Using Downhole Annular Pressure Measurements
to Improve Drilling Performance
When monitored downhole in the context of other parameters, pressure in the borehole annulus can
be used to identify undesirable well conditions, help suggest and evaluate remedial procedures and
prevent serious operational drilling problems from developing.
Walt Aldred
John Cook
Cambridge, England
Peter Bern
BP Exploration Operating Company Ltd.
Sunbury on Thames, England
Bill Carpenter
Mark Hutchinson
John Lovell
Iain Rezmer-Cooper
Sugar Land, Texas, USA
Pearl Chu Leder
Houston, Texas
For help in preparation of this article, thanks to Dave Bergt,
Schlumberger Oilfield Services, Sugar Land, Texas, USA;
Tony Brock, Kent Corser, Kenneth Sax and James Thomson,
BP Exploration, Houston, Texas; Tony Collins, Liz Hutton,
John James, Dominic McCann, Rachel Strickland and
Dave White, Anadrill, Sugar Land, Texas; Tim French,
Anadrill, New Orleans, Louisiana, USA; Vernon H. Goodwin,
EEX Corporation, Houston, Texas; Aron Kramer, GeoQuest,
Youngsville, Louisiana; and Technical editing Services (TeS),
Chester, England.
APWD (Annular Pressure While Drilling), CDR
(Compensated Dual Resistivity tool), LINC (LWD Inductive
Coupling tool), SideKick, VISION475, VISION675 and VIPER
are marks of Schlumberger. PWD (Pressure-While-Drilling)
service is a mark of Sperry-Sun.
40
To survive and prosper in today’s low-price oil
and gas market, operating companies are continually challenged to lower their finding and
producing costs. To tap the full potential of existing reservoirs and make marginal fields more
productive, many wellbores are becoming both
longer and more complex. However, keeping
costs low requires operating companies to
improve drilling efficiency. The rig floor is sometimes like a hospital surgical theater. Instead of
finding physicians and nurses, one finds drillers,
engineers and other crew members working
with one objective: to keep their patient, the
borehole, alive and healthy. Just as biological
vital signs, like blood pressure and heart rate,
are monitored during an operation, so the life
signs of the borehole construction process—
downhole pressure and mud flow rates—are
monitored during drilling.
The measurements described in this article
are the “sight and touch” of the driller, enabling
him to “see and feel” the dynamic motions of the
Oilfield Review
Pressure
Winter 1998
Fracture
gradient
Pore
pressure
Annular
pressure
Depth
The pressure window. In some wells,
especially deviated and extended reach, the
margins (right) between pore pressure (red
curve) and fracture gradient (yellow curve)
may be small—500 psi [3447 kPa] or less—
and very accurate annular pressure (white
curve) information is essential to maintain
operations within safe limits. Well control
requirements are such that circulation of an
influx through the long choke and kill lines
that run from the subsea blowout preventer
(BOP) also imply a lower kick tolerance
(orange dashed curve). The influence of
well deviation angle on the pressure window
(below) shows that managing the mud
weight in extended-reach wells is made
more difficult by annular pressure losses
which are inherently high for wells with long
horizontal sections.
Kick
tolerance
2.4
Fracture
gradient
2.0
Stable
1.6
Mud weight, sg
drillstring, and the downhole behavior of the
drilling fluid, so that optimal decisions can be
made. Vibration and shock data along with
torque and weight on bit can be used to modify
drilling parameters for increased bit and bottomhole assembly (BHA) reliability and performance.
The lifeblood of the drilling process is the drilling
fluid, and downhole mud pressure—measured in
the annulus between the drill collar and the borehole wall—is one of the most important pieces
of information that the driller has available to
sense what is happening as the drill bit enters
each new section of formation, or during running
the bit into or out of the hole.
Monitoring downhole annular pressure is being
used in many drilling applications, including
underbalanced, extended-reach, high-pressure,
high-temperature (HPHT) and deep-water wells.1
Such measurements are provided by a number of
service companies, and operators have been
using them for a wide variety of applications
including monitoring the effects of pipe rotation,
cuttings load, swab and surge, leak-off tests
(LOT), formation integrity tests (FIT), and detecting lost circulation (see “How Downhole Annular
Pressure is Monitored,” page 42 ).2
In underbalanced directional drilling, the use
of downhole annular pressure sensors keeps the
operation within safe pressure limits and monitors the use of injected gas, which results in
more efficient, lower cost drilling. In extendedreach drilling (ERD), annular pressure measurements can be used to detect poor hole cleaning
and help the operator modify fluid properties
and drilling practices to optimize hole cleaning.
In conjunction with other drilling parameters,
real-time annular pressure measurements
improve rig safety by helping avoid potentially
dangerous well-control problems—detecting
gas and water influxes. These measurements
are often used for early detection of sticking,
hanging or balling stabilizers, bit problem detection, detection of cuttings buildup and improved
steering performance. While real-time pressure
data are of significant value, the information
from these measurements is also useful in planning the next well.
This article examines the physical processes
associated with downhole hydraulic systems
and the use of annular pressure in monitoring
the downhole drilling environment. We will look
at field examples that show the dynamics of
common drilling problems and demonstrate how
a basic understanding of hydrodynamic
processes—together with a knowledge of
drilling parameters—can help provide advance
warning of undesirable and preventable events.
Collapse
gradient
1.2
0.8
0.4
0.0
0
20
40
60
Well deviation, degrees
The examples illustrate three important drilling
applications in which downhole pressure measurements are valuable:
• Extended-reach wells, where efficient hole
cleaning and cuttings transport are essential in
preventing stuck tools and packoff events,
which may damage formations and lead to
expensive fluid loss.
• Deep-water wells, where there is a narrow
pressure window between pore pressure
and formation fracture pressure, and both
fluid influx detection and wellbore stability
are critical.
• Improved drilling efficiencies, with downhole
annular pressure measurements providing
accurate LOT and FIT pressures, and a more
realistic determination of formation stress.
1. Isambourg P, Bertin D and Brangetto M: “Field Hydraulic
Tests Improve HPHT Drilling Safety and Performance,”
paper SPE 49115, accepted for presentation at the SPE
Annual Technical Conference and Exhibition, New
Orleans, Louisiana, USA, September 27-30, 1998.
2. Rudolf R and Suryanarayana P: “Field Validation of Swab
Effects While Tripping-In the Hole on Deep, High
Temperature Wells,” paper SPE 39395, presented at the
IADC/SPE Drilling Conference, Dallas, Texas, USA, March
3-6, 1998.
80
Wellbore Stability
Successful drilling requires that the drilling fluid
pressure stay within a tight mud-weight window
defined by the pressure limits for wellbore stability. The lower pressure limit is either the pore
pressure in the formation or the limit for avoiding
wellbore collapse (above). Normal burial trends
lead to hydrostatically pressured formations,
where the pore pressure is equal to that of a
water column of equal depth. If the drilling fluid
pressure is less than the pore pressure, then formation fluid or gas could flow into the borehole,
with the subsequent risk of a blowout at surface
or underground.
The upper pressure limit for the drilling fluid
is the minimum that will fracture the formation. If
the drilling fluid exceeds this pressure, there is a
risk of creating or opening fractures—resulting
in lost circulation and a damaged formation. In
the language of drilling engineers, pressures are
often expressed as pressure gradients or equivalent fluid densities. The upper limit of the pressure window is usually called the formation
fracture gradient, and the lower limit is called the
pore pressure, or collapse, gradient.
41
How Downhole Annular Pressure is Monitored
The history of annular pressure measurements
extends as far back as the mid 1980s when
Gearhart Industries, Inc. provided annular pressure sensors on their measurements-whiledrilling (MWD) tools. Since then, Anadrill and
other service companies have developed sensors
for downhole annular pressure measurements
while drilling.1 The first application of these
measurements has been primarily for drilling
and mud performance, kick detection and equivalent circulating density (ECD) monitoring.
Adding internal pressure sensors, combined
with annular pressure measurements, enables
differential pressure to be determined, which
can be used to monitor motor torque and power
performance.
Sperry-Sun was an early proponent of recording ECD measurements during connections, and
while pulling out and running in hole to monitor
swab-and-surge effects.2 Their PWD (PressureWhile-Drilling) service uses a quartz pressure
gauge capable of measuring up to 20,000 psi
[138 MPa], and is available in collar sizes from
31⁄4 to 91⁄2-in.
Today, Anadrill provides APWD Annular
Pressure While Drilling measurements both in
real time and recorded mode using an electromechanical or bellows resistor device installed
on the side of the 150°C-[300°F]-rated CDR
Compensated Dual Resistivity tool and the
175°C-rated VISION475 tool (right). The CDR
tool is available in 63⁄4-, 81⁄4- and 91⁄2-in. collar
sizes. These tools can measure several pressure
ranges, up to 20,000 psi, with an accuracy of
0.1% of the maximum rating and a resolution of
1 psi. They are also capable of continuous monitoring during no-flow conditions, which enables
real-time dynamic testing while mud pump
motors are shut down—such as during leakoff
testing. Other parameters measured while
drilling, such as downhole torque and weight
on bit, can be combined with APWD measurements to evaluate hole-cleaning efficiency and
early detection of sticking, hanging or balling
stabilizers, to detect bit problems and cuttings
buildup, as well as to improve drilling and steering performance.
42
For operators trying to reduce drilling and
completion costs by downsizing from conventional hole sizes, the Anadrill 43⁄4-in. VISION475
tool enables simultaneous real-time APWD
measurements as well as drilling, directional
surveying and formation evaluation of boreholes
as slim as 53⁄4 in. (see “Pushing
Annular pressure sensor
the Limits of Formation
Evaluation While
Drilling,” page 29).
HPHT upgrades for
25,000 psi [172
MPa] and 350 °F
[175 °C] are available, and a new
system with APWD
capability for larger
boreholes, called
VISION675, will be
available soon.
For underbalanced operations, a coiled tubing
drilling system, the VIPER system, offers realtime internal, annular and differential pressure
measurements. The use of a wired BHA such as
in the VIPER system can be used in standpipe
gas injection applications such as nitrified fluids
and foams. APWD measurements in such underbalanced operations enable the driller to optimize production by maintaining planned
downhole pressures selected to minimize or
eliminate invasion and formation damage.
Under these conditions, the rate of penetration
will also be improved.
>
1. Hutchinson and Rezmer-Cooper, reference 5, main text.
2. Ward CD and Andreassen E: “Pressure While Drilling
Data Improves Reservoir Drilling Performance,” paper
SPE/IADC 37588, presented at the SPE/IADC Drilling
Conference, Amsterdam, The Netherlands, March
4-6, 1997.
CDR tool
Gamma ray
Pressure port
Resistivity
6.5 ft
Annular pressure sensor. Resistor-based bellows
gauges (insert) are used for APWD measurements
in the CDR Compensated Dual Resistivity tool, and
are available in three pressure ranges to meet the
expected wellsite conditions. These tools are mud
pulse-operated, so no information is sent in real
time when the mud pumps are off. However, they
can record pressures when the pumps are off, and
once pumping is re-established, this information
can be sent to the surface. Master calibrations
are performed over a range of temperatures using
a dead-weight tester. At the location or wellsite,
hydraulic tests using a hand pump are performed
on these gauges before and after use in each well
to verify calibrations.
Oilfield Review
Pore pressure—One ongoing oilfield challenge is determining the pore pressure in shales,
and almost all pore pressure prediction is based
on correlation to other measured properties of
shales. Shales start their life at the surface as
clay-rich muds, and water is expelled from them
as they are buried and subjected to increasing
loading from the overburden above them. If the
burial is sufficiently slow, and there is an escape
route for the water, the pressure in the pore fluid
remains close to hydrostatic, and the overburden
is supported by increased stresses in the solid
parts of the rock. The water content, or porosity,
decreases, and this variation of porosity or other
water-dependent properties with depth is known
as the normal compaction trend.
However, if burial is very rapid, or the fluid
cannot escape—because of the low permeability
of shales—the increasing overburden load is supported by the increasing pore pressure of the fluid
itself. The stress in the solid parts of the rock
remains constant, and the water content, or
porosity, does not decrease. After rapid burial, the
shale is not normally compacted; its pore pressure is above hydrostatic, and its water content is
higher than it would be for normallycompacted shale at that depth. The shale
becomes overpressured as a result of undercompaction. Detecting overpressured zones is a major
concern while drilling, because water or gas
influx can lead to a blowout.
Fracture gradients—Fracture gradients are
determined from the overburden weight and lateral stresses of the formation at depth and from
local rock properties. Density and sonic logging
data help provide estimates of rock strengths.3
Calculating offshore fracture gradients in deep
water presents a special problem. The uppermost
formations are replaced by a layer of water,
which is obviously less dense than rock. In these
wells, the overburden stress is less than in a
comparable onshore well of similar depth. This
results in lower fracture gradients and, in general, fracture gradients decrease with increased
water depth. Thus, increasing water depth
reduces the size of the margin between the
mud weight required to balance formation
pore pressures and that which will result in
formation breakdown.
Downhole Pressure
After the wellbore stability pressure window has
been determined, the driller has more to do than
keep the drilling fluid within these limits. To correctly interpret the response of a downhole annular pressure measurement, it is important to
appreciate the physical principles upon which it
depends. The downhole annular pressure has
two components. The first is a static pressure
due to the density gradients of the fluids in the
borehole annulus—the weight of the fluid vertically above the pressure sensor. The density of
the mud column including solids (such as cuttings) is called the equivalent static density
(ESD), and the fluid densities are pressure- and
temperature-dependent.
Second is dynamic pressure related to pipe
velocity (swab, surge and drillpipe rotation),
inertial pressures from string acceleration or
deceleration when tripping, excess pressure to
break mud gels, and the cumulative pressure
losses required to move drilling fluids up the
annulus. Flow past constrictions, such as cuttings
beds or swelling formations, changes in hole
geometry, and influxes or effluxes of liquids and
solids to or from the annulus all contribute to the
dynamic pressure. The equivalent circulating
density (ECD) is defined as the effective mud
3. Brie A, Endo T, Hoyle D, Codazzi D, Esmersoy C, Hsu K,
Denoo S, Mueller MC, Plona T, Shenoy R and Sinha B:
“New Directions in Sonic Logging,” Oilfield Review 10,
no. 1 (Spring 1998): 40-55.
4. For a detailed discussion of static, dynamic and cuttings
pressure contributions to the total downhole pressure:
Adamson K, Birch G, Gao E, Hand S, Macdonald C, Mack
D and Quadri A: “High-Pressure, High-Temperature
Well Construction,” Oilfield Review 10, no. 2 (Summer
1998): 36-49.
> Flow regimes. In laminar flow the annular pressure losses decrease with increasing pipe rotation,
because azimuthal stresses reduce the effective viscosity of the drilling fluid. Once the Taylor number
(a condition for rotational flow instability) is exceeded, vortices will be formed, which extract energy
from the mean axial flow, and yield a turbulent-like pressure drop. As the axial flow rate increases,
full turbulence will occur and the axial pressure drop will then increase with increasing rotational
rate. Similarly, increases in the rotation rate can also assist in the transition from laminar to turbulent
flow and can lead to an increase in the axial pressure drop.
Winter 1998
weight at a given depth created by the total
hydrostatic (including the cuttings pressure) and
dynamic pressures.
Understanding the different pressure
responses under varying drilling conditions also
requires an appreciation of the drilling fluid’s rheological properties, including viscosity, yield and
gel strength, and dynamic flow behavior. Is the
flow laminar, transitional or turbulent? The variation of the rheological properties with flow
regime, temperature and pressure singly, and in
combination, affects the total pressure measured
downhole.4 Some of these downhole parameters,
such as flow rate, can be controlled by the driller.
Others, such as downhole temperature, cannot.
Pressure Losses
Until recently, the industry had been divided on
the effects of drillpipe rotation on pressure
losses. Some researchers have explicitly stated
that rotation acts to increase axial pressure drop,
while others have taken the opposing view, that
an increase in rotation rate decreases annular
pressure drop. In fact, both of these seemingly
conflicting views can be correct, and both effects
have been observed. Annular pressure losses or
axial pressure drop depend upon which part of
the flow regime predominates when the rotation
rate is changed (below).
Flow rate
Turbulent
Turbulent with vortices
Laminar
Laminar with vortices
Rotation rate
Pressure increasing
43
2500
Pressure gradient, Pa/m
2000
Low flow
Medium flow
High flow
1500
Experimental conditions
Hole size = 4.9 in.
Pipe outer diameter = 3.5 in.
Plastic viscosity = 3.4 cp
Yield point = 3.8 lbf/100 ft2
1000
500
0
0
50
100
150
200
250
300
350
400
450
500
Rotation, rpm
> Laboratory-measured annular pressure losses. Experimental comparisons of the effect of rotation
on annular pressure losses with a clean drilling fluid (no solids) at low, medium and high flow rates
highlight the flow behavior in different flow regimes. These measurements confirm that under some
conditions rotation acts to increase axial pressure losses, whereas under other conditions it
decreases the losses.
1.13
Equivalent circulating density, sg
1.11
600 gal/min
1.09
1.07
1.05
1.03
400 gal/min
1.01
0.99
0.97
200 gal/min
0.95
0
10
50
100
Rotation, rpm
120
130
> Effect of rotation on equivalent circulating density (ECD). In addition to distinct effects on holecleaning efficiency, rotation also affects fluid behavior in an unloaded annulus. In this field experiment
of drillpipe rotation (at different flow rates), the ECD increases from 1.092 sg to 1.114 sg as the rotation
rate increases to 130 rpm with a 1.0 sg mud weight circulating at 600 gal/min [2300 L/min] in an 8-in.
[20-cm] casing section. The increment of 0.022 sg is equivalent to 50 psi [350 kPa]. No cuttings were
in suspension as this test was performed just prior to drilling.
Drillpipe
eccentricity
Cuttings
density
Little
influence
on cuttings
transport
Mud
rheology
Hole size
and angle
Mud
weight
Flow
rate
Rate of
penetration
Drillpipe
rotation
Cuttings
size
Hard to control
44
Hole cleaning.
Some factors are
under the control
of the driller, such
as surface mud
rheology, rate of
penetration (ROP),
flow rate and hole
angle. Others,
including drillpipe
eccentricity, and
cuttings density
and size, cannot be
controlled as easily.
>
Large
influence
on cuttings
transport
Easy to control
Experiments performed with the 50-ft [15-m]
flow loop at Schlumberger Cambridge Research
(SCR), in England confirmed the complex effects
of rotation on annular pressure losses (left). At
low flow rates, the pressure drop decreases with
increasing rotation rate. At higher flow rates, the
opposite effect is observed. However, in nearly
all field examples, with typical drilling muds in
conventional borehole sizes, only the increase in
annular pressure loss with increased rotation
rates has been observed (middle left). This is an
area of ongoing research.
Hole Cleaning
Efficient hole cleaning is vitally important in the
drilling of directional and extended-reach wells,
and optimized hole cleaning remains one of the
major challenges. Although many factors affect
hole-cleaning ability, two important ones that the
driller can control are flow rate and drillpipe rotation (bottom left).
Flow rate—Mud flow rate is the most important parameter in determining effective hole
cleaning. For fluids in laminar flow, fluid velocity
alone cannot efficiently remove cuttings from a
deviated wellbore. Fluid velocity can disturb cuttings lying in the cuttings bed and push them up
into the main flow stream. However, if the fluid
has inadequate carrying capacity—yield point,
viscosity and density—then many of the cuttings
will fall back into the cuttings bed. Mechanical
agitation due to pipe rotation or back-reaming
can aid cleaning in such situations, but sometimes are inefficient or worsen the situation.
Agitation that is too vigorous, such as rotating
too fast with a bent housing in the motor,
can have a detrimental effect on the life of downhole equipment.
Inadequate flow results in increased cuttings
concentrations in the annulus (next page, top). A
cuttings accumulation may lead to a decrease in
annular cross-sectional area, and hence an
increase in the ECD—ultimately leading to a
plugged annulus, called a packoff. The use of
real-time downhole annular pressure measurements allows early identification of an increasing
ECD trend, caused by an increasing annular
restriction, and helps the driller avoid formation
breakdown resulting from high pressure surges
or a costly stuck-pipe event.
An example shows how APWD Annular
Pressure While Drilling measurements help
detect packoff.5 The log shows that the annulus
started to pack off at approximately 1:20 (next
page, middle). Drilling parameters, such as
increasing surface torque and variations in rotation rates, were becoming erratic. Standpipe
pressure increased slightly. These warnings
Oilfield Review
High ECD
Asymmetric
suspension
Rolling
Stationary
Symmetric
suspension
Low ECD
>
Cuttings transport. The cuttings transport mode affects hole-cleaning
ability, especially in deviated wells. At low flow rates, the cuttings can fall
out of suspension to the low side of the borehole—building a cuttings bed
and increasing the ECD due to cuttings restriction in the annulus. As the
flow rate is increased, the cuttings will start to roll along the wellbore eroding the cuttings bed. As the cuttings bed is partially eroded, the annular gap
increases and the ECD will start to decrease. As the flow rate increases
further, the majority of the cuttings are transported along the low side of the
wellbore, with some suspended in the fluid flow above the bed (asymmetric
suspension) leading to an increase in ECD. At higher flow rates frictional
pressure losses are significant, and the cuttings are transported completely
suspended in the fast-moving fluid (symmetric suspension). [Adapted from
Grover GW and Aziz A: The Flow of Complex Mixtures in Pipes. Malabar, Florida,
USA: Robert E. Krieger Publishing Company, Inc., 1987.]
Low flow rate
0
Time
0
Surface rotation
Total pump flow
rpm
gal/min 1000 0
150 0
Surface torque
Standpipe pressure
psi
kft-lbf
30 0
4000 10
Temperature
°C
ECD/ESD
lbm/gal
Packing off. The driller responds in real time
to an increase in the ECD (red curve), shown
in track 4, as the annulus packs off above the
measurements-while-drilling (MWD) tool.
Surface torque and rotation rates, shown in
track 2, start to become erratic as the drillpipe
begins to pack off. Standpipe pressure, shown
in track 3, increases slightly. By temporarily
reducing the mud flow (green curve), shown in
track 3, and working the pipe, the annulus
becomes clear again.
>
Surface weight on bit
klbf
60
Measured depth
ft
0
11000
0
High flow rate
200
14
01:00
02:00
>
Effect of drillpipe
rotation on hole
cleaning. The ECD (red
curve), shown in track
6, increases—indicating cuttings are resuspended in the drilling
fluid—at 16:15 as
rotation recommences
after a slide-drilling
interval is completed.
Depth
ft
Block
speed
-10 ft/s 10 0
0
Hookload
klbf
500
Time
Surface torque
kft-lbf
Total
pump flow 0
Surface
rotation
0
1000
gal/min
0
rpm 200
13.2
15:00
Temperature
°C
100
Standpipe pressure
5000
psi
ECD / ESD
14.2
lbm/gal
Rotation
stops
Sliding
interval
16:00
Rotation
starts
could have been interpreted as due to increased
motor torque associated with an increase in surface torque. However, the large ECD increase
confirmed that the mud flow was restricted
around the BHA just above the annular pressure
sensor. Based on the confirmation from APWD
measurements, the driller reduced the mud flow
rate and worked the pipe to prevent the ECD from
exceeding the fracture gradient.
Winter 1998
Drillpipe rotation—Another example demonstrates the effect of pipe rotation on hole cleaning (above). At 15:00, pipe rotation was stopped
to enable drill-bit steering. The ECD decreased
for 20 minutes as the cuttings fell out of suspension. A few swab-and-surge spikes were
observed. These pressure spikes were introduced
as the pipe was moved up and down to adjust
mud motor orientation. After steering for a total
of 11⁄4-hours (at 16:15), rotary drilling was
resumed, and the ECD abruptly increased as the
cuttings—accumulated during the sliding interval—were resuspended in the drilling fluid.
Here, real-time APWD data helped determine the
minimum rate of rotation required to effectively
stir up cuttings and clean the wellbore.
5. Hutchinson M and Rezmer-Cooper I: “Using Downhole
Pressure Measurements to Anticipate Drilling Problems,”
paper SPE 49114, accepted for presentation at the SPE
Annual Technical Conference and Exhibition, New
Orleans, Louisiana, USA, September 27-30, 1998.
45
Bit on bottom flag
Drilling cycle 1
Block
position
0
m 50
ROP
Surface
weight on bit
Surface torque
200 m/hr 0
klbf
80
Hookload 0
20
kft-lbf 60
0 klbf 400
Downhole
Surface
Downhole
weight on bit
rotation
torque
Bit depth
Time
value, m
kft-lbf 20 0 rpm 200
0
klbf
80 19:00 0
ECD
1.65
sg
1.75
Annulus temperature
Turbine
rotation 0
°C
200
Annulus pressure
0 rpm 5000
Total pump 0
psi
4000
flow
Standpipe
pressure
gal/min
psi
0
1500 0
4000
Pumps on
Rotary drilling
Hole swabbed
Hole surged
Slide drilling
Cuttings
settling out
Kelly down
20:00
Pipe
reciprocating
Surge and
swab
Pumps off
Drilling cycle 2
21:00
> Downhole pressure monitoring to improve hole cleaning. Drilling fluid pumps start at 19:05, shown by pump flow rate in track 5. Pipe rotation starts a few
minutes later, seen by the increase in surface rotation rate shown in track 4. The instantaneous increase in standpipe pressure (green curve) and the
delayed downhole ECD (black curve) measurement can be seen in track 6. Rotary drilling stops and slide drilling starts at 19:27, shown by surface rotation
rate (track 4) and weight on bit (track 2). The immediate effect of slide drilling on the downhole ECD (black curve) can be seen in track 6. After Kelly down,
shown by the block position in track 1, the driller starts hole cleaning by reciprocating the pipe in and out. After the hole cleaning is completed, the driller
makes a new connection and starts the next drilling cycle at 20:30.
Improving Efficiency in
Extended-Reach Drilling
BP encountered severe wellbore instability problems when drilling development wells in Mungo
field in the Eastern Trough Area Project (ETAP) of
the North Sea. These instability problems were
due in part to large cavings formed while drilling
the flanks of salt diapirs. Long S-shaped 121⁄4-in.
[31-cm] sections are generally the most problematic. The volume of cavings—coupled with highly
inclined wellbore trajectories—results in poor
hole-cleaning conditions. The main cause of the
poor hole cleaning is believed to be the formation
of cuttings and cavings beds on the highly
inclined 60° section. These beds are manageable
while drilling, but present a major hazard when
46
tripping and running in casing. Most of the early
wells experienced extreme overpulls, packing off
and stuck-pipe incidents when pulling out of the
hole. In addition, severe mud losses had been
encountered when drilling inadvertently into the
chalk at total depth.
Based on this experience with borehole instability, BP revised its drilling program with a combination of better fluid management and
hydraulics monitoring aimed at improving both
hole cleaning and drilling practices. The results
were impressive. In the first well in the second
phase of the Mungo development, nonproductive
time was reduced from 34%—the average experienced on earlier wells—to 4%, with estimated
cost savings of over $500,000. Drilling rate performance increased 10%, while the incidence of
stuck pipe decreased.
The logs from this well exemplify how new
hole-cleaning practices, supported by APWD
monitoring, led to a successful drilling program
(above). The pumps were switched on at 19:05,
and the flow rate increased to 1000 gal/min [3785
L/min]. The standpipe and the downhole annular
pressure responded almost instantaneously and
after a few minutes, the driller started rotating
the pipe. The increased downhole weight on bit
indicates that drilling commenced just before
19:10. The first part of the stand was rotary drilled
at approximately 100 rpm until 19:27. At this time,
the drillstring was raised to set the necessary
toolface for the next sliding period. Sliding
began—shown by zero surface rotation rate—at
19:30 and continued until 19:45.
Oilfield Review
As the stand was being drilled, the ECD log
showed the effects of rotating and sliding.
During rotary drilling, ECD values were approximately 1.70 sg. When the drillstring was picked
up to set the toolface for sliding, the hole was
swabbed and the ECD dropped slightly to 1.69 sg.
As the drillstring was lowered, the hole was
surged about the same amount, raising the ECD
to 1.71 sg. Once rotation stopped, the ECD again
fell to 1.68 sg and continued to fall, as the cuttings started to settle in the hole, due to the lack
of mechanical agitation—reducing the cuttings
contribution to the ECD.
Even though drilling continued during sliding,
and cuttings were being produced at a steady
rate, the ECD did not increase. This demonstrates that the hole was not being cleaned as
efficiently as it had been with rotary drilling.
This was confirmed by the lack of cuttings over
the shale shakers.
The last part of the stand was also rotary
drilled. Rotation resumed at 19:46, and the ECD
increased immediately and continued to show an
increasing trend. Increasing ECD was caused by
turbulence and axial flow in the mud column in
the annulus as it stirred cuttings that settled on
the bottom of borehole. The cuttings added to the
hydrostatic pressure and increased the ECD. At
19:54 the driller picked up the string and started
the hole-cleaning procedure.
The bell-shaped profile of the ECD curve during rotary drilling was formed by the increasing
ECD due to the rotation and stirring of pre-existing cuttings beds as well as increased cuttings
load resulting from drilling ahead. The ECD
reached its peak value when the stand was
drilled down. As the hole was cleaned by reciprocating the pipe (maintaining a constant mud
flow and rotary speed), the ECD decreased.
When the value returned to nearly 1.71 sg, the
hole was deemed to be sufficiently cleaned.
After pipe reciprocation and flow were stopped,
a survey was taken at 20:19. After completion of
this operation, a connection was made and
drilling resumed successfully at 20:30 with good
hole cleaning.
Another example—using APWD monitoring
to avoid stuck pipe—shows how an indication of
cuttings accumulation during a drilling break can
take several hours to appear in the ECD log
because of the horizontal wellbore traveltime in
extremely long ERD wells. In BP’s most recent
Winter 1998
Block position
Hookload
50 0
m
500
klbf
Surface torque
ROP
0
50
kft-lbf
100 0
m/hr
ECD
Standpipe pressure
3000
4000 1.2
sg
1.3
psi
Annulus pressure
Total pump flow
2000
psi
3000 0
gal/min 2000
0
12:00
Drilling
break
1:00
4:00
5:00
Standpipe
pressure
increase
5:00
ECD
increase
> Preventing packoff events. The ECD, shown in track 4, rises—due to cuttings accumulation entering
the vertical section of an extended-reach well—about five hours after a drilling break.
record-breaking horizontal well at Wytch Farm,
England, a cuttings cluster traveled along the
horizontal leg of the wellbore for almost five
hours after the drilling break at 12:00 before
reaching the vertical section of the well (above).6
Finally, at 4:40 the ECD readings started increasing—approaching the fracture gradient of the
formation. The driller, anticipating potentially
severe well problems, decided to stop drilling
early, and clean out the cuttings accumulated in
the borehole by reciprocating the pipe. This is
another success story. Without advance notice
from the APWD measurement, the drillstring
might have become stuck.
6. Allen F, Tooms P, Conran G and Lesso B: “ExtendedReach Drilling: Breaking the 10-km Barrier,” Oilfield
Review 9, no. 4 (Winter 1997): 32-47.
47
48
Slim hole
20
5000
12
4800
8
Pit gain, bbl
16
4
4600
Shut-in Kill
0
Shut-in Kill
800
2000
600
400
1000
200
0
0
10
20
Time, min
Friction pressure loss
40 0
30
Pit gain
10
Standpipe pressure
20
Time, min
40
30
Friction pressure loss, psi
Annular pressure, psi
Typical hole
Standpipe pressure, psi
Kick Detection
The influx of another fluid into the wellbore due
to unexpected high formation pressure is one of
the most serious risks during drilling. The character of the fluid influx will depend primarily
upon influx fluid density, rate and volume,
drilling fluid properties and both borehole and
drillstring geometry (right). Simulations performed by The Anadrill SideKick software model
are frequently used to understand the pressure
responses expected downhole and at the surface due to gas influxes. (see “Simulating Gas
Kicks,” page 50).7 During gas kicks, ECD
responses for typical boreholes and slim wellbore geometries are dominated by two phenomena—reduced density of the mud column as
heavier drilling fluid is replaced by less dense
gas, and increased annular pressure loss due to
friction and inertia when accelerating the mud
column above the gas influx.
The reduced annular gap in slimhole wells
can cause unique drilling problems.8 For example,
in slim holes the acceleration of the kick fluid
into the wellbore can lead to a sudden increase
in frictional pressure loss in the annulus due to
acceleration of the mud ahead of the kick fluid. In
addition, evidence of the influx may not be seen
until the pumps are shut down. In typical hole
sizes, the hydrostatic imbalance between the
drillpipe and the annulus outweighs any frictional
losses, and a decrease in the bottomhole annular
pressure is evident.
Constant monitoring of all available drilling
data is critical in detecting a downhole kick
event. In an example of a gas kick, an operator
was drilling a 121⁄4-in. hole section in a well in
the Eugene Island field in the Gulf of Mexico
(next page). The formations were sequences of
shales and target sands, and several of the
sands were likely to be depleted by previous
production. In offset wells, the low-pressure
sands led to problems including stuck pipe,
twist-offs and stuck logging tools.
Maintaining a minimum mud weight was
required to avoid differential sticking in the
depleted sands. Due to faulting in the area, zonal
communication was uncertain and the pore pressure limits were difficult to anticipate. Anadrill
was using the CDR Compensated Dual Resistivity
tool for formation resistivity and the Multiaxis
Vibrational Cartridge (MVC), Integrated Weighton-Bit (IWOB) tool and APWD sensors for monitoring drilling performance. The plan was to set a
liner below a normally pressured zone before
drilling into the underpressured sand beds.
0
Annulus pressure
> Kick detection. In a typical wellbore geometry (top left), the annular pressure (orange curve) can be
seen to decrease as the displacement of heavier drilling fluids by a gas influx dominates the pressure
response. For slimhole geometry (top right) the annular pressure (orange curve) can increase initially
during a gas influx as the inertia of the mud column dominates the response. One major benefit of
downhole annular pressure monitoring is early kick detection. Mud-pit gain (red curves in upper plots),
standpipe pressure (green curves in lower plots), and frictional pressure loss (yellow curves in lower
plots) help the driller identify gas kicks.
Annulus
temperature
Block height
0
ft
120 200
°F 300
Time
08:00
13
ECD
lbm/gal
Standpipe
pressure
18 3000 psi 5000
09:00
Rack back
stand of pipe
10:00
Temperature rises,
ECD drops
11:00
Flow check
and close in
12:00
> Gas influx. When gas mixes with drilling fluid, the density of the drilling fluid decreases. Fifty minutes
after the ECD (blue curve), shown in track 3, started to decrease, a flow check confirmed that a small
gas influx had occurred. Note the increase in annular temperature, shown in track 2, as the formation
fluid warmed the borehole.
Oilfield Review
During drilling through a shale zone just
before 14:00, a few indications of increasing
formation pressure were seen in the APWD data
and several connection and background mud gas
indications were detected in the mud flow. Oilbase mud weights during this run were
increased from 11.5 to 12.0 lbm/gal [1.38 to 1.44
g/cm3 ]. Just before the sand was entered at
17:10, the real-time ECD measured downhole
was 12.5 lbm/gal [1.50 g/cm3 ]. At this point, the
ROP abruptly increased and drilling was
stopped—10 ft [3 m] into the sand zone—to
check for mud flow. Although the potential for a
kick was a concern, the fact that there was no
evidence of a kick or mud flow suggested that it
was safe to proceed.
As drilling progressed after 18:10, the ECD
measurement decreased slowly to 12.35 lbm/gal
[1.48 g/cm3] over a period of 90 minutes. Suddenly at 19:20, the ECD dropped to 12.0 lbm/gal
[1.44 g/cm3] while drilling the next 9 ft [2.7 m] of
the well. The drilling foreman noticed the large
drop in ECD readings—signaling an influx.
Increased pit volumes were noticed at this time
and the well was immediately shut in at 19:50.
The kill took 24 hours with an additional 30 hours
to repair blowout preventer (BOP) damage.
At what point did the kick first become
apparent on the downhole ECD log? The first
ECD drop from 12.5 to 12.35 lbm/gal probably
could be attributed to the decrease in ROP. Such
changes were seen earlier in this well.
Statistical variations in ECD, due to drilling
noise, can be as high as 0.2 lbm/gal. On the
other hand, the systematic change from 12.35 to
12.0 lbm/gal is a clear signal that an influx is
already in the mud column. Monitoring the ECD
constantly, using alarms set to detect the first
sign of ECD changes, and checking corroborating
drilling indications, such as ROP, can provide earlier warning of such occurrences.
In another example, use of APWD data helped
save a well. In this well, drilling was proceeding
without any indication of an influx either from pit
gain or in mud flow rates in or out of the well (previous page, bottom). However, the ECD started to
decrease at 11:00 and continued for 50 minutes.
At the same time, an increase in the annulus temperature was observed, due to the formation fluid
warming the borehole fluid. Guided by the ECD
response, the driller stopped drilling and safely
circulated out a small gas influx.
Winter 1998
Annulus temperature
100
°F
300
Standpipe pressure
Block speed
-2
ft/s
Axial vibration
2 4
ROP
500 ft/hr
Bit depth
0
ft
klbf
0
4000
klbf
0
60
60
ft-lbf
9
lbm/gal
Time
0
kft-lbf
25
Downhole torque
kft-lbf
5000
ECD
0
Surface torque
Downhole weight on bit
100 0
psi
Torsional vibration
G
Surface weight on bit
0 0
0
8 0
Total
pump
flow
gal/min
1500
11
CDR annulus pressure
0
psi
10000
Bit on bottom flag
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
> Kick alert in the Gulf of Mexico. A sudden increase in the rate of penetration (ROP) (blue curve),
shown in track 1, at 17:10 alerted the driller that the bit had entered a sand zone and that an influx
was possible. Drilling restarted after having seen no evidence of flow in the mud-flow measurements
or pit volume. However, as drilling progressed into the sand zone, the ECD (pink curve), shown in
track 5, started to decrease slowly at 18:10 and continued until 19:20. At this time, the rate of decrease
suddenly increased. After drilling ahead for 30 minutes with rapidly decreasing ECD and increasing
pit volume, the driller recognized that an influx had occurred and the well was shut in.
7. MacAndrew R, Parry N, Prieur J-M, Wiggelman J,
Diggins E, Guicheney P, Cameron D and Stewart A:
“Drilling and Testing Hot, High-Pressure Wells,” Oilfield
Review 5, no. 2/3 (April/July 1993): 15-32.
8. In this article, slimhole wells are defined as those with an
average pipe-to-annular radius ratio greater than 0.8.
49
Simulating Gas Kicks
The growth in deep-water drilling activities in
many regions of the world is attracting
increased attention to the specific problems of
gas influx and well control. Deep water poses
special problems related to both the depth and
temperature of the water. Reduced margins
between pore pressure and fracture gradient
require accurate understanding of downhole
fluid behavior.
Various definitions of kick tolerance exist and
may be given in terms of pit gain, mud weight
increase or even underbalance pressure. Whatever way it is expressed, kick tolerance is a
measure of the size and pressure of kick the well
can take and still be controlled without fracturing the formation. Kick tolerance decreases as
drilling proceeds deeper, and once the limit is
reached, additional casing must be set to protect
the formation. Kick tolerance is a complex concept as it varies as a function of the formation
pressure driving the kick, the amount of influx
entering the well and the distribution of the
influx in the annulus. Balancing this complexity
makes a simulator an ideal choice for computing
kick tolerance.
Scientists at BP and Schlumberger Cambridge
Research, England have spent years studying the
behavior of gas kicks.1 Their work, along with
engineering development at the Schlumberger
Sugar Land Product Center in Texas, has produced the Anadrill SideKick-PC software model,
which simulates gas kicks and helps plan methods of detecting and controlling them. SideKickPC models include the effects of gas distribution
in the annulus. This produces a more realistic
and less conservative kick tolerance, which
leads to the use of fewer casing strings and substantial cost savings. Kick tolerance is illustrated in user-friendly, automatically generated
plots of safe pit gain versus safe formation pressure (below). The simulator helps engineers
anticipate and meet the challenges of a wide
variety of drilling environments.
The simulator can be used in planning underbalanced drilling programs, which require estimates of wellbore pressures and fluid production rates. In addition, the cost-effectiveness of
using the underbalanced methods must also be
evaluated. Other simulators have helped address
Shut-in drillpipe pressure, psi
1000
Static
Circulating
900
Unsafe
800
700
Safe
600
500
400
0
10
20
Pit gain, bbl
30
40
these issues, but have looked only at stabilized
steady-state conditions. This simulator is a fully
transient numerical simulator that can determine the optimum amount of nitrogen necessary
to reach a desired underbalance.2
The SideKick-PC program also introduces
the concept of the Maximum Allowable Blowout
Preventer Pressure (MABOPP).3 This gives an
improved indication of the potential for shoe
fracture during a kill using a BOP pressure
measurement to remove uncertainties involved
in fluid properties in long choke and kill lines.
Simulations have shown that a simple technique can minimize the risk at the end of a
deep-water kill by slowing the pumps when the
choke is wide open to minimize pressure in the
annulus. This technique has been shown to be
preferable to other methods, such as using a
reduced slow-circulation rate over the whole kill
or arbitrarily reducing the flow rate, and is now
an integral feature of the simulator.
The SideKick-PC program has proved effective
in allowing engineers to run many complex simulations easily and quickly. Coupled with defining safe operating envelopes in minutes rather
than hours or days of well planning, gas-kick
simulation is helping to enhance overall performance by improving efficiency and reducing
well construction costs.
1. Rezmer-Cooper IM, James J, Davies DH, Fitzgerald P,
Johnson AB, Frigaard IA, Cooper S, Luo Y and Bern P:
"Complex Well Control Events Accurately Represented by
an Advanced Kick Simulator," paper SPE 36829, presented at the SPE European Petroleum Conference, Milan,
Italy, October 22-24, 1996.
2. A fully transient simulator is one that allows for the
temporal development of fluid behavior in the borehole as
the fluids are circulated, or while the well is shut in. This
has the advantage over steady-state models, where the
imposed state does not change fluid properties
over time, and cannot allow for effects such as gas
solubility as the gas cloud migrates after circulation has
stopped. Furthermore, such a transient simulator can
indicate whether steady state can even be reached.
3. James JP, Rezmer-Cooper IM, and Sørskår SK: “MABOPP
– New Diagnostics and Procedures for Deep Water Well
Control,” paper SPE 52765, submitted for presentation at
the 1999 SPE/IADC Drilling Conference, Amsterdam, The
Netherlands, March 9-11, 1999
> SideKick-PC kick tolerance. The SideKick-PC program computes separate kick tolerances for the shut-in
and kill periods of a simulation. The kick tolerance plot is used to differentiate kicks that can be safely
shut in (static) from those that can be safely killed (circulating). The determination depends on many
factors such as pressures in the well, gas migration, circulating friction and kill-mud hydrostatic pressure.
Kicks in the region to the left and below each curve are considered safe, and those severe enough to be in
the region above and to the right of each curve may cause lost circulation.
50
Oilfield Review
Casing, in.
Deep-Water Wells
Unconsolidated sediments typically encountered in deep-water formations tighten the
wellbore stability window between pore pressure and formation fracture pressure. At a given
depth, fracture gradient decreases with increasing water depth, and can result in a very narrow
pressure margin.9
Additionally, cooling of the mud in the deepwater riser can cause higher mud viscosity,
increased gel strength, and high frictional
pressure losses in choke and kill lines during
well-control procedures. Combined, these factors increase the likelihood of lost-circulation
problems, and drilling engineers must take
appropriate steps to avoid exceeding formation
fracture gradients.
Staying within the pressure window—
Keeping the ECD within the pressure window is
a constant struggle, especially in deep water and
HPHT applications. In a well in the Gulf of
Mexico, EEX Corporation experienced a kick
while drilling at near-balance conditions in Zone
A (right). After the kick was taken and the well
was under control, increased mud weight was
needed to continue safely. A 13 3⁄8-in. [34-cm] casing string was set because the heavier mud
weight exceeded the previous leakoff test.
The next two hole sections were drilled
without incident. However, as drilling proceeded deeper into the third section, the
increasing pore pressure eventually approached
the pressure exerted by the heavier mud and
another kick was experienced in Zone B. A
95⁄8-in. [24-cm] casing was needed to permit
another increase in mud weight. As drilling continued, increases in the cuttings load caused the
mud pressure to exceed the overburden pressure in Zone C, resulting in some lost circulation
over a period of several days. Lost-circulation
material helped minimize mud losses, and
drilling continued successfully thereafter. At the
narrowest point shown in this example, the
pressure window was only 700 psi [4827 kPa].
Dynamic kill procedure—Real-time analysis
of downhole annular pressure helped BP
Exploration monitor a dynamic kill procedure
used to stop an underground flow in a deepwater well in the Gulf of Mexico. Drilling unexpectedly entered a high-pressure zone, where a
Winter 1998
20
16
Zone A
Kick
133/8
113/4
Zone B
Kick
95/8
Zone C
75/8
10.00
Overburden gradient, lbm/gal
17.00
10.00
Resistivity pore pressure estimate, lbm/gal
17.00
10.00
ECD, lbm/gal
17.00
10.00
Seismic pore pressure estimate, lbm/gal
17.00
> Staying within the pressure window. A gas kick was observed in Zone A, where the ECD (blue curve)
dropped significantly below the pore pressure gradient—estimated from resistivity logs (red curve) or
seismic time-to-depth conversions (black curve). The well was brought under control with an increase
in mud weight—shown by the increased ECD. However, a second kick was experienced in Zone B
as pore pressure again increased above the ECD in this deeper section of the well. After another
increase in mud weight, some mud losses were experienced in Zone C, where the ECD increased
slightly above the overburden gradient (purple curve).
water influx fractured the formation at the casing
shoe. Real-time APWD measurements were
combined with standpipe pressure to monitor the
process of the dynamic kill.
The procedure circulated kill-weight mud fast
enough to “outrun” the influx and obtain a sufficient hydrostatic gradient to kill the well. Drilling
fluid used in this well weighed 11.8 lbm/gal
[1.41 g/cm3], and the kill-weight mud was
17.0 lbm/gal [2.04 g/cm3]. During the kill
procedure, BP’s Ocean America operating crew
monitored the standpipe pressure to determine if
9. Brandt W, Dang AS, Mange E, Crowley D, Houston K,
Rennie A, Hodder M, Stringer R, Juiniti R, Ohara S
and Rushton S: “Deepening the Search for Offshore
Hydrocarbons,” Oilfield Review 10, no. 1 (Spring
1998): 2-21.
51
kill weight mud was outrunning the influx fluid by
filling the annulus (below). However, under flowing conditions, the standpipe pressure could not
be used to accurately determine bottomhole
pressure. APWD measurements showed that
bottomhole pressure was increasing due to the
kill mud, and confirmed that the new dynamic kill
procedure was working. This process, monitored
with downhole annular pressure measurements,
has been incorporated into BP’s recommended
drilling practices.
Shallow-water flow—According to a recent
Minerals Management Services survey covering
the last 14 years, shallow-water flow occurrences
have been reported in about 60 Gulf of Mexico
lease blocks involving 45 oil and gas fields or
prospects.10 Problem water flow sands are typically found at depths from 950 to 2000 ft [290 to
610 m], but some have been reported as deep as
3500 ft [1067 m] below the seafloor. Frequently,
these problems are due to overpressurized and
unconsolidated sands at shallow depths below
the seafloor.11 They can lead to formation cave-in
when uncontrolled water production occurs. If an
influx is severe enough, wells can be lost due to
continuous water flow. Extensive washouts can
undermine the large casing that is the major support structure for the entire well.
Without riser
With riser
ρwater
ρmud
Sand
ρmud
Sand
> Riserless operations. During typical offshore drilling (left), drilling mud is circulated
through a riser back to the surface and the APWD tool measures an average ECD for the
entire interval. During riserless operations (right), the pumped drilling fluid does not return
to the surface, but rather carries its drilling solids only as far as the seafloor.
ECD
12
Block speed
2
500
ft/s
ROP
ft/hr
ft
Standpipe pressure
psi
4000
Annulus temperature
0
Bit depth
0
2000
2
13
lbm/gal
50
Hookload
100 400
klbf
Time
600 18:00
Surface torque
0
kft-lbf
Surface rotation Total pump flow
25 0
rpm 200 0 gal/min 1000 7000
°F
Annulus pressure
150
psi
9000
Kill starts
19:00
Kill stops
> Monitoring dynamic kill procedure. A water influx was encountered in a Gulf of Mexico deep-water well that was strong enough to fracture the
casing shoe, resulting in an underground flow. In track 6, both the standpipe pressure (green curve) and downhole annulus pressure (purple curve)
showed a steady increase at 18:30 while the kill mud was being circulated in the wellbore.
52
Oilfield Review
In many deep-water wells, the first casing
or conductor pipe is usually 30 or 36 in. [76 or
91 cm] in diameter. The next hole section, typically 24 or 26 in. [61 or 66 cm], is often drilled
without a riser. In these wells, spent drilling fluid
and cuttings are returned to the ocean floor
around the wellhead (previous page, top). Since
the drilling fluid is not recovered under these
conditions, expensive synthetic- or oil-base muds
typically are not used. Instead, either seawater
or inexpensive water-base mud is used.
Standard operating practices in deep-water
wells use a remote operating vehicle with a camera at the mud line to monitor flow coming out of
the wellhead. At a connection, the driller will
hold the drillpipe stationary and turn off the
pumps for a few minutes, to allow fluid u-tubing
oscillations to stabilize, and to observe whether
there is flow at the wellhead.
Downhole pressure measurements detect
shallow-water flow—Monitoring ECD helps the
operator assess both the depth and severity of
the water flow, and decide whether the flow is
serious enough to stop drilling. Most conventional hydraulics models do not consider the
effects of mud returns to the seafloor, and thus
cannot accurately predict the expected ECD in
these wells. A direct measurement of downhole
mud pressure solves this problem.
Operators are starting to use downhole pressure measurements as a way to detect the onset
of and prevent serious damage from shallowwater flows.12 In a deep-water well in the Gulf of
Mexico, a water sand in Zone A was encountered
at X090 ft (right). The ECD suddenly increased in
this zone as the sand was penetrated—indicating water and possible solids entry. The rise in
annular pressure and an ensuing visual confirmation of the mudline flow confirmed water entry.
The flow was controlled by increasing mud
weight and drilling proceeded. The same
trends—increased ECD with a corresponding
annular temperature increase—were seen in the
lower section of the next sand, Zone B, and in the
sand in Zone D below. The influxes were not
severe and were safely contained by the increasing ECD of the drilling fluid. Knowledge of the
location and severity of the contained water
influxes and quick response to early warning
from annular pressure measurements made it
possible to continue drilling successfully to the
planned depth for this hole section.
10. The Department of Interior Minerals Management
Services manages the mineral resources of the Outer
Continental Shelf and collects, verifies and distributes
mineral revenues from Federal and Native American
lands. They can be located at URL:
http://www.mmm.gov/.
Winter 1998
0
500
0
A
Rate of penetration
ft/hr
0
0
Gamma ray
Depth
m
150
API
0
Annulus temperature
Phase-shift resistivity
ohm-m
°F
2 50
100
Phase-shift resistivity
Annulus pressure
ohm-m
psi
10 2000
3000
Attenuation resistivity
ECD
ohm-m
lbm/gal
10 8
9
X000
Water influx
X100
B-upper
B-lower
X200
Water influx
X300
X400
C
X500
X600
X700
X800
D
X900
Water influx
> Shallow water flow in a deep-water well. Sand zones at A, B, C and D are indicated by decreasing
gamma ray (pink curve), shown in track 1, and resistivity responses shown in track 2. Increasing
annular pressure (green curve) and ECD (blue curve), shown in track 3, indicate that a water influx
occurred in three of these sands.
Improving Drilling Efficiency
With higher rig costs on many drilling projects,
such as extended-reach and deep-water wells,
time savings and precise measurements are
critical. Accurate leakoff tests (LOT) are essential
to enable efficient management of the ECD
within the pressure window, and the corresponding mud program.
Leakoff Testing—A LOT is usually performed
at the beginning of each well section, after the
casing has been cemented, to test both the
integrity of the cement seal, and to determine
the fracture gradient below the casing shoe. In
general, these tests are conducted by closing in
the well at the surface or subsurface with the
BOP after drilling out the casing shoe, and
slowly pumping drilling fluid into the wellbore at
a constant rate (typically 0.3 to 0.5 bbl/min [0.8
to 1.3 L/sec]), causing the pressure in the entire
hydraulic system to increase. Downhole pressure buildup is traditionally estimated from
standpipe pressure, but can be monitored
directly with APWD sensors. If pressure measurements are made in the standpipe, then complex corrections must be made for the effects of
temperature on mud density, and other factors
on downhole fluid pressure.13
Pressures are recorded against the mud volumes pumped until a deviation from a linear
trend is observed—indicating that the well is
taking mud. This could be due either to failure of
the cement seal or initiation of a fracture. The
point at which the nonlinear response first occurs
11. Smith M: “Shallow Waterflow Physical Analysis,” presented at the IADC Shallow Water Flow Conference,
Houston, Texas, USA, June 24-25, 1998.
12. APWD measurements are just one of the aids to minimize the hazards of shallow water flow. For additional
information: Alberty MW, Hafle ME, Minge JC and Byrd
TM: “Mechanisms of Shallow Waterflows and Drilling
Practices for Intervention,” paper 8301, presented at the
1997 Offshore Technology Conference, Houston, Texas,
USA, May 5-8, 1997.
13. Adamson et al, 1998, reference 4.
53
is the leakoff test pressure used to compute the
formation fracture gradient. Sometimes, the procedure is to stop increasing the pressure before
the actual leakoff pressure is reached. In such
cases, the planned hole section requires a lower
maximum mud weight than the expected fracture
pressure, and the test pressures only up to this
lower value with no evidence of fracture initiation. This is called a formation integrity test (FIT).
If pumping continues beyond the fracture initiation point, the formation may rupture, pressure
will fall, and the fracture will propagate.
APWD measurements helped monitor downhole pressure in a leakoff test performed by BP
Exploration in a deep-water well in the Gulf of
Mexico (below). As the pumped volume
increased to 3.5 barrels, the standpipe pressure
increased to 520 psi [3585 kPa]. Downhole ECD
increased from 9.8 lbm/gal (hydrostatic) to
10.9 lbm/gal [1.17 g/cm3 to 1.31 g/cm3]. At
this point, the pumping stopped, and the
ECD dropped exponentially to 10.7 lbm/gal
[1.28 g/cm3], indicating that the formation was
taking fluid. The pressure margin determined
from this test was sufficiently high to allow
drilling to proceed without incident.
Before a well is pressure tested, in order to
estimate downhole pressures from surface
measurements, the drilling fluid is often circulated to ensure that a homogeneous column of
known density mud is between the surface and
casing shoe. However, the downhole annular
pressure measured at the casing shoe provides a
direct measurement, and therefore the mud conditioning process is not required—saving the
cost of additional circulations. Downhole pres-
Pumping-up
phase
Leakoff
phase
600
B
Leakoff test
520
500
480
A
460
445
435
430
Surface pressure, psi
430
400
420 415
410 408 405
400
350
Formation taking
drilling fluid
300
260
200
165
100
80
0
1
2
3
Volume, bbl
1 2 3 4
Block speed Surface weight on bit
ft/s
2 0
klbf
80
Surface torque
Bit depth
Hookload
Time
0
500 14:00 10
kft-lbf
30
klbf
ft 100 0
2
5 6 7 8 9 10
Time, min
Surface
rotation
rpm
Total pump
flow
9
gal/min
0
1500 0
ECD
12
lbm/gal
Annulus pressure
psi
10000
15:00
16:00
> Leakoff testing. A leakoff test was conducted in a deep-water well in the Gulf of Mexico. During
the pumping-up phase, the standpipe pressure increases linearly as the pump volume increases
(top). At point A, the formation fractures and starts to take on some of the drilling mud. After the
pumping stops at point B, the standpipe pressure decreases rapidly at first, then more slowly as the
formation fractures close. The ECD log (bottom) from the APWD measurements, shown in track 6,
increases from the hydrostatic pressure to 10.9 lbm/gal [1.31 g/cm3] during the pump-up phase. After
pumping stops, the pressure starts to fall, and the ECD drops back.
54
sure measurements remove uncertainties caused
by anomalies in mud gel strength or inhomogeneities in the mud column density due to pressure and temperature effects.
Technologies from Schlumberger Wireline &
Testing, Anadrill and Dowell were combined to
perform a real-time downhole formation integrity
test in a deep-water well in the Gulf of Mexico.
During this test, an Anadrill CDR tool was
included in the BHA used to drill the casing shoe.
The CDR tool contained an APWD sensor to monitor downhole pressure. In typical logging-whiledrilling (LWD) applications, sufficient mud is
pumped to enable the BHA to communicate to
the surface through mud-pulse telemetry. This is
not the case with slow pumping rates used during a typical LOT or FIT. However, downhole pressure can be monitored in real time through the
use of a wireline-operated LINC LWD Inductive
Coupling tool that sits inside the CDR tool and
transmits pressure data to the surface.
With this arrangement, the operator can
simultaneously view the surface and downhole
pressure buildup as the test proceeds. In the
absence of compressibility and thermal effects,
the rate of pressure rise downhole would be the
same as that at the surface. The operator can use
downhole pressure measured with the APWD
sensor to calibrate formation integrity while using
the pressure buildup differences to monitor the
compressibility of the drilling fluid. Because of
shallow water flow concerns in deep-water wells
with narrow wellbore stability margins, differences of a few tenths of a lbm/gal can make the
difference between one or two extra strings of
casing being needed to protect shallow intervals.
Real-time downhole annular pressure measurements offer at least three advantages during
LOT and FIT testing. First, the operator does not
want to overpressure downhole too far—leading
to formation fractures or a damaged casing shoe.
A change in the slope of the pressure buildup
curve with pumped volume is a signal to stop the
test. This is the pressure used to determine the
fracture gradient of the formation. The use of
real-time annular pressure measurements provides the operator with an instantaneous signal
to stop the test.
14. Hutchinson and Rezmer-Cooper, reference 5.
15. Rojas JC, Bern P and Chambers B: “Pressure While
Drilling, Application, Interpretation and Learning,” BP
Internal Report, December 1997.
Oilfield Review
Next, monitoring surface pressure alone can
lead to incorrect estimates of bottomhole pressure because of uncertainty in correcting for
the compressibility of the drilling fluid, particularly significant when synthetic- or oil-base
muds are involved.
Finally, the unsteady nature of surface pressure data can lead to errors in LOT estimates of
fracture gradient. An accurate measurement of
fracture gradient is required to determine the
ability of the formation and casing cement to
support the drilling fluid pressure during the
next section of drilling. The use of stable and
accurate downhole annular pressure measurements helps makes drilling ahead a more exact
and safer process.
The Big Picture
In wireline logging, the log represents a state of
the well—showing the more-or-less static formation properties, such as lithological beds and
fluid saturations. Getting the data is most important, but decisions made at the time of acquisition are not necessarily critical. However, logs of
downhole annular pressure and other drilling
performance parameters show a process—
a process that is evolving with time. The evolution of the log in real time must be monitored as
downhole conditions are dynamic, and timely
decisions are essential. Delay or indecision can
lead to serious risks and added costs.
The format of drilling performance logs is different from wireline logs. Drilling problems gen-
Event or procedure
ECD change
Other indications
Comments
Mud gelation /
pump startup
Sudden increase
possible
Increase in pump pressure
Avoid surge by slow
pumps and break rotation
(rotation first)
Cuttings pick-up
Increase then leveling
as steady-state
reached
Cuttings at surface
Increase may be more
noticeable with rotation
Plugging annulus
Intermittent surge
increases
• Standpipe pressure
• Surge increase?
• Torque/RPM fluctuations
• High overpulls
Packoff may
“blow-through”
before formation
breakdown
Cuttings bed formation
Gradual increase
• Total cuttings expected
not seen at surface
• Increased torque
• ROP decreases
If near plugging, may get
pressure surge spikes
Plugging below sensor
Sudden increase as
packoff passes sensor
– none if packoff remains
below sensor
• High overpulls
• “Steady” increase in
standpipe pressure
Monitor both standpipe
pressure and ECD
Gas migration
Increase if well is
shut-in
Shut-in surface pressures
increase linearly (approx.)
Take care if estimating
gas migration rate
Running in hole
Increase – magnitude
dependent on gap,
rheology, speed, etc.
Monitor trip tank
Effect enhanced if
nozzles plugged
Pulling out of hole
Decrease – magnitude
dependent on gap,
rheology, speed, etc.
Monitor trip tank
Effect enhanced if
nozzles plugged
Making a connection
Decrease to static
mud density
Pumps on/off
indicator
Pump flow rate lag
Watch for significant
changes in static mud
density
Barite sag
Decrease in static
mud density or
unexplained density
fluctuations
High torque and
overpulls
While sliding periodically
or rotating wiper trip to
stir up deposited beds,
use correct mud rheology
Gas influx
Decreases in
typical size hole
Increases in pit level
and differential pressure
Initial increase in
pit gain may be masked
Liquid influx
Decreases if lighter
than drilling fluid
Increases if influx
accompanied by solids
Look for flow at mudline
if relevant
Plan response if shallow
water flow expected
> Interpretation guide. Monitoring ECD with downhole annular pressure measurements along with
other drilling parameters helps the operator know what is happening downhole in the wellbore. Some
of the known, clearly identifiable, and repeatable signatures of ECD changes are shown along with
secondary or confirming indications, such as those seen in surface measurements.
Winter 1998
erally result in slower rates of penetration and
data are compressed on a depth scale.
Therefore, a time-based presentation is often
better suited for detailed analysis during problematic drilling intervals. Still, depth-based presentations are important for assessment of
drilling events in the context of BHA position relative to lithological boundaries.
Drilling parameters should be presented in
relation to one another on the log. Wireline logs,
such as the triple-combo used for formation evaluation, have a standard layout that helps analysts learn how to quickly spot the important
productive zones. A standard layout for drilling
performance logs has recently been proposed
(previous page).14
The proposed layout enters geometric parameters such as bit depth, ROP, and block speed in
track 1, followed by weight parameters such as
hookload and downhole weight-on-bit in track 2.
Time or true vertical depth (TVD) are shown in the
next column. Next, torque parameters in track 3,
rotation rates along with lateral shock and motor
stall in track 4, and flow parameters such as mud
flow rates, differential flow, total gas, mud pit
level and turbine rotation rate in track 5. Finally,
pressure measurements such as ECD, ESD, annular pressure, annular temperature, swab-andsurge pressures, estimated pore and fracture
pressure limits and standpipe pressure are all
shown in track 6.
Downhole annular pressure interpretation is
an evolving technique. All possible downhole
events have not yet been observed. Sometimes
the data are enigmatic. Nonetheless, certain
clearly identifiable and repeatable signatures
can be used to help diagnose problems (left).
Combining the information gleaned from downhole annular pressure logs with other drilling
parameters creates an overall assessment, or the
big picture. This global view helps decipher the
individual measurements used to detect drilling
problems downhole.
Downhole real-time annular pressure measurements have a significant impact on today’s
drilling practices with applications in every
aspect of drilling. For example, many of the lessons and efficiency improvements made in highcost ERD and deep-water wells can be applied to
simpler wells. Monitoring downhole annular
pressure along with other drilling parameters
provides an integrated view of a healthy drilling
environment—one that puts emphasis on anticipation and prevention rather than reaction and
cure.15 Such improved operational procedures
will lead to decreases in nonproductive time and
increases in drilling efficiency.
—RCH
55