The Pressures of Drilling and Production
Yves Barriol
Karen Sullivan Glaser
Julian Pop
Sugar Land, Texas, USA
Pressure measurement is essential to optimized hydrocarbon recovery. Now,
Bob Bartman
Devon Energy
Houston, Texas
production, accurate, cost-effective pressure data can be acquired to help reduce
accurate formation pressures can be determined at almost any time in a well’s life
cycle. Whether while drilling, when the well is at total depth, or years after initial
risk and improve recovery.
Ramona Corbiell
New Orleans, Louisiana, USA
Kåre Otto Eriksen
Harald Laastad
Statoil
Stavanger, Norway
James Laidlaw
Aberdeen, Scotland
Yves Manin
Clamart, France
Kerr Morrison
BP Exploration and Production
Aberdeen
Colin M. Sayers
Houston, Texas
Martin Terrazas Romero
Petróleos Mexicanos (PEMEX)
Poza Rica, Mexico
Many everyday pressure effects go unnoticed. We
seldom consider why water flows from a tap or
how an airplane flies. And certainly, while fueling the family automobile, the nature of
geopressures that drive hydrocarbons to the
surface is far from our minds. Our world relies
on pressure in many ways, not the least of which
is the production of oil and gas.
The story of geopressure is rooted in the
Earth’s beginning. As the molten outer core of
the Earth cooled, plate-tectonic movements
driven by convection within the Earth generated
stresses in the crust. Movement, warping and
buckling of these stressed crustal plates caused
mountains and basins to form. Volcanic eruptions
associated with plate-tectonic forces spewed
material from within the Earth, forming the
atmosphere and oceans.
As plate-tectonic activity continued to
influence subsurface pressure conditions, weather
patterns formed. Cycles of oceanic evaporation,
atmospheric saturation, condensation and inland
precipitation fueled rivers that run to the oceans,
carrying with them large amounts of eroded rock
and terrigenous and marine organic material. As
the transport velocity slowed, these materials
settled in depositional basins (below). Later,
during continued burial and compaction, these
Condensation
Evaporation
Precipitation
Yakov Volokitin
Shell E & P Americas
New Orleans, Louisiana
Surface
runoff
Ocean
Lake
Flow
For help in preparation of this article, thanks to Jeff Cordera
and Aaron Jacobson, Clamart, France; Roger Goobie,
Houston, Texas; Jose de Jesus Gutierrez, Mexico City,
Mexico; Martin Isaacs, Frederik Majkut and Lorne Simmons,
Sugar Land, Texas; and Paula Turner, independent
consultant, Houston.
adnVISION675, AIT (Array Induction Imager Tool),
arcVISION675, CHDT (Cased Hole Dynamics Tester),
CQG (Crystal Quartz Gauge), FloWatcher, MDT (Modular
Formation Dynamics Tester), Platform Express, PowerDrive
Xtra, PressureXpress, proVISION675, Sapphire, Smart
Pretest, StethoScope, TeleScope, USI (UltraSonic Imager),
VISION and WellWatcher are marks of Schlumberger.
22
Water table
Particle transport
Sedimentation
Bedding
> The hydrologic cycle. Evaporation of water from the ocean forms clouds. These clouds drift over
the land and produce rain that flows along rivers back to the ocean, carrying with it rock and organic
debris that accumulates in basins. The cycle repeats, depositing massive layers of material.
Oilfield Review
Autumn 2005
23
materials were transformed by heat, pressure and
organic activity into the many hydrocarbon
compounds we know as petroleum.
Thus begins the story of geopressure,
hydrocarbons and production. In this article, we
first review the development of geopressured
systems, and then discuss the effects of
formation pressure on drilling, evaluation,
production and recovery of hydrocarbons. Case
histories from the Gulf of Mexico, Mexico and the
North Sea show how drillers, engineers and
geoscientists are using advanced techniques to
predict, measure and manage pressure, allowing
wells to be drilled more safely, boreholes to be
placed more accurately, and reservoir contents
to be evaluated and managed for maximum oil
and gas recovery.
Development of Geopressured Systems
The Earth’s outer crust hosts a complex system of
stresses and geopressures that constantly seek
equilibrium. Although the subsurface comprises
many geologic features in different pressure and
stress regimes, one of the most commonly
Congo fan
free-air
gravity
Seep clusters
Bathymetry
contours
> Seepage identified offshore Angola, West Africa. About 75% of the world’s
petroliferous basins contain surface seeps. Knowing where oil and gas seeps
are emerging is helpful in locating the sources of subsurface oil and gas
accumulations. Scientists use satellite imagery to help identify potential
hydrocarbon reservoirs. In this image, free-air gravity values derived from
European Remote-Sensing Satellite (ERS) data identify areas of high gravity
resulting from sediment emitted from the Congo River, known as the Congo
Fan. The data are also used to help identify areas of hydrocarbon seepage
shown as red-outlined contours. The subsea seep source is typically located
using sonar or shallow seismic reflection. The hydrocarbons can then be
sampled, helping to identify oil type and field maturity and to correlate with
other subsea seeps. (Image courtesy of NPA Group; Archive block outlines
courtesy of IHS Energy.)
24
studied subsurface pressure distributions occurs
in relatively shallow sediments, laid down in
deltaic depositional environments. Rivers wash
large amounts of sand, silt and clay into offshore
basins where they accumulate, are lithified over
millions of years and form primarily sandstone,
siltstone and shale.
Initially, the sediments deposited at the
mouths of rivers are unconsolidated and
uncompacted, with relatively high porosity and
permeability that allow remnant seawater, or
connate water, in the pores to remain in full
hydraulic communication with the ocean above.
With time and compaction as more sediment is
deposited, water is squeezed out of pore spaces
and grain-to-grain contact supports more and
more of the depositional load. Provided there is a
conduit for the water to escape, pressure
equilibrium is maintained in the pore spaces.
Once formed, oil and gas migrate upward to
zones of lower pressure, possibly reaching the
surface to form seeps if there is no mechanical
blockage along the way. Geological and
archeological evidence shows that hydrocarbon
seeps have occurred naturally in various parts of
the world for thousands of years. In some cases,
subsurface pressures drive large volumes of
hydrocarbons to the surface. Along the California
coast near Goleta Point, USA, commercial
volumes of natural gas continue to escape from
natural fractures in the Earth’s crust. Here
engineers designed a unique underwater gasrecovery system, capturing more than
4,000 million ft3 [113 million m3] of natural gas
since 1982. This is enough natural gas to supply
the annual needs of more than 25,000 typical
California residential consumers.1
Seeps generally occur where erosion exposes
hydrocarbon-bearing rocks at the Earth’s surface,
or where a fault or fracture allows pressure-driven
hydrocarbons to migrate to the surface. Historical
records indicate that surface seepage led to the
discovery of many petroleum deposits.2 Today,
aerial and satellite imagery helps geologists
detect natural oil and gas seeps migrating from
great ocean depths, offering the promise of yet
undiscovered hydrocarbon reserves (left).
Fortunately, most subsurface hydrocarbons
do not leak to the surface. As oil and gas migrate
upward, they typically become trapped beneath
low-permeability layers, or seals. These seals may
consist of many rock types, including shales,
calcareous shales, well-cemented sandstone,
lithified volcanic ash, anhydrite and salt.
Hydrocarbon traps are frequently grouped
according to the geologic processes that cause
them, such as folding, faulting and structural
Oilfield Review
Gas
Oil
Salt water
> Structural traps. The weight of overlying sediments causes salt layers to plastically deform, creating diapirs. As diapirs evolve, sediments onlap their
margins, forming traps that typically accommodate hydrocarbons (left). Where the strata have deformed to form an anticline (center), oil (green) and gas
(red) may become trapped under a seal. Faulting may also trap hydrocarbons (right) by sealing the updip margin of a reservoir.
changes caused by plate-tectonic activity or the
plastic deformation of salts or shales (above).
Many hydrocarbon traps involve combinations of
structural and stratigraphic features, but once
trapped beneath a seal, reservoir fluids have no
hydraulic communication with the surface. Given
time and the right circumstances, pressure
increases in the rock pore space (see “Causes of
Abnormal Pressure,” page 26).
Early Oil and the Uncertainty of Pressure
Sometime before 200 BCE, the Chinese relied on
geopressure to help produce the first gas wells.3
Other records indicate that as early as 1594, near
Baku, Azerbaijan, shallow pits or wells were dug
by hand to depths of 35 m [115 ft], making this
area the first actual oil field.4
In the USA, the history of drilling prior to the
19th Century is unclear, although seep-oil use is
noted in numerous early historical accounts. In
1821, drillers completed the first well in the USA
designed specifically to produce natural gas. This
well, in Fredonia, New York, USA, reached a
depth of 27 ft [8.2 m] and produced enough gas,
driven by natural pressure, to light dozens of
burners at a nearby inn. Then, Edwin L. Drake
drilled an exploratory well in 1859 near
Titusville, Pennsylvania, USA, to locate the
source of an oil seep.5 At a depth of 69.5 ft [21 m],
drillers pulled their tools from the well. Within
24 hours, geopressure effects forced oil up the
borehole. Fortunately for Drake, oil seeps in the
area precluded abnormal pressure buildup.
Using a manual pump, drillers produced about
25 bbl/d [3.9 m3/d] of oil. Although production
soon dropped to around 10 bbl/d [1.5 m3/d], the
well is said to have continued producing for a
year or more.6
By the early 1900s, drillers, geoscientists and
engineers recognized the importance of geopressure in oil and gas production. The
Spindletop discovery, which blew out during
drilling near a salt dome at 1,020 ft [311 m],
produced around 800,000 bbl [127,120 m3] of oil
in eight days and provided scientists with
insights into salt dome-related abnormal
geopressure effects.7
As drilling activity increased, exploration
reached into new and uncharted territories.
Remembering the uncontrolled oil gushers of the
past, drillers were constantly on the lookout for
abnormal geopressures. Engineers and scientists
began to seek new ways to predict abnormal
pressures during the search for oil.
At around the same time that Drake drilled
his first well, seismic instruments were being
developed and used to record and measure Earth
movements during earthquakes. Researchers
developed the technologies that form the basis of
reflection seismology. In reflection seismology,
subsurface formations are mapped by measuring
the time it takes for acoustic pulses transmitted
into the Earth to return to the surface after being
reflected by geological formations with varying
physical properties.8 Over time, seismic technology moved into the oil field, providing
geophysicists, geologists and drilling engineers
with the tools to evaluate reservoirs and pressure
regimes long before drilling a well.
Although early geopressure estimations from
seismic image analysis were crude, drillers
needed predrilling pressure estimates for mudweight selection, casing design and well-cost
estimation, among other uses. Engineers found
early pressure estimates too uncertain,
especially in complex oil and gas reservoirs. To
more easily understand and visualize the
geopressure environment, geoscientists now use
sophisticated seismic data acquisition and
processing techniques, mechanical earth models
and pore-pressure cubes to study, evaluate and
visualize pressure environments within a given
basin or area.
Engineers use reflection tomography that
yields higher spatial resolution than conventional seismic techniques to accurately predict
pore pressure from seismic data. This high
resolution also helps differentiate variations in
pore pressure from variations in lithology and
fluid content.9
(continued on page 28)
1. Natural Oil and Gas Seepage in the Coastal Areas of
California; U.S. Department of the Interior, Minerals
Management Service. http://www.mms.gov/omm/pacific/
enviro/seeps1.htm (accessed October 8, 2005).
2. For more on seeps and oil exploration:
http://www.npagroup.co.uk/oilandmineral/offshore/oil_
exploration/ (accessed October 8, 2005).
3. Brufatto C, Cochran J, Conn L, Power D, El-Zeghaty
SZAA, Fraboulet B, Griffin T, James S, Munk T, Justus F,
Levine JR, Montgomery C, Murphy D, Pfeiffer J,
Pornpoch T and Rishmani L: “From Mud to Cement—
Autumn 2005
Building Gas Wells,” Oilfield Review 15, no. 3
(Autumn 2003): 62–76.
4. For more on the chronology of oil events: http://www.
sjgs.com/history.html#ancient_to_present (accessed
October 8, 2005).
5. For a chronology of oil- and gas-well drilling in
Pennsylvania: http://www.dep.state.pa.us/dep/
deputate/minres/reclaiMPa/interestingfacts/
chronlogyofoilandgas (accessed October 8, 2005).
6. Yergin D: The Prize. New York City: Simon & Schuster, 1992.
7. For more on the history of the Spindletop oil field:
http://www.tsha.utexas.edu/handbook/online/articles/SS/
dos3.html (accessed October 8, 2005).
8. For more on the evolution of seismic technology:
http://www.spe.org/spe/jsp/basic/0,1104_1714_
1004089,00.html (accessed October 8, 2005).
9. Sayers CM, Woodward MJ and Bartman RC: “Seismic
Pore-Pressure Prediction Using Reflection Tomography
and 4-C Seismic Data,” The Leading Edge 21, no. 2
(February 2002): 188–192.
25
Causes of Abnormal Pressure
Normally pressured formations generally
have pore pressure that equals the hydrostatic
pressure of the pore water. In sedimentary
basins, pore water usually has a density of
8.95 lbm/galUS [1,073 kg/m3], which
establishes a normal pressure gradient of
0.465 psi/ft [10.5 kPa/m]. Significant deviation
from this normal hydrostatic pressure is
referred to as abnormal pressure.
Abnormal geopressures, above or below
the normal gradient, are found in many
hydrocarbon-producing reservoirs. While the
origin of these pressures is not understood
completely, abnormal pressure development
is usually attributed to the effects of
compaction, diagenetic activity, differential
density and fluid migration.1 Abnormal
pressure involves both physical and chemical
actions within the Earth. Pressures above or
below the normal gradient may be detrimental
to the drilling process.
Subnormal pressures, or those below the
normal gradient, can cause lost-circulation
problems in wells drilled with liquid drilling
mud. Subnormal pressure conditions
frequently occur when the surface elevation
of a well is much higher than the subsurface
water table or sea level. This is seen when
drilling in hilly or mountainous locations,
but it may also occur in arid regions where
the water table may be more than 1,000 ft
[305 m] deep.
Abnormally low pressures are also
frequently found in depleted reservoirs. These
are reservoirs whose original pressure has
been reduced by production or leakage.
Depletion is not unusual in mature reservoirs
from which significant volumes of oil and gas
have been produced without waterflooding or
pressure maintenance.
By contrast, abnormally high pressures
are typical in most oil-producing regions.
Abnormal overpressures always involve a
particular zone becoming sealed or isolated.
The amount of overpressure depends on the
structure, the depositional environment and
the processes and rate of deposition.
26
Well 1
Well 2
Well 3
Well 4
Well 5
Pressured sand
Pressured sand
Pressured sand
> Pressure isolation by fault displacement. In zones of faulting, pressure-bearing
zones (brown) can be displaced along a fault plane. If adequately sealed, the
displaced zone maintains its abnormal pressure. Although the top of an abnormally
pressured zone may be defined in a given area or structure, faulting can cause
significant changes in formation depth only a short distance away. For the driller, this
not only is confusing but also causes an increased drilling risk.
1. Bourgoyne AT, Millheim KK, Chenevert ME and Young FS:
Applied Drilling Engineering, 1st ed. Richardson, Texas:
Society of Petroleum Engineers, 1986.
2. For more on faulting: Cerveny K, Davies R, Dudley G,
Fox R, Kaufman P, Knipe R and Krantz B: “Reducing
Uncertainty with Fault-Seal Analysis,” Oilfield Review
16, no. 4 (Winter 2004): 38–51.
Oilfield Review
One of the most common mechanisms
generating abnormally high pressures is
trapping of pore water during deposition. If
a seal forms before pore water is displaced,
grain-to-grain contact between solids is not
established. Over time and with increases in
compaction due to overburden pressure, the
water in the pore space becomes compressed,
causing abnormally high pore pressure.
Another cause of abnormally high geopressure is geologic uplifting and displacement
of a formation, which physically relocates a
higher pressured formation from one depth
to another (previous page). When a previously
normal pressure zone at great depth is
displaced by tectonic activity to a shallower
depth with the seals remaining intact, the
resulting pressure will be abnormally high.
Undercompaction during deposition is
another mechanism for generating high
pore pressure. In the Gulf of Mexico and
other depositional basins, compaction
disequilibrium is believed to be the most
important cause of overpressure. For
sediment to compact, pore water must be
expelled. However, if sedimentation is rapid
compared to the time required for fluid to
be expelled from the pore space, or if seals
that prevent dewatering and compaction
form during burial, the pore fluid becomes
overpressured and supports part of the
overburden load.
Artesian systems are a unique source of
abnormally high pressures. In these systems,
the surface elevation of the well is below
sea level or the water table, a condition that
might exist if drilling in a valley between
mountains (above right).
The same principle also applies to
structural situations in which highly dipping
permeable formations allow pressure
transmission from a higher-pressured deep
zone to a shallower depth. Abnormal
pressures caused by structural effects are
common adjacent to salt domes, where the
rising, migrating salt has uplifted the
surrounding formations, tilting them and
sealing the permeable formations.
Autumn 2005
Rain
Rain
Well elevation below water table
Artesian well
Ground level
Permeable sand
Seal
> Artesian pressure system. In these systems, the surface elevation of the well is below sea level or
below the water table. This commonly occurs when drilling in a valley or basin surrounded by hills
or mountains—locations where a connected water table is charged by water from higher
locations.
Overpressures can also occur in shallow
sands if higher-pressured fluids migrate from
lower formations as the result of faulting or
through a seal in a network of microfractures
(below right).2 In addition, man-made actions
can charge upper sands. Poorly cemented
casings, lost circulation, hydraulic fracturing
and underground blowouts can cause
otherwise normally pressured zones to become
abnormally pressured.
Another cause of overpressure is chemical
activity. If massive deposition of organic
material becomes sealed with time and
exposed to higher temperatures, this organic
matter generates methane and other
hydrocarbons that charge the formation.
Increasing depth, temperature and pressure
may cause gypsum to convert to anhydrite,
releasing water that may charge a formation.
Conversely, anhydrite that is exposed to water
may form gypsum, resulting in as much as a
40% increase in volume, thereby increasing
zonal pressures. Pore pressure may also be
increased by the transformation of smectite
to illite at increasing temperature and depth.
As water is expelled from the clay crystal
lattice, pore pressure increases.
Charged sand
Zone of higher
pressure
> Fracture migration. Fault planes may allow
pressure transmission from a zone of higher
pressure to a more shallow, lower-pressured
zone. This results in an abnormally pressured,
or charged, sand. These effects are common
in tectonically stressed environments and
adjacent to salt domes.
27
Pore Pressure from Stacking Velocities
0.5
13.0
1.0
12.5
1.5
12.0
2.0
11.5
2.5
11.0
3.0
10.5
10.0
3.5
16
lbm/galUS
Depth, km
14.0
13.5
9.5
14
9.0
12
10
y, k 8
m
6
6
8
12
10 km
,
x
14
16
Pore Pressure from Tomographic Velocities
0.5
15
1.0
14
1.5
13
2.0
12
2.5
11
3.0
10
3.5
16
lbm/galUS
Depth, km
16
9
14
12
10
y, k 8
m
6
6
8
12
10 km
x,
14
16
8
> Seismic tomography. In previous methods, interpreters stacked seismic
velocities to improve resolution; from this they generated a pore-pressure
cube representing pore pressures across a given area (top). Now,
tomographic techniques dramatically improve pore-pressure resolution,
reducing uncertainty and increasing accuracy in well planning (bottom).
Reflection tomography offers significant
advantages compared with conventional seismic
data. Conventional seismic data processing
smoothes out velocity fluctuations, and velocity
interval picks are often too coarse for accurate
pore-pressure prediction. Reflection tomography
replaces the low-resolution, conventional
velocity analysis with a completely general raytrace modeling-based approach. Although an
interpretable image might be obtained using a
relatively poor but smooth conventional seismicvelocity field, the resolution is sometimes too low
28
to accurately predict pore pressure for wellplanning purposes. By contrast, the tomographically refined velocity model leads to better
understanding of the magnitude and spatial
distribution of pore pressure, reducing the
uncertainty of pore-pressure predictions (above).
Reducing Uncertainty
In areas where the geology is unknown and
where few, if any, wells have been drilled, seismic
geopressure prediction may be the only planning
tool available to the engineer. However, data from
multiple sources, especially drilling, can be used
in conjunction with seismic tomography to refine
models, and reduce risk and cost, while
improving drilling efficiency.
Once wells have been drilled, drillers and
planning engineers have access to additional
data, including mud records, mud logging
information, formation samples, wireline and
while-drilling logs, and formation test data. Tools
such as the MDT Modular Formation Dynamics
Tester sample formation fluids and provide
accurate reservoir pressures.10
Pressures in shale sections above a reservoir
can be estimated based on offset-well mud
weights. Daily drilling reports of problems such as
kicks, lost circulation, differential sticking and
other drilling problems also may indicate the
presence of abnormal pressures. Planning
engineers generally use offset-well data cautiously.
Using mud weights to estimate formation pressure
may be misleading, particularly when the data
come from older wells.
Most wells are drilled in an overbalanced
condition, with mud weights that exceed actual
formation pressure by 1 lbm/galUS [120 kg/m3] or
more. Drillers frequently increase mud weights to
control troublesome, or sloughing, shales.
A more detailed evaluation of geopressure
can be obtained by combining drilling data with
offset-well electric, acoustic and density logs. To
predict pore pressures from wireline or whiledrilling logs, analysts often correlate changes in
shale porosity with the potential presence of
abnormal pressure. This is possible because
shales generally compact with increasing depth
in a uniform manner. Because of this compaction,
the porosity and electrical conductivity decrease
at a uniform rate with increasing depth and
overburden pressure. However, if a seal is
present, higher than normal levels of conductive
connate water may be present, increasing
conductivity and indicating abnormal pressure
(next page, top). Although conductivity is a good
indicator, many variables such as connate-water
salinity, mineralogy, temperature and drillingmud filtrate may also affect electric log response.
Acoustic velocity derived from sonic logs
provides another tool for determining pore
pressure that is less affected by wellbore
conditions. Acoustic tools measure the time it
takes for sound to travel a specified distance. As
formation characteristics change, so do the
velocity and the interval transit time.
Shales with porosities approaching zero may
transmit sound at velocities on the order of
16,000 ft/s [4.88 km/s] and transit times of
62.5 µs/ft [205 µs/m].11 Shales with higher
porosity have more pore space filled with
Oilfield Review
400 600 1,000 2,000
Normal pressure trend line
16
14
13
12
11
10
14
12
10
y, k 8
m
Autumn 2005
6
10
8
6
12
14
x, km
16
9
8
Top of abnormal pressure
> Electric log analysis to reduce the uncertainty of seismic-based pore-pressure predictions. In
normally compacted sediment, electrical conductivity will decrease with depth as water is squeezed
from pore spaces. A deflection in conductivity from the normal trend (dashed circle, left and middle)
may indicate a change in pore-water concentration, hence the potential for abnormal pressure. Using
both seismic and electric log data, computer processing refines the data and generates threedimensional predictive models that help engineers and drillers visualize pore-pressure trends (right).
Change in interval
transient time, µs/ft
200 300
50 70 100
Conductivity, mS
200
0
400 600 1,000 2,000
Normal pressure trend line
1
2
3
Top of abnormal pressure
4
16
5
Depth, km
Depth, 1,000 ft
10. For more on the MDT tool: Crombie A, Halford F,
Hashem M, McNeil R, Thomas EC, Melbourne G and
Mullins OC: “Innovations in Wireline Fluid Sampling,”
Oilfield Review 10, no. 3 (Autumn 1998): 26–41.
11. The unit µs means microsecond, or one millionth of
a second.
12. Sayers CM, Hooyman PJ, Smirnov N, Fiume G, Prince A,
de Leon Mojarro JC, Romero MT and Gonzales OM:
“Pore Pressure Prediction for the Cocuite Field,
Veracruz Basin,” paper SPE 77360, presented at the
SPE Annual Technical Conference and Exhibition,
San Antonio, Texas, USA, September 29–October 2, 2002.
13. Drillers often perform downhole seismic measurements
to provide data for correlation of surface seismic data to
actual downhole conditions. A checkshot measures the
seismic traveltime from the surface to a known depth in
the well. Compressional, or P-wave, velocity of the formations encountered in a wellbore can be measured
directly by lowering a geophone to each formation of
interest, sending out a source of energy from the surface
of the Earth, and recording the resultant signal. The data
are then correlated to prewell surface seismic data by
correcting the sonic log and generating a synthetic seismogram to confirm or modify seismic interpretations.
Mechanical earth models and pore-pressure predictions
can then be updated.
lbm/galUS
Resistivity
15
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Depth
Spontaneous
Potential
(SP)
Depth, km
15
6
7
8
9
10
11
12
13
14
0.5
1.0
1.5
2.0
2.5
3.0
3.5
14
13
12
11
lbm/galUS
Improving Pore-Pressure Predictions in the
Veracruz Basin
Inaccuracies in pore-pressure prediction may
lead to well-control problems, exposing an
operator to undue risk and excessive cost.
Drilling problems in the Veracruz basin, offshore
Mexico, led the operator, Petróleos Mexicanos
(PEMEX), to reevaluate pore-pressure predictions.12 Engineers at PEMEX and Schlumberger
found that predicted mud weights in the Cocuite
field were higher than required, resulting in loss
of circulation and significant cost overruns. To
improve drilling efficiency and reduce risk,
engineers and geoscientists used previously
acquired three-dimensional (3D) surface seismic
data along with sonic logs, mud weights,
checkshot surveys and pressure tests from offset
wells to improve pore-pressure predictions.13
Conductivity, mS
200
Depth
formation water, hydrocarbons, or both. At 30%
porosity, the velocity drops to 12,700 ft/s
[3.87 km/s], and the interval transit time
increases to about 103 µs/ft [338 µs/m]. Normally
pressured shales exhibit decreasing interval
transit times with depth. However, as increased
pore pressure is encountered, the trend will
reverse (below right).
Density logging tools also help engineers
predict geopressures. The tool irradiates a
formation with gamma rays that interact with the
electrons surrounding the borehole. The
intensity of the backscattered gamma rays varies
with bulk density. Since the bulk density of
abnormally pressured shale is less than the
density of normally pressured shale, engineers
can combine predictions made by density,
electric and acoustic measurements with surface
seismic data to better refine models and
reservoir pressure profiles.
10
14
12
10
y (k
8
m)
6
6
8
10
12
m)
x (k
14
16
9
8
15
> Acoustic logs for pore-pressure prediction. Sound waves slow when encountering rock with higher
pore-water concentrations. The top of an abnormally pressured zone can be predicted based on the
change in interval transit time (dashed circle, right), then correlated to changes in conductivity (left).
Both measurements can then be used to reduce the uncertainty of the seismic pore-pressure cube
(center).
29
Before pore pressure can be estimated from
seismic velocities, local knowledge of the total
vertical stress must be obtained. In the area
covered by the Cocuite 3D seismic survey, the
only density log available was from Well Cocuite
402, covering a depth range of 643 to 7,690 ft [196
to 2,344 m]. To estimate the overburden stress to
the required depth of more than 13,000 ft
[3,962 m], density data from the Cocuite 402
density log were combined with other density
information from the Veracruz basin into a
composite density log. This information was then
used to calculate a general overburden stress
gradient for the area. Calculated formation
velocities were verified by comparing them to
sonic logs upscaled to seismic wavelengths and
to seismic interval velocities obtained by inverting traveltime depth pairs from checkshots.
Although reasonable agreement was found
over the intervals for which sonic logs and
checkshots were available, variations in the
velocity field from location to location were
observed (below). Similar variations were seen for
the other wells in the study area. To mitigate these
small-scale variations, geoscientists smoothed the
velocities laterally before converting the seismic
interval velocities to pore pressure. This
technique results in 3D models with a high data
density that are less uncertain than those
acquired with conventional techniques.
Using seismic velocities from the Cocuite 3D
survey and a velocity-to-pore-pressure transform,
engineers optimized drilling operations by
adjusting mud weights. Engineers believe that
further refinement in this pore-pressure
prediction is possible using reflection
tomography to enhance lateral resolution of the
seismic velocities.14
Adjusting Pore-Pressure Predictions
While Drilling
The progression from conventional seismic porepressure prediction to reflection-tomographic
techniques significantly reduced uncertainty
and improved the accuracy of pore-pressure
estimates. However, drilling deep into the Earth
continued to be fraught with uncertainty.
During well construction, drillers strive to
balance mud weight and formation pressure,
often based solely on indirect measurements or
indicators. Real-time drilling parameters are
closely monitored for changes in penetration
rate, gas shows and the condition of cuttings
returning to the surface, along with signals
transmitted from measurements-while-drilling
(MWD) and logging-while-drilling (LWD) tools.
Schlumberger geophysicists developed a
technique for updating uncertainties in the
predicted velocities and pore pressures while
drilling.15 This technique evaluates uncertainties
in the predicted pore pressure on the basis of
0
1
2
U S A
4 101
102
15
12
10
Cuatas #1
4.0
3
402 405
403
13 6
Depth, km
3
1
5
1
9
2
10
1
2
3
Velocity, km/s
4
5
3
15
10
y,
k
m 5
0 0
5
10
x, km
e
f M
Gulf o
xic
o
2.0
0
1.8
1
2
1.6
3
M E X I C O
1.4
4
600
Cocuite field
Inli 400
ne
num 200
ber
600
400
200
n
ine
sl
Cros
Pore-pressure gradient, g/cm3
4
15
Depth, km
Depth, km
Velocity, km/s
2.0
6
8
3.5
2.5
5
7
0
3.0
4
1.2
er
umb
> Comparison of P-wave interval velocities. Data (top right) obtained by upscaling the sonic log (green curve) and by inverting traveltime-depth pairs from
the checkshot (red curve) in Cocuite Well 101 are compared with the seismic interval velocities (blue dots) for all locations surveyed in the Cocuite field
study. From this information, engineers generated a seismic interval velocity 3D cube (left) and a pore-pressure gradient cube (bottom right) showing a
transition zone around 3 km [9,843 ft]. This cube helped to define lower and upper formation-pressure limits.
30
Oilfield Review
2
500
500
1,000
1,000
1,500
1,500
Depth, m
Depth, m
1
2,000
2,000
Sonic
2,500
2,500
3,000
3,000
1,500
2,000
2,500
Vp, m/s
3,000
1,500
10
15
20
Pore-pressure gradient, lbm/galUS
3,000
10
15
20
Pore-pressure gradient, lbm/galUS
4
3
500
500
Mud weights
1,000
1,500
2,000
1,500
2,000
Sonic
2,500
3,000
3,000
2,000
2,500
Vp, m/s
Porepressure
data
Sonic
2,500
1,500
Mud weights
1,000
Depth, m
Depth, m
2,000
2,500
Vp, m/s
3,000
10
15
20
Pore-pressure gradient, lbm/galUS
1,500
2,000
2,500
Vp, m/s
3,000
10
15
20
Pore-pressure gradient, lbm/galUS
> Reducing uncertainty. The degree of uncertainty in a pore-pressure gradient is exemplified by the width and low resolution of the compressional-velocity
(Vp) and pore-pressure gradient curves (1). Vp data from sonic logs are added to the model, somewhat reducing pore-pressure uncertainty (2). Adding mud
weights from drilling reports (3) and physical pore-pressure measurements (4) refines estimates and dramatically improves pore-pressure resolution.
borehole-seismic, well-logging and pressure
measurements acquired while drilling. The
technique was evaluated on two wells in the Gulf
of Mexico, USA.
14. Sayers et al, reference 12.
15. Malinverno A, Sayers CM, Woodward MJ and
Bartman RC: “Integrating Diverse Measurements to
Predict Pore Pressures with Uncertainties While
Drilling,” paper SPE 90001, presented at the SPE Annual
Technical Conference and Exhibition, Houston,
September 26–29, 2004.
Bryant I, Malinverno A, Prange M, Gonfalini M, Moffat J,
Swager D, Theys P and Verga F: “Understanding Uncertainty,” Oilfield Review 14, no. 3 (Autumn 2002): 2–15.
Autumn 2005
The process involved establishing baseline
uncertainties in the coefficients of the velocity to
pore-pressure relationship from compressionalwave velocity and density. When drilling began,
uncertainties were completely defined by
baseline values (above).
As drilling progressed on the first evaluation
well, a checkshot survey provided data for
velocity structure calibration, allowing geophysicists to refine baseline projections and decrease
the uncertainty in velocity and pore-pressure
predictions. A relatively small decrease in
velocity uncertainty resulted, due to the small
size of the checkshot dataset, which comprised
traveltime measurements acquired at variable
intervals of 50 to 200 m [164 to 656 ft].
After initial logging, engineers incorporated
sonic log data to further refine the pressure
profile. This additional information markedly
reduced velocity uncertainty and gave a
correspondingly more detailed pore-pressure
prediction. The improved pore-pressure
31
> The StethoScope 675 tool. The tool is 31-ft [9.1-m] long; it has a 6.75-in. collar with an 8.25-in. stabilizer
or optional 9.25-in. stabilizer. The stabilizer is made up of a four-blade spiral section at the bottom and
two straight blades at the top. The packer and probe are mounted in the blade of the stabilizer
(black). The stabilizer blade rests, or is pressed, against the formation by gravity or by force applied
by the drillable setting piston (not shown), negating the need to orient in holes up to 10.5 in. for the
8.25-in. stabilizer tool. The probe can extend out of the blade by 3⁄4 in., but normally only moves out
level with the surface of the blade and is compressed against the formation to make the seal. The
probe is then opened to the formation to take a pressure measurement. The retainer ring (Q-shaped
piece around black packer) minimizes deformation of the packer during a test, helping to maintain an
effective seal (inset).
prediction continued to have a level of uncertainty
that could be reduced only by incorporating
measured pore-pressure data. In the absence of
direct pore-pressure measurements, mud weight
was used to represent pore-pressure boundaries.
On the second test well, relatively low
velocities were inferred from surface seismic
data below 1,500 to 2,000 m [4,921 to 6,562 ft],
corresponding to predicted overpressure.
Geophysicists incorporated sonic log data to
reduce uncertainty. Although pore-pressure
predictions improved, the inclusion of mud
weights and direct pore-pressure measurements
calibrated the coefficients in the velocity to porepressure relationship and placed an upper
boundary on the predicted pore pressures.
Initially, the pore-pressure gradient from
1,500 to 2,000 m was estimated to be above
13 lbm/galUS [1,560 kg/m3], using porepressure predictions based solely on surface
seismic data, checkshot values and sonic logs.
With the inclusion of MDT pore-pressure
measurements, the calibrated pore-pressure
prediction constrained the equivalent pore
16. Pop J, Laastad H, Eriksen KO, O’Keefe M, Follini J-M and
Dahle T: “Operational Aspects of Formation Pressure
Measurements While Drilling,” paper SPE/IADC 92494,
presented at the SPE/IADC Drilling Conference,
Amsterdam, February 23–25, 2005.
32
pressure to less than 13 lbm/galUS. Uncertainty
was reduced, allowing drillers to better control
mud weights, define casing points and improve
overall drilling efficiency.
Measuring Reservoir Pressures
After drilling, concerns regarding pressure
usually switch to reservoir management and
production operations. Understanding pressures
in the reservoir ultimately impacts production
and payout, and today may even provide guidance
to place additional wellbores for optimized
production. Operational demands dictate how
and when pressure measurements are
performed, with many methods and tools being
available to measure and monitor reservoir
pressures at almost any time during a well’s life
cycle. As described above, the understanding of
pressure begins with predrill estimates from
seismic data and offset wells, and is further
refined during drilling. Reservoir and production
engineers make additional measurements using
logging tools or permanent sensors in the well or
at surface.
Some of the many ways reservoir engineers
use precise pressure measurements are for fluid
identification and typing, defining fluid contacts
and assessing reservoir continuity. Obtaining the
required measurement precision involves use
of services such as the MDT tool, the
PressureXpress reservoir pressure while logging
service or while-drilling formation-pressure
tools. In these services, high quality data are
obtained by allowing time for pressure
stabilization before the measurement, by
allowing sufficient time for the pressure within
the tool to equilibrate with the pressure in the
formation and by obtaining a large number of
pretests to establish fluid gradients.
Later, in mature reservoir environments
where substantial production has taken place,
formation-pressure measurements are used to
quantify depletion, to assess pressure support or
to further analyze reservoir continuity. Even
though the accuracy requirements of pressure
measurements may not be as strict in mature
reservoirs, the ability to measure pressures over
a wide range of formation permeabilities may be
critical for increasing hydrocarbon recovery.
While-Drilling Pressure Measurement
in Norway
Although borehole seismic techniques have
brought the driller closer to understanding and
predicting pore pressures in real time, scientists
and engineers continue to develop tools for
obtaining direct pressure measurements while
drilling. As LWD technology advanced, engineers
adapted the CQG Crystal Quartz Gauge and
strain-gauge pressure sensor technologies used
in other pressure tools, such as the MDT system,
to real-time, while-drilling, pressure-sensing
tools (see “Quartz Pressure Sensors,” next page].
Engineers at Statoil and Schlumberger field
tested the new StethoScope formation pressurewhile-drilling service in 2004 in several fields
located offshore Norway.16 The goal of field
testing was to establish whether a while-drilling
formation-pressure measurement could be of
comparable quality to wireline MDT tester
measurements given the range of permeablities,
well conditions and mud properties encountered
in these fields.
All formation tester tools measure pore
pressure at the interface between the external
filtercake and the wellbore wall, or sandface.
Whether or not the pressure at the sandface is a
good estimate of the true, far-field formation
pressure depends not only on the properties of
the mud, the filtercake and the formation, but
also on the drilling-fluid circulation-rate history.
Oilfield Review
If the filtercake is totally ineffective in
sealing between the formation and test probe,
then wellbore pressure will be measured; if the
filtercake provides a perfect seal, given sufficient
time, the tester should measure the true
formation pressure.
In most drilling situations, filtercakes are
neither perfect nor uniform in composition.
During the course of normal drilling operations,
the filtercake is eroded by mud circulation,
scraped away during trips, and then rebuilt at
the borehole face. Laboratory experiments with
both water-base and oil-base muds indicate that
dynamic wellbore conditions influence the mudfiltration rate into the formation and, by
implication, the pressure measured at the
sandface. A leaking filtercake is frequently a
problem and may result in significant differences
between measured and true formation pressures.
When the difference between the measured
sandface pressure and the true formation
pressure is significant, the formation is usually
said to be supercharged. This situation may
occur in both while-drilling and conventional
wireline-conveyed methods of measurement, but
may be more common in a while-drilling method
due to the dynamic environment.
To improve confidence in pressure
measurements, the StethoScope tool was
designed with a pressure-measurement probe
embedded in a stabilizer blade surrounded by an
elastomeric sealing element, or packer (previous
page). The stabilizer design maximizes the flow
area at the cross section of the probe, diverts the
flow away from the probe-to-formation interface,
and minimizes the mud velocity in the vicinity of
the probe, thereby helping to reduce filtercake
erosion and filtrate leakage into the formation
while testing. A drillable setting piston is
employed to push the stabilizer containing the
probe against the formation face.
The tool draws power from a downhole MWD
turbine. Additional power is provided by a
battery, capable of fully operating the formationpressure-while-drilling tool, for example during
tests, when the pumps are off. Sandface
pressures are measured by two drilling-qualified
pressure gauges: a proprietary, ruggedized CQG
pressure sensor and a strain-gauge sensor. A
second strain-gauge pressure sensor, located
near the probe, measures wellbore pressure
continuously. All data acquired during formation
tests are stored in tool memory, including
pressures, temperatures, actual pretest volumes
and drawdown rates, and tool-related state and
Autumn 2005
Quartz Pressure Sensors
Quartz is one of several minerals that display
piezoelectric properties. When pressure is
applied to a quartz crystal, a positive
electrical charge is created at one end of the
crystal and a negative charge at the other.
Quartz crystals are also strongly pyroelectric;
temperature changes cause the development
of positive and negative charges within
the crystal.
A correctly cut quartz crystal has a
resonant frequency of vibration, similar to a
tuning fork. As the quartz vibrates, there is a
detectable sinusoidal variation in electrical
charge on its surface. Pressure-induced
stress applied to the crystal causes the sinewave frequency to vary in a predictable and
precise manner. These properties make
quartz valuable in many electronics and
sensing applications, including oilfield
pressure sensors.
Researchers at Schlumberger-Doll
Research in Ridgefield, Connecticut, USA,
began work on a highly sensitive pressure
gauge based on the unique properties of
quartz crystals in 1980, and proposed the
dual-mode oscillation concept that became
fundamental to the development of the CQG
Crystal Quartz Gauge sensor (above right).1
The project was transferred to SchlumbergerFlopetrol, Melun, France, in 1982. The
development team was supported by
researchers at Ecole Nationale Supérieure
de Mécanique et des Microtechniques,
Besançon, France.
Pressure sensors are sensitive to
temperature and pressure variations, and
must be corrected for temperature
fluctuations. The CQG gauge improved on
1. Two mechanical oscillation modes are excited and
maintained by the electronics in the CQG resonator
plate. One is more sensitive to lateral stresses
caused by pressure applied on the sensor; the
other is more sensitive to temperature variations.
These two resonance frequencies provide
simultaneous information on pressure and
temperature and allow computation of a temperaturecorrected pressure measurement.
> Sensor for making temperaturecompensated pressure measurements. The
crystal blade CQG sensor (gold) is a dualmode resonator with one mode dependent on
applied pressure and a second dependent on
the applied temperature. The pressure and
temperature measurements are taken at
exactly the same time.
previous crystal pressure transducers by
providing both temperature and pressure
measurements from a single sensitive
element, eliminating problems associated
with thermal lag between separate pressure
and temperature sensors. This sensor
produces a small peak error induced by
transient conditions. Transient errors are
further minimized by a dynamic temperature
compensation algorithm based on a simple
model of the sensor. CQG sensors operate
efficiently at pressures ranging from 14.5 to
15,000 psi [0.1 to 103.4 MPa] and in a temperature range of 77 to 300°F [25 to 150°C].
In 1989, the CQG sensor was optimized for
commercial fabrication and applied to
numerous oilfield pressure-sensing applications, including the MDT tool. More recently,
the CQG sensor was ruggedized for LWD and
MWD applications, and today it is the primary
pressure sensor in both the StethoScope
tester and the PressureXpress tool.
33
Pretest 2
Pretest 1
Mobility
(mD/cP)
A: ≥ 0.1
Rate,
cm3/s
Volume,
cm3
Buildup
time, s
Rate,
cm3/s
Volume,
cm3
Total
time, s
0.2
2
450
0.2
0.5
900
B:
≥1
0.3
5
100
0.3
6.0
300
C:
≥ 10
0.5
10
100
1.0
15.0
300
1.0
10
60
2.0
15.0
180
D: ≥ 100
1,800
Wellbore pressure
1,600
Pretest 1
Pretest 2
Pressure, psi
1,400
1,200
1,000
800
Pumps off
Pumps on
600
100
200
300
400
500
Elapsed time, s
600
700
800
> Fixed-mode pretests, A through D, with two drawdown-buildup pairs.
Parameters are chosen to cover a wide formation-fluid mobility range (top).
The parameters specify the volumes employed and the duration of the
buildups for Pretest 1 (the “investigation” pretest) and Pretest 2 (the
“measurement” pretest). The graph (bottom) demonstrates the StethoScope
tool response when testing a 1.5-mD/cP limestone formation using a pretest
sequence similar to that of fixed-mode Type B. During this test, the second
buildup was extended, allowing engineers to observe the pressure
stabilization time across a longer than normal test sequence. There is a
variance in the sandface pressure measurement when performing the
measurement with pumps on (red) at a rate of 1,363 L/min [360 galUS/min],
and with pumps off (blue).
2,000
First estimate of
formation pressure
1
Pressure, psi
3
5
Pressure
data
Final estimate of
formation pressure
1,000
2
Investigationphase pretest
Measurementphase pretest
4
0
0
100
200
300
400
500
Time, s
> Pressure data in real time. In this field-test example, pressure data, presented
as open triangles, are displayed in real time at surface during a 5-minute
time-limited pretest performed with the mud pumps on, circulating at a rate
of approximately 600 galUS/min [2,271 L/min]. The telemetry rate for this test
was 6 bits/s. The colored circles represent the principal event markers
identified as the data are acquired. The first event marker (1) identifies the
well pressure prior to the test; the second marker (2) indicates the beginning
of buildup for the investigation phase; the third marker (3) shows the
investigation-phase, sandface-pressure estimate; the fourth marker (4)
identifies the beginning of buildup for the measurement phase; and the fifth
marker (5) represents the sandface pressure as determined during the
measurement phase. The formation fluid mobility was determined to be
approximately 1.4 mD/cP.
34
operating information. The tools have sufficient
memory to store more than 80 five-minute
pressure tests.
When acquiring formation pressures and fluid
mobilities, engineers may choose between two
different modes of operating the pretest: an
optimized pretest sequence or fixed-mode
pretest sequence.17 An optimized, or timelimited, pretest consists of a small initial pretest
during which the formation is tested to
determine its dynamic properties, followed by
one or more, preferably larger-volume, optimized
pretests. The optimized pretests are designed
downhole by the tool’s logic systems using
information obtained from previous tests so that
at the end of a prescribed test time, multiple
stabilized sandface pressures have been
achieved. Only as many tests are performed as
will deliver stabilized pressures in the prescribed
time; for formations with low mobilities, this may
result in a single drawdown.
In the field-testing stage, offshore Norway,
fixed-mode pretests were employed. Four fixedmode pretest sequences that utilize different
preset test parameters are available in the
StethoScope tool (left). Each fixed-mode pretest
sequence comprises two drawdown and buildup
pairs designed to deliver two stabilized sandface
pressures within a specified time frame,
generally 5 minutes. When consistent, these two
independent pressure measurements per test
location, or station, together with an estimate of
the formation fluid mobility, give confidence in
the final pressure result. Comparison of the two
pressures obtained in conjunction with the
computed mobility can reveal the effects of a
static or dynamic pressure environment. An
order of magnitude estimate of the formation
fluid mobility is helpful in deciding which
particular fixed-mode sequence to employ in any
given situation, but there is sufficient overlap in
their ranges of application that this decision is
not critical.
Communication to and from the tool is by
means of the TeleScope high-speed telemetrywhile-drilling service, specifically designed to
provide increased data rate and bandwidth for
data delivery. A special telemetry protocol for use
with the Telescope telemetry system allows a
single device, such as the StethoScope tool, to
monopolize data transmission when it has a large
amount of data to transmit over a short time
interval. The combination of the TeleScope
system and on-demand data transmission allows
StethoScope data to be visualized at surface in
real time (left).
Oilfield Review
Autumn 2005
600
While-drilling tool
Test 6: 1,850 to 2,250 L/min
550
500
Start of change
in circulation
450
Pressure, bar
400
350
300
While-drilling tool
Test 5: 2,262 L/min
While-drilling tool
Test 7: No circulation
250
MDT test: 20 cm3 at 20 cm3/min
200
0
100
200
300
400
500
Time, s
407
While-drilling tool
Test 6: 1,850 to 2,250 L/min
406
While-drilling tool
Test 5: 2,262 L/min
405
Pressure, bar
During field testing, the performance of the
tool in both low-mobility (less than 0.2 mD/cP)
and high-mobility (more than 350 mD/cP)
formations was evaluated, with most data
acquired being compared with wireline MDT
pressure data and cores. Tests were conducted in
a vertical well, highly deviated wells (up to 75°)
and a horizontal well, with circulation rates
ranging from pumps off to 2,300 L/min
[600 galUS/min]. To assess the effects of time
elapsed since drilling, pressure measurements
were taken from one hour to 43 hours after the
bit penetrated the test depth. While-drilling
pressures were compared with those obtained
with a MDT tester up to 24 days after the whiledrilling measurements.
Field tests in Norway established that realtime pressure measurements made by the
StethoScope tool are comparable to those made
by wireline MDT testers under similar
permeability, mud type and borehole conditions.
In general, the most accurate pressure
measurements were obtained in formations with
the highest mobility, with pumps off, or when
using a circulation rate that was as low and as
constant as possible, and while tripping out of
hole (right). Measurements made during the
drilling process should be repeated at selected
stations while tripping out to confirm the
pressure values obtained, especially if
supercharging is suspected.
Engineers determined that for formations
having fluid mobilities below 5 mD/cP, there is a
distinct advantage to acquiring sandface
pressures with pumps off. The degree of
supercharging as a function of circulation rate
depends directly on the amount of time since the
filtercake was mechanically disturbed. High
circulation rates can promote the erosion of an
established filtercake, yielding supercharged
sandface pressures even after a lengthy period
between drilling and the pressure test. It is not
always safe to assume that the supercharging
effect decreases with time after drilling. Timelapse data are important in identifying dynamic
supercharging in formations with low mobilities.
The field test conducted by Statoil and
Schlumberger in the North Sea yielded positive
results. The StethoScope tool demonstrated its
ability to accurately measure formation pressures
in real time without needing to orient the tool or
incurring excessive nonproductive time. In
formations where the mobility is sufficiently high,
5 mD/cP or more, the StethoScope measurements
are of the same quality as those acquired with the
MDT tool. Today, both tools are helping engineers,
404
403
Start of
change
in circulation
While-drilling tool
Test 7: No circulation
402
MDT test
401
150
200
250
300
350
400
450
Time, s
> Measuring pressure in a low-mobility formation. Three StethoScope test sequences (top) were
conducted at the same depth under different mud-circulation rates in a 3-mD/cP formation: a rate of
2,262 L/min [597 galUS/min] (Test 5); a changing rate from 1,850 to 2,250 L/min [489 to 594 galUS/min]
(Test 6); and a test with pumps off (Test 7). All of the while-drilling tests are of pretest Type C. For
comparison, a single-pretest MDT tester conducted some 24 days after the StethoScope tests is
displayed. The graph (bottom) shows details of the final buildup. Here the effects of the dynamic
wellbore can be clearly seen by comparing the while-drilling tests with pumps on and pumps off with
the MDT tool test, in which the filtercake should have reached maximum resistance.
geologists and drillers quickly make decisions,
reduce drilling uncertainty and save time
and money.
While-Drilling Reservoir Pressure in
the Gulf of Mexico
In deepwater drilling and production environments, operators strive to reduce risk, uncertainty
and cost. An example is the Ram Powell
Production Unit, operated by Shell Offshore.
Covering eight blocks in the Viosca Knoll area,
eastern Gulf of Mexico, USA, wells are located in
2,000- to 4,000-ft [609- to 1,219-m] water depths,
about 125 miles [200 km] east-southeast of New
Orleans. Production began in September 1997,
making it one of the most mature deepwater oil
fields in the Gulf of Mexico.18
17. Pop J, Follini J-M and Chang Y: “Optimized Test
Sequences for Formation Tester Operations,” paper
SPE 97283, presented at Offshore Europe 2005, Aberdeen,
September 6–9, 2005.
18. Volokitin Y, Stachowiak J and Bourgeois T: “Value of
Specialized While Drilling Measurements: Recent
Experience in Ram/Powell, GOM,” Transactions of the
SPWLA 46th Annual Logging Symposium, New Orleans,
June 26–29, 2005, paper C.
35
Five commercial sands between 5,500- and
13,500-ft [1,676- and 4,114-m] subsea true
vertical depth (TVD) are responsible for most of
the Ram Powell production. Geologists and
engineers reevaluated the field between 2001
and 2003, including time-lapse seismic
surveys that identified potentially undrained
infill-drilling opportunities.
In January 2004, Shell initiated redevelopment activities. Engineers found a high degree
of risk and uncertainty in the new drilling
projects. New well targets required drilling
complicated directional wells. Production had
also depleted several pay sands, rendering them
unstable and difficult to drill. Although these
circumstances made formation evaluation more
difficult, the added uncertainty increased the
need for formation evaluation while drilling.
To reduce cost and improve efficiency, Shell
and Schlumberger engineers planned to use LWD
and MWD technologies to evaluate the reservoir
and drilling environment in real time on Well 2 of
the redevelopment campaign. Engineers selected
a bottomhole assembly (BHA) consisting of a
PowerDrive Xtra rotary steerable system, a suite
of 6.75-in. VISION Formation Evaluation and
Imaging While Drilling tools, and the StethoScope
tool components—all positioned below a hole
opener. The VISION suite included an
arcVISION675 6 3⁄4-in. drill collar resistivity tool,
an adnVISION675 6.75-in. Azimuthal Density
Neutron tool and a proVISION675 6.75-in.
nuclear magnetic resonance (NMR) tool. The
TeleScope telemetry service provided real-time
data transmission and control.
Engineers planned to use the pressure data
acquired by the StethoScope tool for completion
design and to verify dynamic reservoir models.
Obtaining formation pressure measurements
while drilling reduced both rig cost and borehole
exposure times, and allowed reservoir engineers
and geologists to make timely wellplacement decisions.
After the driller set 11 3⁄4-in. casing at 10,474-ft
[3,192-m] measured depth (MD), the initial
10 5⁄8-in. hole section was drilled at an inclination
of about 45° from 10,514- to 15,688-ft [3,205- to
4,782-m] MD. Shell’s petrophysicist selected the
formation pressure-measurement points using
data from the density neutron tool to determine
the location of target sands. When on station,
the StethoScope tool automatically began a
drawdown-wait-retract sequence. After each
pressure measurement, the probe was retracted
and the tool was moved to the next station.
On-station time averaged 10 minutes or less
per measurement.
36
Real-time formation pressure measurements
showed good pressure support within the
reservoir and confirmed that the low-resistivity
zone at the bottom of the target sand was swept
oil, indicating a higher than expected oil/water
contact. Using this real-time data, Shell engineers
decided to sidetrack the well. The new hole was
placed higher in the reservoir by drilling updip
from 11,501- to 16,952-ft [3,506- to 5,167-m] MD
at 58° inclination. The pressure measurements
Sidetrack
Original Well
40-in. Blended
Attenuation Resistivity
40-in. Blended
Attenuation Resistivity
0
10 0
10
adnVISION
Bottom Quadrant Density
adnVISION
Bottom Quadrant Density
g/cm3
g/cm3
1.65
2.65 1.65
Photoelectric Factor
0
b/e
20 0
Gamma Ray
Hydrostatic
Pressure
30 psi per division
Formation Pressure
200 psi per division
4
3
5
6
7
8
11
150 0
Neutron Porosity
0.6
%
20
gAPI
150
Neutron Porosity
0 0.6
%
0
4
5
6
7
8
9
12
11
12
XX,800
9
1110
13
1
1
2
2
5
XX,900
5
6
7
6
7
11
11
10
13
gAPI
b/e
Gamma Ray
3
13
9
0
Depth
2.65
Photoelectric Factor
10
9
8
XY,000
13
Sidetrack
Original well
> Using adnVISION data to help pick pressure stations. Density data from the adnVISION675 logging
tool (Tracks 3 and 4 - red) helped select locations, or pressure stations, to be tested with the
StethoScope pressure tool. Tracks 1 and 2 show formation and hydrostatic pressures, respectively,
from the original hole (red circles) and the sidetrack (green circles). Zones with lower density have
higher porosity and fluid mobility.
Oilfield Review
> Wireline pressure-measurement tool. The PressureXpress tool diameter and profile are designed to reduce the risk
of sticking. Shown are the sampling seal system (black) and the backup anchoring pistons (top image – lower side)
used to push and hold the tool in position at the formation face.
confirmed good connectivity within the reservoir,
so casing was run to total depth.
The proVISION675 NMR data helped engineers
calibrate net-sand calculations and improve the
petrophysical evaluation of laminated sands.
Combining while-drilling data from NMR with data
from other LWD tools provided important
information on rock texture, permeability, grain
size and net sand. NMR fluid-property data were
used with formation pressure and fluid mobilities
to estimate formation permeability.
In total, 26 pressure measurements were
made—13 while drilling the initial section and
13 while drilling the sidetrack. Pressure
measurements provided critical information for
making sidetrack and completion-design decisions.
Pressures were successfully acquired in both
massive and laminated sands (previous page).
Advances in MWD technologies now provide
pressure and fluid-mobility measurements that
were previously available only with wireline logs.
Engineers can perform complex evaluations
based on MWD data alone, significantly reducing
the risk, cost and uncertainty of drilling
deepwater development wells.
Engineers estimate that formation pressure
while drilling and associated measurements
saved more than US$1 million by eliminating the
Autumn 2005
need for two conventional drillpipe-conveyed
pressure-measurement runs. In addition, whiledrilling NMR data provided important
information regarding fluid viscosity and rock
texture for net-sand calculation as well as
permeability and grain-size estimations, which
were used in the completion design. Shell plans
to continue using pressure-while-drilling and
other real-time technologies to improve
efficiency and reduce risk, particularly on
challenging deepwater projects.
Quick and Precise Reservoir Pressures
Wireline-conveyed formation-testing measurements have long been recognized as key to
collecting essential information to help identify
fluids in place, pressure regimes and dynamic
properties of a reservoir. Although they measured
formation pressures accurately, previous
techniques required that a wireline tool be
stationary for relatively long periods of time
while testing the formation. This is particularly
true in low-mobility zones where longer
evaluation times increase the cost and risk of
tool sticking.19 Now, reservoir engineers have
options that provide fast and accurate pressure
measurements. Tools such as the PressureXpress
service quickly make multiple, highly accurate
pressure measurements.
Engineers at the Schlumberger Riboud
Product Center in Clamart, France, integrated
advanced versions of the CQG gauge and the
Sapphire pressure gauge into the PressureXpress
tool. These pressure sensors provide highresolution pressure measurements, dynamically
compensated for temperature (above).
Earlier formation testing tools relied on
hydraulically driven pretest systems that were
monitored and controlled from surface. The lag
time between surface commands and changes in
the downhole hydraulic-sampling actuator
limited pretest volume control. The system was
redesigned, replacing the hydraulic system with
an electromechanical motor coupled to a
planetary roller-screw mechanism and highreduction gearbox, greatly enhancing the
stability and accuracy of both the pretest rate
and volume. Transferring the controls and
commands from the surface to the downhole
electronic cartridge improved the response time,
making it possible to achieve pretest volumes as
low as 0.1 cm3 [0.006 in.3].
19. Manin Y, Jacobson A and Cordera J: “A New Generation
of Wireline Formation Tester,” Transactions of the
SPWLA 46th Annual Logging Symposium, New Orleans,
June 26–29, 2005, paper M.
37
AIT H 30-in. Investigation
Test is Not Recommended
0.2
ohm.m
2,000
AIT H 60-in. Investigation
Tight
0.2
Permeability
Volume of Clay
0
—
Slow Pretest
Computed
Micro Normal
0.2
Gamma Ray
0
gAPI
ohm.m
20
150 0
Env. Corr. Thermal Neutron Porosity (TNPH)
ohm.m 10
Computed
Micro Inverse
ohm.m 10
Gas Effect From DPHZ to TNPH
2,000
AIT H 20-in. Investigation
0
in.
2,000
AIT H 10-in. Investigation
1
Caliper
0
ohm.m
Normal Pretest
0.2
AIT H
Water
Saturation
ohm.m
2,000
0.6
AIT H 90-in. Investigation
%
0
Std. Res. Density Porosity (DPHZ)
Fast Pretest
0.2
ohm.m
2,000
0.6
%
0
> Locating pressure-test stations while logging. During the running of the combination
PlatformExpress integrated wireline logging tool and the PressureXpress tool, a real-time estimate of
formation fluid mobility is output using the k-lambda correlation, a permeability estimator for
siliciclastics. Engineers use this information to help select zones for pressure testing (Track 5). The
data output also helps select an appropriate pretest flow rate and volume that minimize time on
station during the subsequent formation pressure-test operations.
20. For more on time-lapse seismic monitoring: Alsos T,
Eide A, Astratti D, Pickering S, Benabentos M, Dutta N,
Mallick S, Schultz G, den Boer L, Livingstone M,
Nickel M, Sønneland L, Schlaf J, Schoepfer P,
Sigismondi M, Soldo JC and Strønen LK: “Seismic
Applications Throughout the Life of the Reservoir,”
Oilfield Review 14, no. 2 (Summer 2002): 48–65; and
Aronsen HA, Osdal B, Dahl T, Eiken O, Goto R,
38
Khazanehdari J, Pickering S and Smith P: “Time Will Tell:
New Insights from Time-Lapse Seismic Data,” Oilfield
Review 16, no. 2 (Summer 2004): 6–15.
21. Burgess K, Fields T, Harrigan E, Golich GM,
MacDougall T, Reeves R, Smith S, Thornsberry K,
Ritchie B, Rivero R and Siegfried R: “Formation Testing
and Sampling Through Casing,” Oilfield Review 14, no. 1
(Spring 2002): 46–57.
Formation testers have traditionally been run
alone or on the bottom of a wireline toolstring,
because of their inability to pass the telemetry of
other wireline tools. Implementation of new
through-wiring hardware and a new software
telemetry system now permits combinations with
all other wireline tools, which can be run
anywhere above or below the new tool.
Through 2004, the PressureXpress service
was field-tested on a total of 57 jobs, and more
than 1,300 pretests were performed, in a wide
variety of environments, including sandstone and
carbonate formations (left). These involved
formation fluids varying from gas to heavy oil
under steam recovery. Bottomhole temperatures
ranged from approximately 100 to 310°F [38 to
154°C], at hydrostatic pressures of 0 to 13,000 psi
[0 to 90 MPa].
Engineers incorporated the Smart Pretest
dynamically controlled intelligent pressure
testing system to automatically find the best
possible compromise between the formationproduced volume and the pressure-buildup time.
In formations with fluid mobilities greater than
about 1 mD/cP, the new tool can perform a
pressure and mobility test in less than one
minute: this represents an improvement of as
much as four to five minutes over other testers.
In tight formations, the pretest system can select
fluid volumes as low as 0.1 cm3, allowing minimal
test times (next page, top).
In some areas of Texas, tight gas-bearing
sandstone reservoirs may have permeabilities
ranging from a few microdarcies to tens of
millidarcies. In these fields, gas production relies
on hydraulic fracturing to provide the conduit for
reservoir flow. Many of these areas are mature
and partially depleted, resulting in large
pressure differences between reservoir layers.
Determining these pressures accurately is key to
optimizing hydraulic-fracturing programs.
Failed attempts to measure pressures with
conventional tools led to fracturing the entire
reservoir thickness, including depleted zones,
resulting in unnecessary completion expenses
and lost production. For one well, Schlumberger
engineers used the PressureXpress service; 58
pretests were attempted and 56 formation
pressures were measured in less than seven
hours. Data obtained from the testing program
identified zones in the mid-reservoir section
depleted by as much as 4,000 psi [27.6 MPa],
while the last 500 ft [152 m] of pay was still at a
Oilfield Review
relatively high pressure (below right). Engineers
designed a four-stage hydraulic-fracturing
stimulation procedure. Six fewer stages were
pumped than on previous wells, yet production
increased by more than 50%, saving the operator
more than US$ 400,000 in fracturing costs.
4,400
Mud pressure before test, psi:
Mud pressure after test, psi:
Last buildup pressure, psi:
Drawdown mobility, mD/cP:
4,200
Pressure, psi
4,436.22
4,428.86
3,809.33
0.01
4,000
3,800
3,600
3,400
3,200
0
100
200
300
400
Time, s
500
600
700
800
> An electromechanical pretest system to reduce time on station. At time 0 s, the PressureXpress tool
is on station and because it is not yet set, the flowline pressure is reading the wellbore mud pressure,
approximately 4,430 psi [30.5 MPa] (black square, left). The tool is then hydraulically set,
corresponding to an increase in the hydraulic pump velocity (green). The pressure curve (black)
measures a pretest drawdown in a 0.01-mD/cP formation at about 45 s, followed by a gradual
pressure buildup. After about 200 s, the tool initiated a second pressure drawdown (red triangles),
extracting a volume of 0.1 cm3 of fluid from the formation. From 280 s to 680 s, reservoir pressure
stabilized, then the tool was hydraulically retracted from the formation (green curve), and the flowline
pressure increased to the wellbore mud pressure. By using an electromechanical motor, the
pressure-testing tool accurately controls the pretest volume and rate at low values (0.1 cm3),
effectively reducing buildup duration and time on station.
8,500
Mud gradient, 0.493 psi/ft
9,000
9,500
Depth, ft
Managing Reservoir Pressures
Geopressures drive oil from a reservoir to a
producing wellbore. As production starts, a
pressure drop in the formation around the
wellbore causes oil to flow through pore networks
in the reservoir toward the point of withdrawal.
With oil withdrawal and subsequent pressure drop
in the reservoir, the oil, water and rock expand.
Changes in pressure, expansion and movement of
all these materials influence oil production.
Once a reservoir is producing, engineers and
geophysicists use various techniques to monitor
the movement of fluids and changes in pressure.
Recent advances in seismic imaging allow
acquisition of 3D surveys over time, known as
time-lapse or four-dimensional (4D) seismic
surveys.20 Understanding the movement of fluids
and changes in reservoir pressures allows
engineers to better model reservoir behavior and
improve recovery efficiency.
From a purely mechanical point of view,
geopressure data are relatively simple to obtain
during or shortly after drilling. As discussed
earlier, real-time, while-drilling pressure tools,
such as the StethoScope system, are providing
engineers with valuable geosteering and reservoir
data for completion design, while wirelineconveyed tools, such as the PressureXpress
service, provide accurate pressure and mobility
data shortly after the well is drilled. But, there is
a problem: once casing is run into the well, these
tools cannot access the formation where there
are no perforations. Thus with time, known
pressures become unknown, and production
decisions become more uncertain.
Using sensors similar to those mounted in
while-drilling and wireline pressure tools,
Schlumberger engineers designed the CHDT
Cased Hole Dynamics Tester, capable of
measuring pressure and extracting fluid samples
from behind a cased wellbore.21
4,600
10,000
10,500
11,000
0
4,000
2,000
6,000
Pressure, psi
> Identifying depleted zones. Formation pressures (red) are compared with
the mud gradient (green), identifying zones depleted by as much as 4,000 psi
[27.5 MPa] in the middle part of the reservoir, while the last 500 ft of pay is
still at a relatively high pressure.
Autumn 2005
39
> Cased-hole sampling tool. Engineers use the CHDT tool to make multiple pressure measurements and collect fluid samples from behind a cased
wellbore. Powered by a wireline cable, the backpressure pads (lower side of tool) push the tool into an eccentric position (tool shown eccentered against
blue casing frame), the probe (shown tool top side) seals against the casing, and then drills a hole and measures pressure, samples fluids and plugs the
hole. As the drill bit penetrates the target, the onboard integrated instrument package monitors pressure, fluid resistivity and drilling parameters.
The CHDT tool can drill through casing and
cement and then into the formation, take
multiple pressure measurements, recover fluid
samples and plug the holes made in the casing,
all in a single descent (above). The ability to
reseal the drilled holes makes the tester
uniquely suitable for several reservoir and
production applications: for example, locating
bypassed hydrocarbons, evaluating unknown pay
zones, producing or injecting through a few
holes, and determining formation-evaluation
parameters when no openhole logs are available.
Engineers can then optimize recompletion plans,
enhance old or incomplete log data, assess
unknown pay zones and evaluate wells for
economic potential. The tool reduces rig cost by
eliminating the costs of conventional plugsetting and cement-squeeze operations.
An operator in south Texas requested an
evaluation of a well drilled in 1941. Cased-hole
logging tools identified multiple zones with
potential hydrocarbons. Engineers used a USI
UltraSonic Imager device to evaluate casing
40
condition and cement quality, and then the
CHDT tool to measure reservoir pressure and
confirm fluid type.
During the test, seven formation pressures
were acquired. Four samples confirmed
hydrocarbons. The CHDT tool successfully
plugged all holes. Based on test data, the
operator was able to plan a recovery program for
the bypassed hydrocarbons.
Even though engineers can evaluate reservoir
pressures behind casing long after production
has begun, running tools in the hole is a costly,
invasive procedure. Well problems are addressed
most efficiently when acted on quickly.
Developments in downhole telemetry, pressure
sensors and advanced completion systems offer
the reservoir engineer the flexibility to make
production decisions in real time.
Permanent downhole pressure sensors and
monitoring tools, such as the WellWatcher realtime production monitoring and surveillance
system, provide a continuous source of downhole
pressure measurement throughout the life of a
well.22 Most often placed in the wellbore along
with completion hardware, permanently
installed sensors constantly monitor production
pressures (next page). When these sensors are used
with other real-time monitoring hardware such
as fiber-optic temperature sensors, engineers
can constantly update reservoir models and
optimize the complete reservoir system.
Before the introduction of these systems,
data acquired through well intervention provided
only a snapshot of well performance at the time
the parameters were measured. Now, highly
reliable downhole monitoring systems are
sustainable in most downhole environments.
The WellWatcher system has been in place on
15 BP North Sea assets for more than eight
years.23 From 1995 through 2003, BP installed 75
of the monitoring systems in platform and subsea
projects, all based on permanent pressure
sensors. BP reports that during this period, only
four of the systems have failed, translating to a
success rate of 95%.24
Oilfield Review
In the BP Madoes field, a satellite of the
Eastern Trough Area Project (ETAP) in the
central North Sea, three producing wells are tied
back 12.5 miles [20 km] to the primary platform.
During completion, field specialists installed a
FloWatcher integrated permanent production
monitor system in each well to monitor pressure,
temperature, absolute flow rate and fluid density
in oil-water flows. Real-time data from the
monitoring system allowed BP production
engineers to quickly react, slowing water
production by reducing production rate. If they
had relied only on surface measurements, the
problem would have been much worse.
Engineers involved in the Foinaven deepwater subsea development, West of Shetlands,
North Sea, are using real-time pressure sensors
to better understand reservoir flow dynamics,
adjust gas lift rates and maximize production.
Prior to real-time downhole pressure measure-
Centralizers and electrodes
Gravel pack
Shrouded valve
(WRFC-E)
Sand screens
Production
packer
ments, engineers relied on modeling software to
help optimize gas lift rates and hence, overall
production rate. These models required data
from costly and time-consuming well tests and
generally provided results with limited accuracy.
Real-time downhole pressure monitoring systems
now allow BP engineers to adjust gas lift rates to
achieve minimum flowing bottomhole pressure,
and hence maximum production rates.
Additional value is derived from the ability to
track well performance based on establishing
baseline parameters early in well life and then
taking periodic time-lapse measurements of
permeability height and skin factors from
analysis of buildup pressure transients. This has
provided early identification of well-performance
problems, allowed more detailed evaluation and
permitted intervention approaches to be
optimized, with associated time and cost savings.
Electrical line
to valves
Resistivity cable
External casing
packer (ECP)
Hydraulic line to ECP
Sand screens
ECP
ECP
Oil
Water
Zone 1
Zone 2
Zone 3
The Foinaven team has also used the data
from permanent downhole sensors to
significantly improve understanding of reservoir
connectivity, and then optimize various water
injection and associated voidage replacement
strategies. Engineers involved in the project
estimate that over a three-year period, beginning
in 2000, the combined benefit of these
monitoring systems accounted for 1 to 3% of
incremental production.
Data from continuous real-time sensors
provide engineers with the necessary information
to optimize reservoir performance and recovery
by detecting problems early and defining timely,
preemptive reservoir-management solutions.
Managing the Pressure System
Maintaining reservoir pressure and optimizing
recovery of oil and gas have become parts of a
global challenge. The measurement of pressure
throughout a reservoir’s life cycle is key to
reservoir management. Accurate and efficient
pressure measurement helps engineers and
geophysicists manage subsidence, improve
sweep efficiency in secondary-recovery
operations and improve asset performance.
Case histories demonstrate that engineers
can refine predrilling seismic pore-pressure
models using downhole data, then adjust models
with real-time data allowing wells to be drilled
more quickly with reduced cost, improved
borehole placement and better management of
the reservoir. As efforts continue to define the
next energy revolution, reservoir engineers,
geologists and geophysicists are combining the
current developments in pressure-measurement
tools with advances in seismic interpretation and
modeling to optimize recovery and extend the
life of known hydrocarbon reserves.
— DW
> Highly complex sensor and control installation. As downhole control-system technology evolves,
the complexity of completion, monitoring and control systems continues to increase. Multizone
completion systems comprising packers, sand-control screens, flow-control valves (WRFC-E) and
sensor packages for temperature, pressure, resistivity and more are not uncommon.
22. For more on permanent downhole pressure sensors:
Bates R, Cosad C, Fielder L, Kosmala A, Hudson S,
Romero G and Shanmugam V: “Taking the Pulse of
Producing Wells—ESP Surveillance,” Oilfield Review 16,
no. 2 (Summer 2004): 16–25.
23. “Keeping Watch on Production, Deepwater,” A
Supplement to Hart’s E&P, Hart Energy Publishing,
August 2004.
Autumn 2005
24. For more on pressure gauges and downhole monitoring:
Eck J, Ewherido U, Mohammed J, Ogunlowo R, Ford J,
Fry L, Hiron S, Osugo L, Simonian S, Oyewole T and
Veneruso T: “Downhole Monitoring: The Story So Far,”
Oilfield Review 11, no. 4 (Winter 1999/2000): 20–33.
41