SPE 77352
Light Annular MudCap Drilling – A Well Control Technique for Naturally
Fractured Formations
John W. Colbert, SPE and George Medley, SPE, Signa Engineering Corp., Houston, Texas
Copyright 2002, Society of Petroleum Engineers Inc.
positive casing pressure. The casing pressure will increase as

This paper was prepared for presentation at the SPE Annual Technical Conference and
hydrocarbons migrate up the annulus. The value of the casing
Exhibition held in San Antonio, Texas, 29 September–2 October 2002.

pressure qualitatively corresponds to the height of the
This paper was selected for presentation by an SPE Program Committee fol owing review of
hydrocarbon migration. Once a predetermined casing
information contained in an abstract submitted by the author(s). Contents of the paper, as
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to
pressure/height is reached, LAMC fluid is pumped into the
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at
annulus until all the hydrocarbon is displaced back into the
SPE meetings are subject to publication review by Editorial Committees of the Society of
formation. After all the hydrocarbons are purged from the
Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper
for commercial purposes without the written consent of the Society of Petroleum Engineers is
wellbore, the casing pressure will return to a constant and
prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300
words; illustrations may not be copied. The abstract must contain conspicuous
predictable value.
acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.
Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
LAMCD is a well control/lost circulation technique

that allows drilling through massive lost circulation zones
Abstract
without downtime associated with lost circulation and
conventional well control. Penetration rates are increased
Light Annular MudCap drilling (LAMCD) is a
significantly as well.
safecost effective drilling technique that may be used to drill
through massively fractured formations or where Karsts are
This paper describes the application of Light Annular MudCap
prevalent, especially when productive fluids are sour. It is an
Drilling as well as the details of the method. Well control and
adaptation to regular Mud Cap Drilling (MCD), used to drill
equipment issues are addressed. Simple equations for
formations such as the Austin Chalk. The technique was first
estimating pressure and volume requirements during LAMCD
developed and used in the Cogollo formation in South America
are presented.
and has recently been used to drill sour formations in
Kazakhstan. The LAMCD technique allows the driller to
control and monitor the amount of sour gas migrating into
Introduction
the annulus.
The presence of fractured formations has plagued drillers
Drilling through formations containing multiple large
since the beginning of rotary drilling. The conventional way
fractures using conventional well control techniques is
to address the problem is to use lost circulation material or drill
impossible unless the fractures are sealed. In many cases
“blind” through the zone and subsequently set casing across
where extremely large fractures or karsts (vugs/caverns) have
the loss zone. Many operators target reservoirs that have
been encountered, lost circulation technology has proven to be
extensive natural fracturing because of the prolific production
unsuccessful.1-7 If the fractured formation being drilled is a
associated with fracture porosity. Consequently, it is
pay interval, plugging the fractures is counter-productive.
not desirable to permanently plug the hydrocarbon

bearing fractures.
The LAMCD well control/lost circulation technique
entails drilling with the choke completely closed while using a
MCD is a form of “blind” drilling that has been used
rotating control device (RCD) to seal the annulus. A sacrificial
extensively to drill the Austin Chalk formation in Texas and
fluid, usually fresh or brine water is injected down the drill
Louisiana.5,7 The technique naturally evolved from the flow
pipe. The drilled cuttings are transported and deposited into
drilling technique in situations where cross flow from
the fractures or vugs. The annulus is periodically injected with
pressured fractures to depleted fractures resulted in high fluid
a viscous fluid that has a density slightly less than the pore
losses and surface pressures. In the Austin Chalk Pearsall field
pressure equivalent, hence the name “Light Annular MudCap”.
water was pumped down the annulus while injecting down the
This controlled displacement process results in a predictive

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2
J. COLBERT AND G. MEDLEY
SPE 77352
drill pipe to bring annular pressures below the operating limit
Mudcap drilling, unlike underbalanced drilling, does not
of the RCD.
allow annular flow at the surface. However, it is
underbalanced from the standpoint that the drilling fluids exert
As the Austin chalk trend continued to be exploited further
a hydrostatic head that is less than the formation pore pressure.
down dip in deeper and higher pressures, MCD evolved. A
MCD may be a safe and economical alternative to
weighted viscous mud was pumped down the annulus while
underbalanced drilling.
the choke was closed. Water was pumped down the drill pipe
and out into the fractures. This “pressured mudcap” allowed
Applications
drilling to continue with lower annular pressures.
The MCD technique is best applied when casing is set
Drilling through formations containing multiple large
above the fractured zone. Large quantities of freshwater or
fractures using conventional well control techniques is
brine are required. MCD has been used successfully in both
impossible unless the fractures are sealed. In many cases
vertical and directional/horizontal wells, and in both onshore
where extremely large fractures or karsts (vugs/caverns) have
and offshore environments. Table 1 is a list of some of the
been encountered, lost circulation technology has proven to be
formations where MCD has been used successfully.
unsuccessful.1-7 When the fractured formation being drilled is
a pay interval, plugging the fractures is counter-productive.
MCD is primarily used in the following applications:
The MCD technique is drilling with the choke
• Drilling through highly fractured formations where it is
completely closed while using a rotating control device (RCD)
not desired to flow drill because of well control issues
to seal the annulus. A weighted viscous fluid “mudcap” is
and/or additional costs associated with surface
injected into the drill pipe – casing annulus with the annulus
equipment.
shut in to prevent hydrocarbon migration to the surface and
• As a contingency plan for flow drilling in fractured
subsequent annular surface pressure. Fig. 1. Is a horizontal
formations when sustained high mud losses and/or
wellbore schematic where MCD operations are in progress.
high annular pressures are encountered. This may be a
MCD techniques are not, however, limited to horizontal wells.
result of connecting fracture systems containing
different pressures.
LAMCD is slightly different than regular MCD as
• Drilling through fractured or Karst containing
historically done in the Austin Chalk and other similar
formations containing sour gas where the H2S gas is
fractured formations that are sweet. LAMCD technique
not desired at the surface during drilling operations.
controls the amount of sour gas allowed to migrate into the
• Drilling through fractured formations where limited
annulus, whereas regular MCD controls the casing pressure.
surface location size cannot support underbalanced
LAMCD technique uses a mudcap fluid that has a density
operations (UBO) fluid separation equipment.
slightly less than the pore pressure. Regular MCD uses a
mudcap fluid density that is typically 2 – 4 ppg greater than the
• Drilling through fractured formations where the bottom
pore pressure. MCD technique allows gas into the wellbore
hole circulating temperature is greater than the
and injects heavy annular mud when the casing pressure begins
temperature rating of downhole tools. The elimination
to increase to undesirable levels.
of fluid returns up the annulus reduces bottom hole
circulating temperature.
LAMCD technique allows monitoring sour gas
Generally, when drilling through extensively fractured pay,
migration qualitatively. The wellbore is displaced with the
flow drilling is preferred over MCD. Some of the
hydrostatically light mud, which results in a predictive positive
disadvantages of MCD compared to flow drilling are

casing pressure. As hydrocarbons begin to migrate the casing
listed below.
pressure will increase too. The value of the casing pressure
can qualitatively be compared with the height of the
• Large volumes of water or brine are required because
hydrocarbon migration. Once this predetermined casing
there are no returns.
pressure/height is reached, the light annular mud is pumped
• Formation damage is more likely, particularly if
into the annulus until all the hydrocarbon is displaced back into
significant matrix permeability exists, since all of the
the formation. After all the hydrocarbons are purged from the
drill fluid and drilled cuttings are injected into
wellbore the casing pressure will reach a constant and
the formation.
predictable value.
• Formation evaluation and fracture penetration
identification is more difficult because there are no
In short, Light MudCap Drilling (LMCD) is a drilling
returns to surface to evaluate mud log samples.
method that can be used to drill through sour highly fractured
• Stuck pipe is more likely because of increased
or karst intervals safely and economically.
potential for differential sticking and less efficient
cuttings removal from the well bore.

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SPE 77352
MUDCAP DRILLING – A NATURALLY FRACTURED FORMATION DRILLING TECHNIQUE
3
Figure 2 helps illustrate why neither conventional nor
• Drilling with 0% returns without filling the annulus
underbalanced techniques will work in thick, extensively
with fluid.
fractured, high-pressure formations. In this example, a
• Drilling with 0% returns while filling the annulus
reservoir pressure of 9,455 psi exists at a datum of 12,250 ft
with fluid.
TVD. The data was extrapolated to the top of the reservoir at
• Drilling with the annulus shut in.
12,000 ft TVD and down to the bottom of the reservoir at
• Drilling with the annulus shut in while using the
12,500 ft TVD using a reservoir fluid gradient of 0.381 psi/ft.
contractor’s rig pump to inject light fluid down the
Notice that the equivalent mud weight (EMW) required to
drill pipe and spotting heavy fluid in the annulus.
balance the formation at the top of the reservoir is 15.0 pounds
• Drilling with the annulus shut in while using service
per gallon (ppg) EMW, as compared to 14.7 ppg EMW at the
company high-pressure pumps to inject light fluid
bottom of the reservoir.
down the drill pipe and pumping heavy fluid into
the annulus.
If the borehole is loaded with 15.0-ppg fluid in order to
MCD involves pumping a weighted viscous fluid
balance the reservoir top, the borehole pressure at the bottom
“mudcap” into the drill pipe-casing annulus with the annulus
of the reservoir will result in an overbalance margin of 200 psi.
shut in to prevent hydrocarbons and high pressure from
It is not uncommon to lose massive returns in a highly
migrating to the surface. The annulus is shut in using a
fractured formation once the overbalance reaches as little as 10
rotating control device placed on top of the conventional
psi. This would preclude drilling the reservoir in a
blowout preventer (BOP) stack. When using LAMCD, mud is
conventional manner.
only pumped down the annulus if the casing pressure reaches a
pre-set upper limit, and then it is pumped only until the casing
On the other hand, if the formation is drilled with a 14.7-
pressure returns to a pre-determined lower limit, which
ppg fluid in order to balance the bottom of the reservoir and
depends on the actual pore pressure in the reservoir.
drill it underbalanced, the amount of underbalance at the
reservoir top will be more than 380 psi. In highly fractured or
At the same time, a clear, solids-free fluid is injected down
kasrt-containing reservoirs, it is not uncommon for reservoir
the drill pipe with the annulus closed. The injection fluid is
productivity to be too great to handle at the surface. The
usually fresh water when drilling on land and seawater when
resulting problem may be either too much fluid produced
drilling offshore. LAMCD has been described as drilling
at the surface, or too high a surface pressure based on
under a “floating” mudcap. The formation pressure holds the
available equipment.
annular mudcap fluid in place. . Annular pressure or the
pressure below the rubbers in the RCD is maintained below the
This type reservoir may also not be economically
equipment’s operating limit or below a predetermined
conducive to historic mudcap drilling techniques because of
maximum allowable surface pressure.
the high pressures and corresponding associated mud weights
required. For example, the use of the continuous injection
Viscosification of the mudcap fluid should be designed to
method of MCD may require pumping a continuous stream of
minimize hydrocarbon migration through the fluid. Periodic
15.0-ppg mud down the annulus. The cost of heavy-weight
injection of mud is normally necessary to add fluid to the
drilling fluid will make the project uneconomic.
mudcap to offset annular losses to the formation or reduce
surface pressure due to hydrocarbon migration, or both.
Since mud loss down the annulus is typically far less with
the LAMCD techniques than with historic MCD, it will allow
Determining the Weight of the Annular
an economic means of keeping the well under control while
“Mudcap” Fluid
drilling the reservoir.
The pore pressure of the reservoir to be drilled using MCD
General Concept Description
techniques must be measured, or at least estimated, before any
Drilling in massively fractured formations with casing set
meaningful planning can be done. The pressure in the
into the top of the formation can be very forgiving, in that the
reservoir can be determined using direct measures such as
well can always be killed or subdued by injecting kill mud
bottom hole pressure (BHP) surveys on offset wells in the
down the drill pipe or annulus while the annulus is shut in.
same reservoir or using indirect methods such as pore pressure
MCD capitalizes on this point.
plots from offset data. The reservoir pressure can also be
measured directly after the first fracture has been encountered,
MCD may be seen as a progression from ”classic” blind
by either measuring the shut in drill pipe pressure or by
drilling to drilling with a lightweight fluid underneath a
measuring the annular fluid level.Fig. 2 also illustrates the use
weighted mudcap as follows:
of offset data and reservoir fluid density to determine the
anticipated reservoir pressure along a vertical wellbore that is
drilled 500 ft true vertical depth (TVD) through the pay. This

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4
J. COLBERT AND G. MEDLEY
SPE 77352
allows appropriately weighted mud for use in the annulus to be
hydrocarbon migration, and in abnormally-pressured reservoirs
prepared prior to drilling into the lost returns zone. Final
the cost of the annular mud may be exhorbitant.

adjustments to mud density can be made after the actual pore
When MCD in formations containing sour gas; monitoring
pressure in the lost returns zone is determined while drilling.
and minimizing the amount of hydrocarbon migration into the
annulus is desirable. The mudcap mud is periodically injected
When drilling a horizontal well a similar situation exists.
into the annulus to displace migrating sour hydrocarbons back
However, we should examine the frictional dynamic gradient
into the formation. The amount of pressure that results from
instead of the reservoir fluid gradient. Annular frictional
use of a lighter annular fluid permits determination of
gradients resulting from circulating water from the bit along a
hydrocarbon migration rate and estimation of the position of
horizontal wellbore to the fractures is quite small. Injecting
any migrated hydrocarbons in the annulus.
water down a 6-1/8” X 3-1/2” annulus at a rate of 250 gpm
will result in a frictional gradient of only ±10.0-psi/1000 ft.
With LAMCD the density of the mudcap mud will
However, because injectivity in fractured formations can be
typically be 0.1 to 0.2 ppg (0.01 –0.02 SG) less than the EMW
very high, up to 50 bbls/day/psi for oil wells and 0.25
of the pore pressure at the top of the lost returns zone. This
mmscf/day/psi for gas wells, significant cross flow from the
will result in a casing pressure in the range of 50 to 150 psi,
zones near the bit to the zones near the heel of the well may
depending on formation depth, which will be used to monitor
occur. Drill fluid, being injected into the fractures, may
hydrocarbon migration. If the top of the lost returns zone (i.e.,
pressure charge the fractures. Massive fracturing along a
the first large fracture or karst) is substantially below the top of
wellbore presents an infinite number of injection pressure
permeable, productive formation pay, the top of the reservoir
cases. Fortunately, to successfully MCD, the downhole flow
will be underbalanced, and may contribute additionally to the
direction does not have to be known, since the annulus is shut
casing pressure. This will result in an intial casing pressure
in and no return flow is allowed at the surface.
higher than the typical range.
The mudcap fluid density required will depend on the
When periodic versus continuous injection is used, non-
formation pore pressure. It will also depend on whether it is
Newtonian fluids are preferred, utilizingthe thixotropic
desirable to keep the annulus fluid, or mudcap mud,
properties of the fluid to minimize hydrocarbon migration into
continually falling (historic MCD) or to minimize mudcap
the annulus. The objective should be the use of an annular
losses to the formation (LAMCD). When minimizing mudcap
fluid that has a density slightly less than the pore pressure
losses to the formation, LAMCD may be used, maintaining a
(EMW) at the top of the reservoir. This will ensure that the
“pressurized” mudcap in the annulus. Mathematically this is
wellbore is fully displaced with annular mud after every
simply expressed as
annular injection cycle, thus being able to monitor the
downhole conditions. After the annular injection cycle, the
Pchoke + .052*MWavg
annular or choke pressure should be equal to the difference in
ann*TVD = PPreservoir ............ (1)
the annular mud weight and the pore pressure at the top of the
where depth and pore pressure are at the top of the reservoir
reservoir or
where the maximum EMW in the reservoir occurs.
Pchoke = 052*(MWannulus - EMW pp)*TVD
(2)
In LAMCD filling the annulus with a lighter weight mud or
even fresh water after the lost returns zone is encountered
If the choke pressure is greater than it is supposed to be,
provides the simplest means of estimating the required mud
then migrated hydrocarbons may still be in the annulus.
weight. By accurately measuring the amount of lighter-weight
fluid put in the annulus, the pore pressure in the lost returns
Estimating Injection Pressures
zone can be determined within an acceptable margin or error.
Standpipe pressure for planning purposes can be estimated
With historic MCD, it is common practice for the operator
for static and dynamic conditions. The static standpipe
to choose a mudcap fluid density greater than the pore pressure
pressures can be estimated using the following equation.
equivalent by as much as 4 ppg. The reasoning is that
hydrocarbons continually migrate up the annulus decreasing
PSPPstatic = 0.052* (EMW pp – MWdrill pipe) *TVD (3)
the average annular fluid density, resulting in increasing
surface pressure. The “heavy” fluid is pumped into the
where PSPPstatic is the static standpipe pressure, which is the
annulus to reduce the surface pressures to below the operating
u-tube pressure imbalance between the drill pipe and the
pressure limit of the RCH or RBOP. However, using “heavy”
annulus. The dynamic or standpipe injection pressure is equal
annular fluid does not allow observation and monitoring of
to the static standpipe pressures plus the pressure losses down

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SPE 77352
MUDCAP DRILLING – A NATURALLY FRACTURED FORMATION DRILLING TECHNIQUE
5
the drill string and into the fractures and can be calculated
Estimating Annular Injection Volumes
as follows
Whether using periodic, continuous, or random annular
PSPPinjection = PSPPstatic + ∆PDP + ∆PDC + ∆PMWD +
injection, the annular injection volume and the respective daily
∆P
volume can be estimated using the following equations.
Motor + ∆PBit + ∆PFrac (4)
Q
2 – OD 2) / 1029 (5)
where P
Ann = (SF) VHM TPI (IDHole
DP
SPPinjection is the dynamic or injection standpipe
pressure. The description of the other variables is provided in
Q
the nomenclature section. The pressure drop associated with
ADC = 24 * 60 * QAnn / TPI
(6)
fluid flow through the fractures is usually neglected or
where Q
assumed to be very small. This is a good assumption when
Ann is the periodic injection rate required to prevent
gas from migrating at a rate of V
very large volume fractures have been encountered, especially
HM, and TPI is the time
between injection cycles. Q
when massive lost returns results. If MCD is attempted in the
ADC is the annular daily cumulative
injection volume.
presence of very small volume fractures, pressures may
increase beyond the mud pump pressure limit.
Hydrocarbon migration rate is a function of the
hydrocarbon composition, pressure, temperature and the
Estimating Drill Pipe Injection Volumes
density and rheology of the drilling fluid. It is also a function
of the well bore geometry. A rule of thumb for gas migration
Injection volumes required for MCD can be easily
rate in drilling mud is 7 ft/min to 15 ft/min. The old driller’s
estimated, whether drilling without a downhole motor or
rule of thumb for gas migration in mud is 1000 ft/hour.
drilling with a downhole motor.
However, Shell reported a gas percolation rate of 90 ft tvd/min
from an in-house gas bubble modeling exercise.3 The Shell
The injection rate for drilling without a motor will depend
model probably best describes gas migration through a non-
on drilling conditions. Normally, the injection rate should be
viscosified fluid in a shallow low-pressured environment.
at least the circulation rate adequate to remove the drilled
cuttings when drilling with water. Sifferman et al. estimated
Fig. 4 illustrates the effect of various hydrocarbon
that the minimum annular velocity to remove cuttings from a
migration rates on casing pressure and the volume required to
vertical well with water is 100 ft/min.8 Cuttings transport
displace the hydrocarbons back down the hole. The major
experiments for horizontal wells have shown that the height of
assumption is that the hydrocarbon density and migration rate
the cuttings bed is a function of the fluid velocity. But hole
is constant. Another simplifying assumption is that the
conditions may require higher annular velocities due to the
migrating hydrocarbons completely displace the drilling fluid.
uneven injection of fluid into or along the wellbore. 100 ft/min
This assumption becomes less valid as the depth decreases.
should be used to determine the minimum fluid needed.
The figure is intended only to give a general idea of the
relationship between migration rate, casing pressure, and
When drilling with a motor, the volume requirement for the
kill volume.
motor dictates the injection volume. Resulting annular
velocities are normally much greater than the minimum
Volume requirements are a major consideration when
velocity required for efficient cuttings removal/injection. For
selecting hole size. The reduction of wellbore size results in
instance, a 4¾-in. mud motor requires ± 240 gpm to operate.
less DP injection fluid and annular mud consumption due to
This equates to an annular velocity of 233 ft/min when using
the smaller capacities. However, smaller tool performance and
3-1/2” drill pipe in a 6-1/8” hole. The respective volume
completion requirements should also be considered.
requirement is 6,171 bbls for an 18-hour circulating day.
Equipment
Fig. 3 illustrates the volume requirements for 3 borehole
sizes. For each bore hole size the minimum requirement for
The equipment necessary for MCD can be divided between
drilling a vertical well without a motor and for drilling with a
surface and downhole equipment. The surface equipment can
mud motor are illustrated. The figure shows estimated volume
be further divided into BOP equipment, contingency gas
requirements for the vertical case using a minimum annular
separation equipment, and circulating equipment. One of the
velocity of 120 ft/min. All cases assume an 18-hour
major advantages of MCD is that very little equipment is
circulating day. Observation of this figure reveals that smaller
necessary compared to other underbalanced techniques. Fig. 5
bore hole sizes may be desired to minimize DP injection
is a schematic of the equipment necessary for MCD.
volume.

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6
J. COLBERT AND G. MEDLEY
SPE 77352
Blowout Preventer Equipment (BOPE)
Gas Separation System
The BOPE required for MCD is basically the same
Gas separation equipment is not normally used in MCD
equipment required for conventional drilling with the addition
operations since the annulus is sealed, preventing fluids from
of an RCD installed on top of the stack. However, High
returning to the surface. However, it is good contingency
pressure MudCap Drilling (HPMCD) requires an additional
equipment in the event the annulus is opened. The two types
high pressure circulating system including high-pressure
of separators that are generally used are gas busters and
cement- or fracture stimulation-type pumps. Since most
vacuum type de-gassers. For sour operations the gas buster
instances of LAMCD are undertaken in high-pressure
and the vacuum de-gasser can be installed in series for more
reservoirs, the use of high-pressure surface equipment often
efficient removal of any sour gas.
accompanies this technique. The blow out preventers,
wellhead equipment, and casing should be designed for a
The mud gas separator or a gas buster should be placed
minimum burst pressure equal to or greater than the maximum
downstream of the choke to route large volumes of gas away
shut in surface pressure when utilizing LAMCD, to be
from the rig via a flare line. Large atmospheric vessels are
conservative.
preferred because of their ability to remove high volumes of
gas efficiently.
In most cases the casing should be designed for production.
If properly designed casing is set into the top of the formation
Circulating System
and the BOPE is properly rated and installed, the well can
always be killed by injecting mud into the annulus from the
The circulating system is composed of rig pumps,
surface. The drill pipe does not have to be in the well during a
manifolding, check valves, kelly hose, standpipe and the drill
kill operation. If operating in a sour gas environment the well
string. All of the components must be able to withstand the
control equipment should have the proper metallurgical trim.
injection pressure created while MCD. High Pressure Mudcap
drilling (HPMCD) requires the circulating system to have a
Rotating Control Device (RCD)
pressure rating of 10,000 psi working pressure. Double or
redundant check valves should be placed between the pump
It is not always practical nor is it necessary for the RCD to
discharge and the standpipe and casing valves. The circulating
be rated for the maximum allowable surface pressure. The
system pressure rating should be at least rated as calculated by
RCD is used for sealing the annulus while allowing the drill
Equation 4.
pipe to be rotated and moved in and out of the hole. If surface
pressures approach the rating of the RCD, the pipe rams are
Pumps
usually closed, and the annular fluid is injected into the
annulus until surface pressure is within an acceptable range.
A minimum of at least two rig pumps should be manifolded
such that mud or water can be pumped with either pump down
It is important to reiterate that the RCD is the last barrier
either the standpipe or the annulus. In offshore operations or if
between pressurized wellbore fluids and drilling rig personnel.
HPMCD is planned, high-pressure cement pumps should be
As such, the RCD, regardless of its pressure rating, should not
manifolded for pumping from the pits down the standpipe or
be used as a shut in device.
the casing. In HPMCD applications, the the driller should
control the high-pressure service company pumps from the
Inside Pipe Shut-Off Tools
driller’s console instead of the service company personnel
controlling them. Also, emergency shut down switches for the
It is extremely important in MCD operations that all inside
high-pressure pumps should be placed strategically around the
pipe shut off tools be used or available during operations. This
rig for safety. A third party should inspect the manifolding to
will assist in containing abnormally high injection pressures
ensure safety.
that may be present due to an unbalanced “u-tube”
environment.
Standpipe
Drillstring Floats
Most drilling rigs have a standpipe rated for 5,000 psi
working pressure. All valves and fittings in the standpipe
Tandem drill pipe floats should be placed inside a bit sub
manifold should be rated at least to the rating of the standpipe.
bored for tandem floats. A piston or flapper type float valve is
Many rigs, particularly offshore, have two standpipes. In this
typically used. In extreme high-pressure MCD with standpipe
case, the standpipe manifold should contain a valve or block
pressure greater than 5,000 psi, a high-pressure differential
placed in the crossover line to separate the top drive bleed-off
float valve can be installed above the tandem float valves for
line from the 2nd standpipe that will be used for pumping
added safety and redundancy.
down the annulus. Each standpipe should have a kelly hose

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SPE 77352
MUDCAP DRILLING – A NATURALLY FRACTURED FORMATION DRILLING TECHNIQUE
7
attached to it, one being the active standpipe and the other one
PPreservoir = pore pressure in the reservoir, psi
as standby. Stand pipes are now available that have a 10,000
MWannulus = mud weight in the annulus, ppg
psi working pressure which can be used in High Pressure
EMW
pp = equivalent weight of pore pressure, ppg
MudCap Drilling. An air actuated bleed off valve connected to
PSPPstatic = static stand pipe pressure, psi
a manifold with a positive choke should be installed to allow
MWdrill pipe = mud weight inside the drill pipe, ppg
the driller to safely bleed off the pressure at the standpipe from
PSPPinjection = dynamic or injection stand pipe pressure, psi
the driller’s console instead of from the standpipe manifold.

∆PDP = parasitic pressure loss in the drill pipe, psi

∆PDC = parasitic pressure loss in the drill collars, psi
Rotary Hoses
∆PMWD = pressure loss through the measurement while
drilling tool, psi
The standard rotary hose(s) is usually 3” ID rated for 7500-
∆PMotor = pressure loss through the mud motor, psi
psi test and 5000-psi working pressure. If the rig has two

∆PBit = pressure loss through the bit, psi
standpipes and kelly hoses, both hoses should be tested to their

∆PFrac = parasitic pressure loss through the fractures, psi
full working pressure during BOP tests. Kelly Hoses are now

QAnn = periodic annular injection rate, bbls
available with a 10,000-psi working pressure, which can be

SF = safety factor
used in High Pressure Mud-Cap Drilling.

VHM = hydrocarbon migration rate, ft/min

TPI = time between injection cycle, min
Swivel/Top Drive
IDHole = diameter of the hole, inches
ODDP
=
outside
diameter of the pipe, inches
Swivels or top drives should have a minimum pressure

QADC = annular daily cumulative injection volume,
rating the same as the standpipe and should be tested at the
bbls/day
same time as the standpipe and rotary hose. Top Drives are


highly recommended for MCD because of pipe
Acknowledgments
movement/rotation abilities and monitoring.
We wish to thank the clients that have teamed with Signa
Conclusions
Engineering Corp. to explore the benefits of MudCap Drilling.
The following conclusions have been drawn from the study
Thanks to all the individuals at Signa that have contributed to
of Mudcap drilling to solve lost circulation and well control
the gaining of knowledge and experience with this technique.
problems associated with drilling fractured formations:
We give special thanks to Sammy Bell for his input from a
field supervisor’s perspective.
1. MCD allows an operator to continue drilling through

fractures/faults to total depth with minimum trouble
References
time/costs while minimizing mud losses to the formation.
2. In many cases it is impossible to drill naturally fractured
1. Urselmann, R., et al: “Pressured MudCap Drilling:
reservoirs with conventional balanced or overbalanced
Efficient Drilling of High-Pressure Fractured Reservoirs”
Paper SPE/IADC 52828 presented at the 1999 SPE/IADC
techniques. Sealing the fractures may be impossible and
Drilling Conference held in Amsterdam, 9-11 March.
sealing “pay zone” fractures is counterproductive.
2. Johnson,
J.,
et al: “High Efficiency Drilling – A Novel
3. If properly designed casing is set into the top of the
Approach for Improved Horizontal and Multi-Lateral
formation and the BOPE is properly rated and installed,
Drilling,” Paper SPE 52185 presented at the 1999 Mid-
the well can always be killed by injecting mud into the
Continent Operations Symposium held in Oklahoma City,
annulus from the surface.
Oklahoma, 28-31 March.
4. Volume requirements are a major consideration when
3. Reyna, K.: “Case History of Floating MudCap drilling
selecting hole size. The reduction of wellbore size results
techniques - Ardalin field, Timan Pechora Basin, Russia”,
in less DP injection fluid and annular mud consumption
Paper SPE/IADC 29423 presented at the SPE/IADC
Drilling Conference held in Amsterdam, 28 February-2 – 2
due to the smaller capacities. However, downsizing the
March 1995.
hole may add drilling and completion risks.
4. Al-Sarraf, A. and Hazel, R.: “The Drilling Optimization
5. The use of LAMCD techniques allows hydrocarbon
Performance in Kuwait’s High Pressured Wells” Paper
migration into the annulus to be monitored and controlled
SPE/IADC 39270 presented at the 1997 SPE/IADC
without undue loss of mud volume.
Middle East Drilling Conference held in Bahrain, 23-25
November.
Nomenclature
5. Mohd, A.: “Carbonate Drilling with Mud Loss Problems
in Offshore Sarawak” Paper IADC/SPE 36394 presented

Pchoke = choke pressure, psi
at the 1996 IADC/SPE Asia Pacific Drilling Technology
MWavg
held in Kuala Lumpur, Malaysia, 9 September.
ann = average mud weight in the annulus, ppg

TVD = true vertical depth, ft
6. Quitzau,
R.,
et al: “System for Drilling an Offshore
Shallow Sour Gas Carbonate Reservoir” Paper SPE/IADC

---

8
J. COLBERT AND G. MEDLEY
SPE 77352
52808 presented at the 1999 SPE/IADC Drilling
11. Adams, N.: Well Control Problems and Solutions

, The
Conference held in Amsterdam, 9-11 March.

Petroleum Publishing Company, 1980.

7. Johnson,
J.,
et al: “High Efficiency Drilling – A Novel
Approach for Improved Horizontal and Multi-Lateral
SI Metric Conversion Factors
Drilling,” Paper SPE 52185 presented at the 1999 Mid-
Continent Operations Symposium held in Oklahoma City,
Oklahoma, 28-31 March.
cp
x
1.0*
E-03
=
Pa.s
8. Urselmann, R., et al: “Pressured MudCap Drilling:

ft x 3.048*
E-01 = m
Efficient Drilling of High-Pressure Fractured Reservoirs”
ft2 x 9.290 304* E-02 = m2
Paper SPE/IADC 52828 presented at the 1999 SPE/IADC
ft3 x 2.831 685
E-02 = m3
Drilling Conference held in Amsterdam, 9-11 March.

in. x 2.54
E+00 =
cm
9. McLennon/Carden/Curry/Stone/Wyman,
SPE

lbf x 4.448 222
E+00 = N
“Underbalanced Drilling Manual”, Gas Research
md
x
9.869
233 E-04
=
µm2
Institute, 1997

psi x 6.894 757
E+00 = kPa
10. Sifferman, T.R., et al: “Drill Cutting Transport in Full-

Scale Vertical Annuli, » J. Pet. Tech. (Nov. 1974).
* Conversion factor is exact




TABLE 1 – FORMATIONS WHERE MUDCAP DRILLING HAS BEEN APPLIED
Formation
Basin or Area Sour Horizontal
On / Offshore Country
Bashkirian SW
Asia
Yes No Onshore/offshore
Kazakhstan
Austin Chalk
Texas/Louisiana
No*
Yes
On Coast
USA
Buda Texas/Louisiana
No Yes
On
Coast
USA
Georgetown Texas/Louisiana No
Yes
On
Coast USA
Glenn Rose
Gulf Coast
No
Yes
On Coast
USA
Mission Canyon
Williston
Yes
Yes
Onshore
USA
Limestone Middle
East
No
No Onshore
Kuwait
Cogollo Maricaibo
Yes No
Offshore
Venezuela
Carbonate Structures
Sarawak Yes
No Offshore
Indonesia
Carbonate Reef
North Sumatra
Yes
No
Offshore
Indonesia

* Sour gas has been found in limited areas of the Pearsall Field in South Texas




Fig. 1— Mudcap drilling schematic of horizontal wellbore
Fig. 2— Determining the Reservoir Pressure Along the Wellbore

---

SPE 77352
MUDCAP DRILLING – A NATURALLY FRACTURED FORMATION DRILLING TECHNIQUE
9
14,000
Minimum Daily Volume - Vertical - no Motor
12,000
Maximum Daily Volume (Down Hole Motor)
10,000
8,000
BBLs / day
6,000
4,000
2,000
-
2 - 7/8" DP
3-1/2" DP
5" DP
4-1/2" Hole
6" Hole
8-1/2" Hole


Fig. 3— Drill Pipe Injection Fluid Requirements for MudCap Drilling
8,000
400
Assumption:
Gas Migration Rate & Density is Constant
7,000
350
6,000
300 Min. Annular Kill Volume, bls.
5,000
250
4,000
200
3,000
150
Casing Pressure, psi.
Casing Pressure - 7 ft/min
2,000
100
Casing Pressure - 15 ft/min
Casing Pressure - 90 ft/min
1,000
Minimum Annular Kill Volume, bbl - 7 ft/min
50
Minimum Annular Kill Volume, bbl - 15 ft/min
Minimum Annular Kill Volume, bbl - 90 ft/min
-
0
0
5
10
15
20
25
30
Time, hrs.


Fig. 4— Effect of the Hydrocarbon Migration Rate on Casing Pressure and Annular Kill Volume

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10
J. COLBERT AND G. MEDLEY
SPE 77352


TOP
DRIVE
MUD
TANKS
RIG
PUMPS
BOP
STACK
HIGH PRESSURE
with
PUMPS for HPMCD
ROTATING
CONTROL
DEVICE
SEPARATOR
CHOKE
MANIFOLD
FLARE
LINE

FIGURE 5 Surface Equipment Layout for MCD

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