second sidetrack. This hole was
drilled, cased and cemented, experiencing
only minimal fluid loss. The operator
reached the objective and was able to
inject at the target rates with no problems.
North Sea
I-BOSS STRATEGY ADOPTED
FOR 11 ADDITIONAL WELLS,
FOLLOWING SUCCESS
A high-risk zone threatened the successful drilling of the 12∏-in. hole section and
the running and cementing of a 97⁄8-in.
liner in this well.
Upon identifying the high-risk zone,
drilling stopped and 50 lb/bbl (142.5 kg/m3)
of LPM was circulated in with only 30-mesh
top screens. Then 50 tons (54.4 metric tons)
of LPM were added for the 2,000-bbl circulating system. The well was drilled to TD
of the 12∏-in. hole section with no losses.
Casing was run and cemented with
full returns to surface.
The M-I SWACO I-BOSS strategy of
inducing and plugging fractures to
strengthen the wellbore got the well
through 7,200 ft (2,194.6 m) of treacherous
formations with no major hole problems.
Fluid losses were held to about 400 bbl vs.
the 6,000-bbl losses experienced on offset
wells. Pulling out of and running in the
hole were trouble free, fluid properties
and hole cleaning remained consistently
good, and torque and stick-slip remained
within limits.
I-BOSS WELLBORE
STRENGTHENING
REDUCES FLUID
LOSSES BY 94%
On this well, the operator expected to lose
more than 6,000 bbl of fluid while drilling
through intermittent overpressured shale
and depleted-sand sections. To stabilize
the shales, a drilling-fluid weight of
11.3 lb/gal (1.36 kg/L) had to be used,
putting the sand sections at risk.
SPECIALIZED ADDITIVERECOVERY SYSTEM SAVES
MONEY, DELIVERS RESULTS
For this operator, it was important to
maintain the proper concentrations of
M-I SWACO G-SEAL* additive, G-SEAL PLUS
graphite/industrial carbon blend and
VINSEAL* fiber in the drilling-fluid system.
With an ordinary solids-control system,
>70% of these necessary additives would
be removed, increasing the cost of operation and drastically reducing the desired
level of fluid-loss prevention.
M-I SWACO recommended the patented1
MANAGED PARTICLE-SIZE RECOVERY SYSTEM
(MPSRS) technology to increase the LostCirculation Material (LCM) percentage in
the drilling fluids. The MPSRS unit was on
location for 40 days and ran continuously
during the 7 days it took to drill the two
intervals. The unit recovered 141,907 lb
(64,368 kg) of material. Laboratory analysis showed that the recovered material
consisted of 55% G-SEAL, G-SEAL PLUS and
45% VINSEAL additives and clay. The
recovery unit also allowed for a much
higher continuous concentration of LCM
in the drilling fluid than would be obtainable without the recovery unit, bringing
the added value of drilling troublesome
formations with the optimal amount
of LCM.
P.O. Box 42842
Houston, Texas 77242-2842
Tel: 281·561·1300
Fax: 281·561·1441
www.miswaco.com
E-mail: questions@miswaco.com
Technology Centers:
HOUSTON, TEXAS
Tel: 281·561·1300 · Fax: 281·561·1441
ABERDEEN, SCOTLAND
Tel: 44·1224·334634 · Fax: 44·1224·334650
STAVANGER, NORWAY
Tel: 47·51·577300 · Fax: 47·51·576503
This information is supplied solely for informational purposes and M-I SWACO makes no
guarantees or warranties, either expressed or implied, with respect to the accuracy and use
of this data. All product warranties and guarantees shall be governed by the Standard Terms
of Sale. Nothing in this document is legal advice or is a substitute for competent legal advice.
©2009 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
1U.S. Patent 7,520,342
NEW DOCUMENT NUMBER TO COME (E) 200 Litho in U.S.A.
luBe-100
LUBE-100* lubricant reduces torque, drag and the potential for differential
sticking by reducing the coefficient of friction of water-base muds.
It can also provide additional wellbore stability and inhibition, reduce bit-balling and improve high-temperature filtration control. LUBE-100
lubricant is only slightly water soluble under most conditions but is readily dispersible in water-base muds. It is acceptable for most
situations specifying a low-toxicity lubricant.
Typical Physical Properties
Physical appearance ............................................................................................................................................................................................... Black liquid
Specific gravity................................................................................................................................................................................................................0.98-1.04
pH .............................................................................................................................................................................................................................................. 8-9.5
Solubility in water ................................................................................................................................................................................................................ Slight
Flash point .............................................................................................................................................................................................. 430° F (221° C) (PMCC)
Applications
LUBE-100 lubricant should be specified for those situations where torque, drag and/or the potential for differential sticking are likely,
such as when drilling highly deviated or high-differential-pressure wells. This additive is especially useful for preventing the "stick-slip”
condition in directional drilling when using the "slide" method without rotation.
Normal concentrations of LUBE-100 lubricant range from 2 to 4% or 7 to 17.5 lb/bbl (20 to 50 kg/m3), depending on the mud density, desired
reduction in coefficient of friction and the mud system. After the initial treatment, periodic treatments should be made to maintain the
desired concentration. Higher concentrations may be needed for pills and special applications. Treatment levels and product usage will
depend on the rate of penetration, solids-control equipment and dilution rates. Due to the potential for an increase in viscosity when
added to lightly-treated, high-bentonite systems or to systems with high solids, heavy treatments of LUBE-100 lubricant should be added
slowly. If high viscosity occurs, circulation time and temperature cycling will restore the fluid to near-original conditions. While LUBE100 lubricant does not affect the rheology of most mud systems, pilot testing is recommended as a precautionary measure for all initial
applications and large treatments.
LUBE-100 lubricant should be added slowly, directly to the mud system wherever there is good agitation or through the mixing hopper.
One suggested application method consists of maintaining a small, constant stream, added directly into the suction pit.
LUBE-100 lubricant does not "grease," is resistant to contamination and is compatible with common water-base mud additives. Because
the product has very low foaming potential, it will not cause foaming problems in the mud system. For offshore applications with Lube100 lubricant concentrations approaching 4%, the LC50 should be monitored closely.
Advantages
■■
Highly effective down hole lubricant for reducing torque and drag
■■
Reduces the potential for, and the severity of, differential sticking
■■
Ideal for minimizing the "stick-slip" condition when "sliding" in directional drilling
■■
Resists contamination and is compatible with other water-base additives
■■
Chemically stable down hole under pressure and at temperatures of more than 450° F (232° C)
■■
Reduces the tendency for bit and stabilizer balling when drilling gumbo clays
■■
Can improve wellbore stability and inhibition, and help obtain more gauge holes
■■
Helps improve high-temperature filtration control
■■
Helps maximize rate of penetration
■■
Environmentally acceptable for offshore use
■■
Does not sheen
Limitations
■■
May cause high viscosity when added to non-dispersed, lightly-treated bentonite or high-solids fluids
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheet (MSDS).
LUBE-100 lubricant is a low toxicity product. For offshore applications with LUBE-100 lubricant concentrations approaching 4%, the LC50
should be closely monitored.
Packaging and Storage
LUBE-100 additive is packaged in 55 gal (208 l) drums and is available in bulk.
Store in a dry, well-ventilated area. Keep container closed. Keep away from heat, sparks and flames. Store away from incompatibles.
Follow safe warehousing practices regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2010 M-I L.L.C. All rights reserved.* Mark of M-I L.L.C.
FPB.1201.1102.R2 (E)
P.O. Box 42842
Houston, Texas 77242-2842
Tel: 281·561·1300
Fax: 281·561·1441
www.miswaco.com
E-mail: questions@miswaco.com
MD-3 Triple-Deck Shale Shaker
More decks. More options. Less space.
E N V I R O N M E N T A L
S O L U T I O N S
Features and Benefits
• Dual modes of elliptical motion:
progressive and balanced1
• Efficiency operating mode for
increased fluid recovery, discard
dryness and screen life
• High-capacity operating mode
for increased capacity and
conveyance rate
• VIBRATORY MOTION DRIVE* in
two modes (6.3 and 7.2 G’s)
produces a drier cuttings
discharge and results in
improved separation efficiency
• VIBRATORY MOTION DRIVE allows
operating modes to be switched
while shaker is in motion
• Fluid distribution designed to
utilize all available screen area,
regardless of drilling conditions
• Modular platform to accommodate a variety of features
• Footprint matches the
M-I SWACO* BEM-650* shaker
• Available in common powersupply configurations to
meet all applicable global
electrical standards
• Deck-adjustment system
capable of adjustment while
processing fluid
• Unique feeder assembly that
presents fluid to the scalping
screens as a uniform, low-impact
curtain. Feeder can be easily configured into a variety of connection points for installations with
limited space.
• Fume-extraction hood reduces
operator exposure to vapors associated with drilling fluids and prevents fluid splashing outside the
shaker boundaries
• Heavy-gauge carbon-steel construction and 316-L stainless steel
on high-wear areas reduces maintenance costs and helps to ensure
long service life
• State-of-the art motion generators
are oilfield proven and require
minimal maintenance
1Patent
pending
• Standard spray bar assists conveyance of heavy and/or sticky
solids on scalping deck during
various formations
• Resists damage caused by
generator voltage fluctuations
Flexibility/Customization Options
• Modular bolting provisions for
installation allow flexible shaker
configurations (mud cleaners,
dual shaker, loss-preventionmaterial recovery for wellborestrengthening applications)
• Inlet and outlet locations can be
configured to exactly match the
BEM-650 shaker, BEM-600* shaker
and other similar-sized shakers
• Feeder can be easily configured
into a variety of connection
points for installations with
limited space
Flow Distribution
• Three effluent ports allow
processed fluid to discharge
through skid rear or sides
Controls
• Remote starting and
monitoring features
• Easy-to-use pneumohydraulic
deck-angle adjustment1 for
reduced mud loss from screens.
Fluid is a water/low-toxicity
antifreeze mixture.
• M-I SWACO can design and supply
customized automation systems
to control and monitor multiple
MD-3 shale shakers and other
related equipment
• Stainless steel electrical control
box is accessible from the typical
operator interface and includes a
remote starting interface
• The pneumatic control, mounted
on the front of the shaker, provides an operator interface to
control the deck-adjustment
and screen-clamping systems
Environmental Protection
• Reduced carbon footprint
• Built to Health/Safety/
Environment (HSE)-driven
specifications
• Front controls, automation options
and fume hood for highest degree
of discharge regulation
• Meets highest standard of
discard dryness
Screen Technology
• Composite screen technology
increases effective open area,
improves process capacity,
and maximizes screen life
• Lightweight screens (<15 lb
[<6.8 kg]) for easier handling
• Integral gasket to withstand fluids
at elevated temperatures
• Compatible with all drilling fluids
• Self-latching for fast and easy
screen changes with no tools
• Pre-tensioned screens allow for
more efficient screen changes
• Front loading for improved
operator safety
• Integral drip lip for proper solids
discharge without contacting
shaker basket
Screen-Clamping System
• Pneumatic actuators rated for
operation at 90 psi (6.2 bar)
and compatible at elevated
temperatures for a variety
of drilling fluids
• Patent-pending screen bed
with sloped bottom to prevent
solids buildup and facilitate
easy cleanup
When expectations are high
and space is tight, this is the only
shale shaker that makes sense
ឣ
A P P L I C A T I O N S
Global drilling projects where more
effective fluids/solids separation is
required and shaker footprint must
be kept to a minimum.
ឣ
P R O B L E M S
Even with rig space at a premium,
maximum solids control is needed
more than ever, particularly in
deepwater where shale formations
present a multitude of drilling and
wellbore-stability challenges.
ឣ
S O L U T I O N S
The M-I SWACO MD-3 shale
shaker provides three decks of
automated, effective solids control
in a small-footprint unit.
ឣ
E C O N O M I C S
Solid engineering and more efficient,
effective solids removal translates to
lower waste volumes and higher feed
rates, increasing project upside and
reducing downtime for shaker repairs.
ឣ
E N V I R O N M E N T A L
By producing drier cuttings and significantly reduced cuttings volumes, the
MD-3 triple-deck shaker reduces your
project’s environmental footprint and
the associated coats.
Changing drilling conditions require
immediate, flexible solids-control
solutions. Environmental requirements demand up-to-the-minute
conformance with ever stricter criteria.
Rig space, especially offshore but
also onshore, is at an all-time premium as more and more technology
crowds the working environment.
The M-I SWACO MD-3 shale shaker
lets you meet all of these challenges
— small footprint, the most effective
solids-control options and the ability
to adapt quickly to changing drilling conditions — with a compact,
high-performance solution.
A high-spec shaker
for high-spec rigs
In addition to meeting the most
stringent criteria for discard dryness,
the MD-3 shale shaker is designed
with many “standard” features that
are considered special-order by
other manufacturers.
We consider the shaker’s flexibility
to meet your project needs the key
to reliability and productivity.
Automation and a fume hood are
standard for high-spec applications
but can be removed to accommodate
“basic” shaker needs. The MD-3
shaker can be configured to process
high volumes of fluid or to recover
Loss-Prevention Material (LPM) in
wellbore-strengthening operations.
For unmatched adaptability, standard MD-3 shaker versions are available to operate with international
power supplies (230, 400, 460, 575
and 690 volts) while meeting regional
hazardous-area specifications (UL, CE,
ATEX and NORSOK).
The front controls have been
designed for operational ease and
safety, while the low operational
noise levels and minimum maintenance requirements further increase
worker safety. The shaker’s footprint
matches the popular M-I SWACO
BEM-650 shaker to simplify retrofitting
into existing shaker houses.
Movement of fluid and cuttings
over all three decks maximizes use
of the screen area for high fluid
capacity. The ability to adjust the
deck angle as conditions change is
just one of many other features that
set the MD-3 shale shaker apart.
Backing up the powerful capabilities
of the M-I SWACO MD-3 shaker is a
global infrastructure that helps you to
get the spare parts, screens and other
solids-removal and waste-handling
technology you require, wherever
your project is located.
Compact shaker, expanded
capability, worldwide solutions
The modular, multi-deck MD-3 shaker
is just one example of the M-I SWACO
approach to understanding and solving your solids-control problems.
Going far beyond the capabilities
of an equipment supplier, we are
problem solvers with a group of
specialists dedicated to increasing
your overall productivity.
For more information about
the MD-3 shaker or any of the
other products and services
within our ENVIRONMENTAL
SOLUTIONS* offerings, contact
your M-I SWACO representative.
Composite, lightweight screen choices with
self-latching mechanism and integrated seal.
Compatible with all drilling fluids.
Two state-of-the-art, oilfield-proven
3.7-HP motion generators with
1,800 rpm maximum speed
Standard configuration has one
scalping deck and two primary
decks. Pre-tensioned, composite
scalping screens have the
following gross screen areas:
• Scalping deck: 25.4 ft2 (2.4 m2)
• Primary decks: 50.8 ft2 (4.7 m2)
Two available modes of operation
with single-switch adjustment:
• 6.3 G’s progressive elliptical
• 7.2 G’s balanced elliptical
Bolting provisions for
installation of multiple-shaker
and mud-cleaner options
Standard unit is ATEX, CE,
NORSOK and UL-rated
Fluid is split into four streams
on top flowback pan and is
directed to primary decks
through four rear ducts
Fume-extraction system doubles
as a splash-retention system
Screen-clamping actuators
designed with continuous
toggle to allow installation
from discharge end of shaker
Standard capabilities,
not just options
Patented deckadjustment system
Deck angle can be adjusted while
processing fluid. Adjustment range:
• Scalping deck: +3 to –1°
• Primary decks: +8 to +4°
We’ve designed the standard MD-3 shale
shaker with the following significant
enhancements, but we do offer options
to enhance onsite performance:
• Dual modes of elliptical motion:
progressive and balanced1
• Efficiency operating mode for
increased fluids recovery, discard
dryness and screen life
• High-capacity operating mode for
increased capacity and conveyance rate
• A scalping deck that can be adjusted
for optimum performance and reduced
installation footprint
• Highest level certifications and
multiple voltage/cycle configurations
• Screen-deck angle can be adjusted
while processing fluid to match
changing drilling conditions
• Unique feeder assembly that presents
fluid to the scalping screens as a
uniform, low-impact curtain
• Screen bed with sloped bottom prevents solids buildup and cleans easily1
• Latest lightweight composite
screen design includes a latching
mechanism to minimize time for
full screen changeouts1
MD-3 Shale Shaker Specifications
25
(64)
1,262
(3,205)
Recommended
screen removal
88.6
(2,249)
20
(51)
12
(32)
69.6
(1,768)
Inspection covers
10 (254)
4 places
37
(940)
Approx.
C of G
70.3
(1,786)
77.4
(1,967)
2.5
Typ
(64)
101.7
(2,584)
Ø 11 (27)
6 places
Motion
generators
Enclosure, pilot box
UL/ATEX rated
Pneumatic controls,
deck adjustment
and screen clamping
Deck angle
indicator
(2 places)
Switch disconnect,
20A, UL/ATEX rated
Ø 15 (38) Typ
Shaker shipping
bracket (4 places)
Lifting lugs
(4 places)
Starter assembly, 2-motor,
explosion-proof, UL/ATEX rated
30.3
(770)
Fume extraction
67.7
(1,720)
Approx.
overall
height at
32.9
0°
(835)
Approx.
C of G
60.2
(1,530)
45.4
(1,154)
Weir
height
64.7
(1,644)
51.5
(1,308)
Approx.
inlet
13.8 (351)
24.4
(621)
A
43.3
(1,099)
29.8
(756)
33.6 (854)
Approx.
C of G
56.2
(1,427) 88.2
(2,240)
Discharge gate
(4 required)
29.8
(756)
92.6
(2,351)
These renderings are for information purposes only
and are not actual schematics.
A
Hydraulic
reservoir
(anti-freeze/
water)
Optional
rear discharge
55.8
(1,416)
74.6
(1,895)
37.3
(948)
Dimensions
• Length
• Width
• Height
• Weight
101.7 in.
77.4 in.
67.7 in.
6,450 lb
• Screen type:
Scalping deck: Pre-tensioned composite
Primary decks: Pre-tensioned composite
• Screen clamping:
Scalping deck: Pneumatic
Primary decks: Pneumatic
• Vibrating basket: Carbon steel
(2,584 mm)
(1,967 mm)
(1,720 mm)
(2,926 kg)
• Screen Deck and Screens
• Gross screen area:
Scalping deck: 25.4 ft2 (2.4 m2)
Primary decks: 50.8 ft2 (4.7 m2)
• Net (API) surface area:
Scalping deck: 15.8 ft2 (1.5 m2)
Primary decks: 31.7 ft2 (2.9 m2)
• Deck-adjustment system:
Scalping deck: +3° to –1°
Primary decks: +8° to +4°
Motion Generator Specifications
• Two (2) vibrator motors
• 460V (220 to 690V available)
• ATEX, CE, NORSOK and UL-rated
• Motor weight: 550 lb (249 kg) each
MD-3 Shale Shaker VIBRATORY MOTION DRIVE
Motion maps of capacity mode (7.2 G’s, balanced elliptical)
Direction of flow
Motion maps of efficiency mode (6.3 G’s, unbalanced elliptical)
P.O. Box 42842
Houston, Texas 77242-2842
Tel: 281·561·1300
Fax: 281·561·1441
www.miswaco.com
E-mail: questions@miswaco.com
Technology Centers:
HOUSTON, TEXAS
Tel: 281·561·1300 · Fax: 281·561·1441
ABERDEEN, SCOTLAND
Tel: 44·1224·334634 · Fax: 44·1224·334650
STAVANGER, NORWAY
Tel: 47·51·577300 · Fax: 47·51·576503
This information is supplied solely for informational purposes and M-I SWACO makes no
guarantees or warranties, either expressed or implied, with respect to the accuracy and use
of this data. All product warranties and guarantees shall be governed by the Standard Terms
of Sale. Nothing in this document is legal advice or is a substitute for competent legal advice.
©2009 M-I L.L.C. All rights reserved.*Mark of M-I L.L.C.
DBR.1311.0904.R1 (E) 2.5M Litho in U.S.A.
m-i Cedar FiBer
M-I CEDAR FIBER* cellulose is shredded cedar wood used to prevent and/or
regain lost circulation.
M-I CEDAR FIBER additive has a fibrous shape, and is an effective material for regaining circulation when seepage or major loss zones are
encountered. It may be used as a preventative additive if losses are anticipated. M-I CEDAR FIBER material can be used to treat the entire
system or used in concentrated slugs or batches.
Typical Physical Properties
Physical appearance ............................................................................................................................................................................................ Brown fiber
Specific gravity ...................................................................................................................................................................................................................... 0.60
Solubility (in water) ..................................................................................................................................................................................................... Insoluble
Bulk density .............................................................................................................................................................................................. 18.8 lb/ft3 (301 kg/m3)
Applications
Additions of M-I CEDAR FIBER product will help to prevent lost circulation when added before entering a thief zone. If seepage or severe
losses occur, the use of M-I CEDAR FIBER fluid-loss-control product will help to regain full returns.
M-I CEDAR FIBER product should be used with various sizes of granular and flake material to provide a wide variation in particle shape
when loss circulation is M-I CEDAR FIBER lost circulation- control product may be used to treat the whole system or spotted as a pill across
the loss zone. It also can be used in high fluid-loss slurries or squeezes.
Suggested treating levels for minor losses are from 2 to 10 lb/bbl (6.0 to 28.0 kg/m3), and 5 to 25 lb/bbl (8.6 to 71.3 kg/m3) for losses
requiring higher concentrations.
M-I CEDAR FIBER lost-circulation-control material can be added directly through the hopper in situations where good agitation is available.
Advantages
■■
Effective fibrous lost circulation additive
■■
May be used for seepage or moderate-to-severe losses
Limitations
■■
Only one size available
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions as described on the Material Safety Data
Sheet (MSDS).
Packaging and Storage
M-I CEDAR FIBER product is packaged in 50 lb (22.7 kg) multiwall, paper sacks.
Store at moderate temperatures in a dry, well-ventilated area. Keep in original container
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.1307.1104.R1 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
m-i-X II
M-I-X II* cellulose fiber is a superior plugging agent used to bridge and
seal permeable formations in water-, oil- or synthetic-base mud systems.
Bridging and sealing permeable formations reduces the differential-pressure sticking tendencies which can cause high torque and
drag or stuck pipe. The product is particularly useful for preventing differentially-stuck pipe when drilling depleted zones where high
differential pressures exist. For added flexibility, M-I-X II fiber is available in fine (original), medium and coarse grades so that the
optimum particle size can be selected to bridge the pores and pore throats of permeable formations. M-I-X II fiber additions have
minimal effect on mud properties.
Typical Physical Properties
Physical appearance ................................................................................................................................................................... Tan to light-brown powder
Bulk density .................................................................................................................................................................................... 22-32 lb/ft3 (352-513 kg/m3)
GrindSize
Fine
Medium
Coarse
Finer than 8 mesh
-
-
>95%
Finer than 50 mesh
-
> 80%
-
Finer than 100 mesh
> 90%
< 60%
< 15%
Median (microns)
44-74
104-149
420-840
Applications
M-I-X II fiber is a superior bridging agent, field-proven to be highly effective when drilling high-permeability/ high-porosity zones
with high differential pressures. Each grind size has a specially selected particle size distribution optimized to seal a wide range of
formations.
M-I-X II fiber is designed to bridge and seal permeable formations, reducing the possibility of stuck pipe, controlling lost circulation and
providing filtration control. It is compatible with water-, oil- and synthetic-base mud systems.
The recommended treatment is 5 to 10 lb/bbl (14 to 29 kg/m3) to reduce differential sticking tendencies. After initial treatment, periodic
treatments should be used to maintain the desired concentration. Significant quantities of the medium and coarse grades will be
removed by fine- mesh shale shaker screens (100 mesh or finer).
Fine-grade M-I-X II fiber is recommended for most applications due to its special particle size distribution. Very high-permeability
formations, such as fractured carbonates and conglomerate zones, can require the medium or coarse products.
For see page losses, normal treatments are from 10 to 20 lb/bbl (29 to 57 kg/m3). Concentrations in the 20 to 35 lb/bbl (57 to 100 kg/m3)
range are recommended for more severe lost circulation. Pilot testing is recommended before adding high concentrations because the
material absorbs a small quantity of liquid when added to the mud system.
Applications (cont’d)
M-I-X II fiber should be added to the mud system through a mixing hopper into a pit with good agitation, such as the suction pit. It is
a one-sack product and does not require any additional additives. It is most effective when maintained at the desired concentration
throughout the circulating system. However, treatment methods such as frequent periodic additions, sweeps, batch- or slug-treatments
and pills have all been used successfully.
M-I-X II fiber is compatible with all mud systems and can be used in combination with other lost-circulation materials, including NUT
PLUG, mica, sized calcium carbonate, gilsonite, etc.
M-I-X II fiber residue can be partially removed using standard treatments such as hydrochloric acid or alkaline hypochlorite solutions.
M-I-X II fiber is more than 55% acid soluble in 15% HCl at 212° F (100° C).
Advantages
■■
Effective bridging and sealing agent for a wide range of formations
■■
Offers unique particle sizes smaller than conventional lost-circulation materials yet larger than the solids found in most mud systems
■■
Available in fine (original), medium and coarse grades, allowing the most appropriate particle sizes to be used
■■
Inert material with minimum effect on mud properties
■■
One-sack product with no other additive requirements
■■
Compatible with all mud systems and other lost-circulation materials
■■
Easily mixed and dispersed into the mud system
■■
Easily passes through most shaker screens
Limitations
■■
Can be removed from the circulating system by shale shakers and solids-control equipment, especially when using the medium and
coarse grades with fine-mesh screens (<100 mesh), which requires close monitoring of shale shakers
■■
Biodegradable and can be subject to bacterial degradation. If fermentation is indicated, a biocide should be used at the recommended
maximum treatment level
■■
Absorbs a small quantity of liquid when added to a mud system and can elevate flow properties when used at very high
concentrations
■■
Treatments with additional wetting agent may be required in low stability or lightly treated oil-base muds because of the high surface
area of this slightly absorbing material
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheet (MSDS).
Dust can form an explosive mixture in the air. Keep away from open flames or other sources of ignition.
Packaging and Storage
MIX II fiber is packaged in 25 lb (11.4 kg), multi-wall, paper sacks).
Store in a dry, well-ventilated area. Keep container closed. Store away from incompatibles. Follow safe warehousing practices
regarding palletizing, banding, shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2007 M-I L.L.C. All rights reserved.*Mark of M-I L.L.C.
FPB.1312.0701.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.com
E-mail: questions@miswaco.com
miCa
MICA* is a soft potassium aluminium silicate mineral graded into fine,
medium and coarse size ranges.
MICA is used for regaining lost circulation. Fine grade is used extensively as a preventative measure against loss of circulation. It will
pass through a 20 mesh shaker screen.
Typical Physical Properties
Physical appearance ................................................................................................................................................... Grey - white - silver lustrous flakes
Specific gravity......................................................................................................................................................................................................................... 2.9
Solubility......................................................................................................................................................................................................... Insoluble in water
Bulk density ......................................................................................................................................................................................................... 700 - 900 kg/m3
Applications
MICA is chemically inert in any drilling fluid systems and is unaffected by crude oils, acids or brines.
There are 3 grades of MICA; MICA FINE , MICA MEDIUM AND MICA COARSE.
The particle size for each grade are as follows:
Grade Size
Fine
Medium
Coarse
Particle Size
< 2.36 mm - 100 %
< 3.0 mm -100%
< 4.75 mm - 100 %
Particle Size
1.0 mm - 92 %
2.36 mm - 90 %
2.36 mm - 96.6 %
Particle Size
0.5 mm - 49.4%
1 .0 mm - 55 %
1.0 mm - 55.9 %
Particle Size
-
0.5 mm - 20 %
0.5 mm - 14.7%
MICA FINE may be added to the drilling fluid system as a preventative measure and will not adversely affect the drilling fluid.
Fine grade can be added up to a rate of 11.0 to 17.0 kg/m3 (3.85 to 6 lb/bbl) when a porous zone is anticipate. Medium and coarse grades
are used singularly or in combination with other lost circulation materials when severe lost circulation occurs.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2007 M-I L.L.C. All rights reserved.*Mark of M-I L.L.C.
FPB.1316.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.com
E-mail: questions@miswaco.com
nuT Plug
ADVANTAGES
■■
Inert additive, compatible in all types
and densities of fluids
■■
Will not ferment
■■
Unaffected by pH or temperature
■■
Based on particle shape, size, and
compressive strength, it is a superior
lost circulation additive
LIMITATIONS
■■
■■
Larger-sized shale-shaker screens are
needed to retain the material in the
system
When using large concentrations in
non-aqueous fluids, increased
amounts of wetting agent may be
needed
NUT PLUG* cellulose comprises ground walnut
or pecan hulls and is used as a treatment for
lost circulation.
NUT PLUG material is available in fine, medium, and coarse particle sizes, and may
be used in all types and densities of fluid systems. NUT PLUG may be also used as a
granular-type lubricant to reduce torque and drag
Typical Physical Properties
Physical appearance .................................................................................Tan to brown granules
Specific gravity.......................................................................................................................1.2 – 1.4
Solubility in water ............................................................................................................... Insoluble
Bulk density ......................................................................................36 – 40 lb/ft3 (580 – 640 kg/m3)
Grade
Median Particle Size
d50 (μm)**
Recommended Test Procedure
Fine
400 - 500
Dry sieve analysis
Medium
1400 - 1600
Dry sieve analysis
Coarse
1500 - 2000
Dry sieve analysis
Applications
NUT PLUG cellulose is an effective lost circulation treating material.
NUT PLUG hulls possess high compressive strength. They are available from two
sources: pecan and walnut with walnut hulls being the stronger of the two.
Treatment levels depend on the severity of the losses and type of formation where the
losses occur. Typical preventative treatment levels are 2 to 5 lb/bbl (6 to 14 kg/m3) for
moderate losses and 5 to 25 lb/bbl (14 to 71 kg/m3) for more severe losses. It may be
used to treat the entire system or added as a high-concentration pill. NUT PLUG has a
granular shape, and can be used in a blend of various sizes (fine, medium, and coarse)
to prevent lost circulation or regain returns once losses begin. It also may be mixed
with particulates of other shapes and sizes to provide a wide variation in particle
properties for optimum control.
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications (Cont)
NUT PLUG can be added to other special slurries, such as high-fluid-loss squeezes, to
assist in forming string bridging plugs.
NUT PLUG also can be used to reduce the coefficient of friction (CoF).
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions as described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
NUT PLUG is packaged in 50-lb (22.7-kg), multi-wall, paper sacks.
Store in a dry location away from sources of heat or ignition, and minimize dust.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.1490.1103.R2 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
oPTiSeal i, ii, iii & iV
ADVANTAGES
■■
“One-sack blends” of specifically
sized WSM for a wide range of
formations and severity of losses
■■
Consistency of grind size, composition
and physical properties
■■
Essentially inert materials, that have a
minimum effect on fluid properties and
compatible with all mud systems
■■
Hard, tough granular materials resist
degradation of particle size
THE OPTISEAL* product family consists of four
blends of Lost Circulation Materials that can
function as Wellbore Strengthening Materials
(WSM).
The four WSM blends are designed to plug fracture apertures up to at least 1,200 μm,
as well as provide fluid-loss control in moderate-to-high-permeability formations.
Laboratory testing has confirmed fracture sealing and fluid-loss-control performance.
Typical Physical Properties
Physical appearance ..................................................................................... White to gray or tan
LIMITATIONS
■■
■■
■■
■■
Bypassed shaker screens or screens
with larger openings allow drill
cuttings to remain in circulation,
resulting in higher fluid rheology, wear
on pump liners, and wear on LWD
tools and risk of plugging LWD tools.
Continuous additions can generate
large volumes of waste material and
more inventories required on the
rigsite.
Non-acid-soluble material in the
OPTISEAL I, II and III blends may not be
suited for openhole completions
where acid treatment is required.
The OPTISEAL I blend is not
recommended for use in operations
where WSM recovered from the
shaker screens is milled and
re-injected with slop and cuttings.
Components of the OPTISEAL I blend
can cause clogging of the cyclones
used to mill/crush the solids.
Specific gravity....................................................................................................................... 1.6 - 2.8
Solubility in water @ 68° F (20° C) ................................................................................... Insoluble
Nominal Median Particle Size (d50)** ...................................................................... 500 – 600 µm
OptiSeal I
OPTISEAL II
OPTISEAL III
Graphitic
material
Graphitic
material
Graphitic
material
Ground Nut Shells
Sized Marble
Sized Marble &
Cellulosic Material
OPTISEAL IV
Sized Marble
Applications
The OPTISEAL blends I, II, III and IV are designed as fracture sealing and Wellbore
Strengthening Materials (WSM) for porous and fractured formations while drilling
with either aqueous or non-aqueous fluids. The OptiSeal I and II blends are designed
specifically for water-based mud applications. The OPTISEAL III blend is designed for
Non-Aqueous Fluid (NAF) applications. The OPTISEAL IV blend comprises acid-soluble
marble for use in reservoir drill-influids. All four blends are designed for loss zones with
maximum openings of at least 1,200 µm and can effectively reduce the potential for
differential sticking, lost circulation and torque and drag through improved sealing of
problem zones.
** Nominal Median Particle Size (d50) is reported as a size range due to variations in the
manufacturing and grinding process. If a precise size distribution of a product is critical to a drilling
operation, it should be measured via Dry Sieve Analysis using samples that are representative of
those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications (Cont)
OPTISEAL treatments can be applied to stop losses using squeeze treatments, or spot
applications. To prevent losses, OPTISEAL can be added continuously to the circulating
drilling fluid or through regular, repetitive sweeps. The former constitutes the majority
of cases where lost circulation has occurred; the latter can be deployed when drilling
through a formation with a known history of losses.
Remedial Lost Circulation Treatments: The basis of design for the treatment is a lowfluid-loss Wellbore Strengthening Material (WSM) formulation. The four OPTISEAL
formulations are designed to plug fracture widths up to at least 1,200 μm in addition to
providing good fluid-loss control in moderate-to-high-permeability formations. Particle
Size Distribution (PSD) for the OPTISEAL formulations is based on laboratory fracture
sealing tests. The blends can be slurrified at the rigsite from sacks/big bags. An
alternative is to pre-mix the WSM at a liquid mud plant in a high-volume, high-density
slurry before shipping to a rig. The WSM slurry uses the same base fluid as the drilling
fluid but is unweighted. The slurry provides greater flexibility, improved logistics and
reduced hazards associated with sacked materials. Typical final concentrations
range from 30 – 70 lb/bbl (85 – 200 kg/m3) depending on severity of losses.
Preventative Treatments: The basis of design for the treatment is continuous particle
addition to the circulating drilling fluid when drilling a formation known to have losses.
The main challenge is to maintain a required PSD and concentration in the drilling fluid.
This may be measured at the rigsite using Wet Sieve Analysis or Laser Reflectance.
Typical concentrations range from 12 to 20 lb/bbl (35 – 57 kg/m3). The method of
treatment will depend on length of interval to be drilled:
• When drilling short intervals, the WSM is added to the active pit or spotted at the bit.
When drilling ahead, the shaker screens are either bypassed entirely or all but the
top screens are removed. This allows the WSM to be directly recycled and retained
in the drilling fluid. Another option is to utilize a MANAGED PARTICLE SIZE RECOVERY SYSTEM*
(MPSRS) to recover the WSM while discarding drilled cuttings and fines.
• When drilling extended intervals (> 300 ft or 91.4 m), it is recommended to use a
MPSRS or MD-3 (triple deck) shaker to recover the WSM. By managing the particles
in circulation, the rheology of the fluid is more easily controlled, resulting in improved
Equivalent Circulating Density (ESD) management.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
The OPTISEAL I, II, III and IV additives are packaged in 55-lb (25-kg) multi-wall, paper sacks.
Store in a dry, well-ventilated area. Keep container closed. Store away from
incompatibles. Follow safe warehousing practices regarding palletizing, banding,
shrink-wrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.1502.1103.R3 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
PolySwell
POLYSWELL* copolymer is used in lost circulation and expands to 200 times
its volume in freshwater.
This material is environmentally safe.
Typical Physical Properties
Physical appearance ......................................................................................................................................................................................... White powder
Specific gravity ..................................................................................................................................................................................................................0.8–1.0
Solubility.................................................................................................................................................................................... Swells on contact with water
Applications
POLYSWELL copolymer is used to fill or seal fractures. As the material fully hydrates the fracture/void is sealed. This product can also be
spotted in caving zones to reduce caving problems.
Directly after placing the POLYSWELL pill, pull up above the problem zone to prevent sticking. Full hydration occurs in 20 to 30 min. Circulate
with mud and lost-circulation material (LCM) to fill the bridge.
Advantages
■■
POLYSWELL copolymer can be prehydrated before adding
■■
Because of its swelling capacity and variability in size, POLYSWELL additive can accumulate in a variety of fracture sizes
Method of Addition
POLYSWELL additive can be mixed in water or drilling mud with or without LCM. Add 1 to 3 lb (0.5 to 1.5 kg) per 4 gal (20 L) of water or mud
in a pail. (Lesser and greater amounts have been used.) Pump the mixture as soon as possible once the dry polymer beads are mixed.
When using POLYSWELL additive in core drilling, be sure the core tube has been pulled before pumping the solution downhole. Repeat as
necessary to stop fluid loss.
Limitations
Improper placement of the POLYSWELL additive can result in stuck drill rods.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheets (MSDS).
Packaging and Storage
POLYSWELL copolymer is packaged in 5 gal (18.9 l) buckets.
Store in a dry location away from sources of heat or ignition.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
HPB.1605.0706.R3 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
SaFe-CarB
ADVANTAGES
■■
Acid-soluble, product which minimizes
formation damage
■■
Effective bridging agent
■■
Numerical suffix provides a simple
method of identifying the approximate
d50 of the material
■■
High-hardness, ground marble resists
particle-size degradation
■■
Essentially chemically inert and has
minimum effect on fluid properties
■■
Finer grades such as SAFE-CARB 2, 10
and 20 will pass through most finemesh shaker screens
SAFE-CARB* ground marble is a high-purity, acidsoluble, calcium carbonate used as a bridging
and weighting agent in drilling, drill-in and
workover/completion fluids.
SAFE-CARB usually is preferred over limestone since it generally is harder and purer
than limestone. Its higher purity provides nearly complete acid solubility. SAFE-CARB is
available in eight standard grind sizes: SAFE-CARB 2, 10, 20, 40, 250, 500, 600 and 750, and
special grind sizes of 1400 and 2500.
Typical Physical Properties
Physical appearance ................................................................................................White powder
Specific gravity.........................................................................................................................2.7–2.8
Solubility in water @ 212° F (100° C) ....................................................................0.0035 g/100 ml
Solubility in 15% HCl @ 76° F (24.4° C) .................................................................................. ≥ 98%
Product Name*
Median Particle Size
d50 (μm)**
Recommended Test Procedure
Laser light scattering
SAFE-CARB 2
1-4
SAFE-CARB 10
6 - 15
Laser light scattering
SAFE-CARB 20
16 - 29
Laser light scattering
SAFE-CARB 40
31 - 48
Laser light scattering
SAFE-CARB 250
225 - 300
Dry sieve analysis
SAFE-CARB 500
430 - 520
Dry sieve analysis
SAFE-CARB 600
550 - 650
Dry sieve analysis
SAFE-CARB 750
655 - 800
Dry sieve analysis
SAFE-CARB 1400
1200 - 1550
Dry sieve analysis
SAFE-CARB 2500
2300 - 2700
Dry sieve analysis
Applications
SAFE-CARB additives are acid-soluble calcium carbonate bridging and weighting agents
used to control fluid loss, lost circulation and density. They can be used in almost any
aqueous or non-aqueous drilling fluid, as well as the FLOPRO* NT, FAZEPRO*, VERSAPRO* and
DIPRO* reservoir drilling fluids, and workover and completion fluids. They also are used
in SEAL-N-PEEL* applications to seal the inside of sand-control completion assemblies.
SAFE-CARB 2 to SAFE-CARB 40 are the grind sizes normally used for fluid loss control and to
minimize
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and grinding
process. If a precise size distribution of a product is critical to a drilling operation, it should be measured with the
appropriate Recommended Test Procedure using samples that are representative of those expected to be used in
that operation. Nominal d10 and d90 values are available from Houston Technical Services upon request.
Applications (Cont)
seepage losses (< 10 bbl/hr or 1.6 m3/hr of whole fluid). Typically, the products are
used as blends to treat the entire drilling fluid at a total concentration of 10 to 50 lb/
bbl (29 to 143 kg/m³). The M-I SWACO OPTIBRIDGE* proprietary engineering software is
recommended for selecting the optimum blend of SAFE-CARB products to minimize lost
circulation in permeable or naturally fractured formations.
The amount of SAFE-CARB required to increase the mud density can be calculated as follows:
SAFE-CARB, lb/bbl =
980 x (w2 - w1)
23.3 - w2
where:
w1 = Initial mud weight in lb/gal
w2 = Desired mud weight in lb/gal
SAFE-CARB, kg/m3 =
2800 x (w2 - w1)
2.8 - w2
where:
w1 = Initial mud weight as specific gravity
w2 = Desired mud weight as specific gravity
SAFE-CARB 250 to SAFE-CARB 2500 grind sizes generally are used in lost circulation
situations requiring larger particle sizes. They often are used in lost circulation and
SEAL-N PEEL fluid loss pills at concentrations of 30 to 100 lb/bbl (86 to 285 kg/m³) to bridge
highly permeable zones, fractured zones and completions. In addition they may be used
to treat the entire circulating system to prevent losses; in that case, treatment levels in
the whole mud can range from 5 to 50 lb/bbl. Outside the reservoir, other lost circulation
materials may be used with the SAFE-CARB products to provide tighter seals.
SAFE-CARB products also can be added periodically for seepage control to limit losses
(lost circulation and leak-off) to high-permeability formations. They especially are
effective when drilling with high differential pressures caused by an overbalanced
condition or when drilling depleted zones. Treatments range from 2 to 10 sacks per hour
when used for prevention of lost circulation. For sealing depleted zones or induced
fractures, SAFE-CARB is most effective when used in combination with G-SEAL*, G-SEAL
PLUS or G-SEAL PLUS COARSE additives.
Additions of SAFE-CARB products to an oil- or synthetic-based drilling fluid system may
also require additional oil-wetting agent.
Toxicity and Handling
Bioassay information is available upon request.
No claim of personal safety is intended nor implied by the use of the name “SAFE” in this
product. Handle as an industrial chemical, wearing protective equipment and observing
the precautions as described in the Material Safety Data Sheet (MSDS).
Packaging and Storage
SAFE-CARB 2, 10, 20, 40, 250, 500, 600, 750, 1400 and 2500 additives are packaged in 50 -lb
(22.7 kg), 25 kg (55 lb) and 50-kg (110-lb) multi-wall, paper sacks.
Store in dry, well-ventilated area. Keep container closed. Store away from
incompatibles. Follow safe warehousing practices regarding palletizing, banding, shrinkwrapping and/or stacking.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.1900.1103.R3 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com
SaFe-link
SAFE-LINK* fluid-loss-control product comprises a chemically modified,
crosslinked cellulose polymer used primarily to control loss of clear brine
fluid to the formation during completion or workover operations.
SAFE-LINK additive controls fluid loss by applying a very viscous material across the formation face, virtually stopping the flow of brine into
the formation. SAFE-LINK fluid- loss-control additive functions through a crosslinked polymer network that is held in place on the formation
face. The effectiveness of this product is not dependent on bridging solids or on viscous drag within the formation matrix.
Typical Physical Properties
Physical appearance .................................................................................................................................................................................. Viscous, tan liquid
Odor .......................................................................................................................................................................................................................... Faint solvent
Specific gravity ........................................................................................................................................................................................................................1.32
pH ................................................................................................................................................................................................................................................~10
Pour point ......................................................................................................................................................................................................... < 10° F (–12.2° C)
Viscosity .......................................................................................................................................................................................................................> 10,000 cP
Applications
SAFE-LINK fluid-loss-control additive is designed to work in non-zinc, halide brines such as CaCl2, CaBr2, NaCl, seawater, NaBr, and KCl,
ranging from 8.6 to 15.1 lb/gal (1030 to 1809 kg/m3) to control wholesale loss of brine to the formation. Generally, SAFE-LINK fluid-losscontrol additive is stable to 250° F (121° C) for at least 48 hours exposure time. Due to the SAFE-LINK additive’s crosslinking mechanism,
differential pressure greater than 2,000 psi is not advisable.
Based on recommended treatment levels and recommended use, the fluid loss to moderately permeable formations (100 to 1000 mD) can
be reduced to < 2 bbl/day per 30 ft (9.1 m) interval.
Mixing Instructions - For a 60 ft, 7.5 in. (18.3 m, 19 cm) perforated interval, mix a 10 bbl pill as follows:
1. Add 2.5 to 3.5 lb/bbl (7.1 to 10.0 kg/m3) SAFE-VIS additive or 3 to 4 gal/bbl (0.071 to 0.095 m3/m3) SAFE-VIS HDE additive to viscosify 260 gal
of brine.
2. Select the density of the viscosified brine prior to the addition of the SAFE-LINK additive so that the total pill density will be correct for
the target application.
3. Add 32 pails of SAFE-LINK additive (the contents of one standard pallet). Stir gently with a lightning mixer or paddle mixer to slurry the
SAFE-LINK additive into the viscosified brine. Do not over-shear the slurry; the slurry should be lumpy or stringy when pumped.
A 10 bbl pill is the minimum recommended treatment. For shorter intervals, use the same treatment. For longer intervals, use a
treatment of 0.5 pail per perforated foot (0.3 m). For variation in pipe diameter, increase or decrease the number of pails and pill volume
as appropriate.
Advantages
■■
Premixed liquid
■■
No special mixing equipment requirements
■■
Good to 250° F (121° C)
■■
Can be used at differential pressures up to 2000 psi
■■
Clean up with dilute acid
Limitations
■■
Not designed for higher temperatures than 250° F (121° C)
■■
For less severe fluid-loss applications, a SAFE-VIS* (i.e., un-crosslinked) pill may suffice
■■
For more severe fluid-loss applications, even a SAFE-LINK pill may not be sufficient, and the user may have to resort to a solids-laden
(sized-carbonate) pill
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions as described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
SAFE-LINK fluid-loss-control additive is packaged in 5 gal (18.9 l) pails.
Store in dry, well-ventilated area. Keep container closed. Keep away from heat, sparks and flames. Store away from incompatibles
This document is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale.
©2004 M-I L.L.C. All rights reserved. * Mark of M-I L.L.C.
CPB.1926.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
E-mail: questions@miswaco.slb.com
Inter-Office Correspondence
To:
From:
Copy To:
Doc. ID:
Neal Smothers
Date:
Wray Curtis
Subject:
Jim Friedheim
Fred Growcock
PA20001016.009WC
19 October 2000
Pelletized lost circulation material
for use in synthetic-based drilling
fluid.
In a previous study, preparation of a viable pelletized lost circulation material for water-based
mud was shown to be feasible. The resulting product, manufactured by Grinding and Sizing Co.,
was found to be readily dispersible in the fluid, and it was used sucessfully in the field.
Pelletized LCM was also prepared for use in non-aqueous fluids, but its dispersion in a typical
SBM fell short of expectations. In the study described below, another pelletized LCM for SBM
was created, this time with 5% NOVAWET as binder; this new product was found to be readily
dispersible in an SBM.
Test Objective
To determine how well the pellets disperse in a 14.0 ppg SBM and to monitor any changes in the
Electrical Stability of the mud.
Results
All three of the pellet formulations dispersed well after mixing 10 minutes at 4000 rpm on a
Hamilton Beach mixer. Each formulation exhibited some reduction in Electrical Stabilty.
Samples
•
•
NOVAPLUS field mud from well OCS-G-18189 #1: the density was cut-back from 16.35
ppg to 13.94 ppg using a 50/50 blend of IO C16-18 and BIO-BASE 560 base fluids. The
resulting rheological properties follow in the Test Data section.
Three types of LCM pellets in Ziploc bags:
1) Dated 10-4-00; 65% G-SEAL, 30% M-I-X II (Med), 5% NOVAWET
Assigned Lab Master Number – 20003199.
2) Dated 10-5-00; Seepage I – Synthetic, 5% NOVAWET
Assigned Lab Master Number – 20003199-01.
3) Dated 10-10-00; Seepage II – Synthetic, 5% NOVAWET
Assigned Lab Master Number – 20003199-02.
PA20001016.009WC
Page 1 of 3
Test Data
Standard Properties of Base Mud:
Rheology Temp., °F
Density, ppg
Cut-Back Field Mud
150
13.94
600 rpm
300 rpm
200 rpm
100 rpm
6 rpm
3 rpm
35
20
14
9
3
3
PV, cP
YP, lb/100ft2
15
5
10-Sec Gel, lb/100ft2
10-MinGel, lb/100ft2
6
10
Elec. Stability, V
721
Dynamic Dispersion Test:
One barrel equivalent samples of the cut-back field mud were weighed into 1-Qt glass jars. The
initial Electrical Stability of the mud was determined at 69.5°F (room temperature) to be 719
volts. Each sample was stirred at 4000 rpm on a Hamilton Beach mixer. The LCM pellet
concentration was 35 ppb and mixing time was 10 minutes. After mixing was completed, the
Electrical Stability was determined. The mud sample was then poured over a 20-mesh sieve and
Dispersion percentages were estimated by visual observation.
1) G-SEAL / M-I-X II (M); ES = 358 volts. The pellets were 100% dispersed, with the
sample passing completely through the 20-mesh sieve.
2) Seepage I; ES = 648 volts. The pellets were approximately 99% dispersed. The 1%
remaining on the sieve were highly eroded pieces that crumbled easily when probed
with a spatula.
PA20001016.009WC
Page 2 of 3
3) Seepage II; ES = 572 volts. The pellets were approximately 98% dispersed. The 2%
remaining on the sieve consisted of half very small, highly eroded pieces and half
very small, but less eroded pieces. All of the pieces crumbled easily when probed
with a spatula.
Another one barrel-equivalent sample of the cut-back field mud was stirred on a Hamilton Beach
mixer at 4000 rpm and treated with 35 ppb conventional LCM consisting of 14 ppb M-I-X II (F),
14 ppb M-I-X II (M) and 7 ppb M-I-X II (C). After mixing 10 minutes the Electrical Stability
was determined to be 638 volts.
Conclusions
The lost circulation material pellets specially prepared for synthetic-based drilling fluid appear to
disperse well under laboratory conditions with only a nominal effect on the Electrical Stability.
It is anticipated that the pellets will perform even better under wellsite conditions, where shear
and mixing energy and significantly greater.
PA20001016.009WC
Page 3 of 3
VerSaPaC
VERSAPAC* rheological additive is a highly efficient thermally activated
organic thixotrope.
A unique 100% active, powdered material, VERSAPAC develops a high level of thixotropy in the VERSADRIL, VERSACLEAN and NOVAPLUS oil- and
synthetic-base fluid systems.
Typical Physical Properties
Physical appearance .............................................................................................................................................Finely divided, cream-colored powder
Bulk density .......................................................................................................................................................................................................................1 g/cm3
Composition ...........................................................................................................................................................................................100% organic polymer
Applications
VERSAPAC is a 100% organic polymer that allows for easy incorporation into an active invert emulsion system without adversely affecting
the rheological properties until thermally activated. Its primary applications are as an annular casing pack and barrier fluid.
VERSAPAC should be introduced to the active mud system through a conventional mixing hopper. Full activation is achieved when the
treated fluid is pumped into the well where downhole temperatures will activate the product on demand.
Alternatively, VERSAPAC-treated fluids can be processed by medium to high shear equipment. Activation temperature is typically in the
120 to 150° F (49 to 66° C) range. This processing temperature range, normally reached by using medium to high- shear equipment, is
sufficient to fully build VERSAPAC’s rheology. For effective thixotropic development, typical levels range from 0.5 to 25 lb/bbl (1.4 to 14 kg/m3).
Pilot testing is suggested to determine the optimum loading level for any given system.
Advantages
■■
Thermally activated gelling agent that can be added directly to oil and synthetic-base systems
■■
Requires no new fluid and only a small treatment to the existing mud system
■■
Maximum formation stability, using oil-base mud as the annular fluid
■■
Minimal viscosity increases until temperature is applied
■■
Minimum impact on ECD and pumping requirements
■■
Gelled fluid column remains able to transmit hydrostatic pressure
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the precautions described in the Material Safety Data
Sheet (MSDS).
Packaging and Storage
VERSAPAC is packaged in 33-lb (15-kg) sacks.
This document is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2007 M-I L.L.C. All rights reserved. * Mark of M-I L.L.C.
FPB.2209.1104.R1 (E)
P.O. Box 42842
Houston, Texas 77242-2842
Tel: 281∙561∙1300
Fax: 281∙561∙1441
www.miswaco.com
E-mail: questions@miswaco.com
VinSeal
ADVANTAGES
■■
Minimal effects on mud rheology and
electrical stability when used at
normal dosages
■■
Effective bridging and sealing agent
for a wide range of formations
■■
Available in FINE, MEDIUM, and COARSE
grades for optimal performance
VINSEAL* cellulose fiber is a unique lost
circulation material and plugging agent that
can be used in all mud systems to bridge and
seal permeable formations.
■■
Easily mixed and dispersed into mud
systems
■■
Can be used in water-, oil-, and
synthetic-based mud systems
VINSEAL has minimal effects on rheology and electrical stability (ES), making it especially
ideal for use in oil- and synthetic-based mud systems. VINSEAL helps reduce fluid loss,
enhance filter cake quality, and minimize differential-pressure sticking tendencies,
particularly when drilling depleted zones. VINSEAL is available in FINE, MEDIUM, and COARSE
grades for optimal performance in bridging and sealing pores and pore throats of
permeable formations.
■■
One-sack product with no other
additive requirements
Typical Physical Properties
■■
Compatible with all mud systems and
other lost-circulation materials
Solubility in water ............................................................................................................... Insoluble
■■
FINE-grade easily passes through most
shaker screens
LIMITATIONS
■■
Can be removed from the circulating
system by shale shakers and solidscontrol equipment, especially when
using the MEDIUM and COARSE grades
with fine-mesh screens (< 100 mesh);
requires close monitoring of shale
shakers.
Physical appearance ..................................................................................Brownish red powder
Grade
Median Particle Size
d50 (μm)**
Recommended Test Procedure
FINE
50 - 90
Laser light scattering
MEDIUM
250 - 350
Dry sieve analysis
COARSE
600 - 800
Dry sieve analysis
Applications
VINSEAL additive is a superior lost-circulation material and bridging agent. It is highly
effective when used for drilling high-permeability/high-porosity zones. The product is
available in three different grind sizes: FINE, MEDIUM, and COARSE. Unlike conventional
fibrous lost-circulation materials, VINSEAL does not adversely impact the electrical
stability of invert emulsion drilling fluids.
VINSEAL additive is designed to bridge and seal permeable formations, reducing the
possibility of stuck pipe, controlling lost circulation, and providing filtration control. It
is compatible with water-, oil-, and synthetic-based mud systems. The recommended
whole mud treatment to control seepage loss in permeable formations ranges from 2 to
20 lb/bbl (6 to 57 kg/ m3). Concentrations in the range of 20 to 35 lb/bbl (57 to 100 kg/m3)
are recommended for more severe lost circulation.
** Median Particle Size (d50) is reported as a size range due to variations in the manufacturing and
grinding process. If a precise size distribution of a product is critical to a drilling operation, it should be
measured with the appropriate Recommended Test Procedure using samples that are representative
of those expected to be used in that operation. Nominal d10 and d90 values are available from Houston
Technical Services upon request.
Applications (Cont)
On the basis of its special particle size distribution, VINSEAL FINE is recommended for
most applications. Very-high-permeability formations, such as fractured carbonates
and conglomerates, may require the MEDIUM- or COARSE-grade products.
After the initial treatment, periodic treatments should be carried out to maintain the
desired concentration. Significant quantities of VINSEAL MEDIUM and VINSEAL COARSE
additive will be removed by fine-mesh shale shaker screens (100 mesh or finer).
VINSEAL should be added to the mud system through a mixing hopper in a suction or
other pit suitable for proper agitation. It also can be pumped as a pill to prevent or
control severe lost circulation.
Like any other product, pilot testing to determine compatibility with mud properties and
any resulting impact is recommended before adding high concentrations.
Toxicity and Handling
Bioassay information is available upon request.
Handle as an industrial chemical, wearing protective equipment and observing the
precautions as described in the Material Safety Data Sheet (MSDS)
Packaging and Storage
VINSEAL is packaged in 50 lb (22.7 kg), multi-wall, paper sacks.
Store in a dry location away from sources of heat or ignition, and minimize dust.
This information is supplied solely for informational purposes and M-I SWACO makes no guarantees or
warranties, either expressed or implied, with respect to the accuracy and use of this data. All product
warranties and guarantees shall be governed by the Standard Terms of Sale. Nothing in this document
is legal advice or is a substitute for competent legal advice.
©2011 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C.
FPB.2255.1103.R2 (E) Litho in U.S. A.
P.O. Box 42842
Houston, Texas 77242-2842
www.miswaco.slb.com
Email: questions@miswaco.slb.com