A New Slogan for Drilling Fluids Engineers
“Zero damage—good; permeability reduction—bad,” long a motto of drilling engineers, is accurate
for most vertical wells. Horizontal wells, however, with more exposure to producing formations,
are different. Laboratory work and reservoir simulation are helping write a more equivocal phrase:
“Zero damage—preferable; permeability reduction—better to avoid, but often allowable.”
Otto Houwen
Hemant Ladva
Gerry Meeten
Paul Reid
Cambridge, England
Don Williamson
Montrouge, France
One of the golden rules for vertical wells is
that formation damage caused by drilling
should, if possible, be eliminated in the
reservoir. Generally, this concept has also
been extrapolated to horizontal wells and
has led to the adoption of aggressive techniques to clean up formation damage. However, in some cases these complicated treatments increase rather than decrease risk to
the wellbore. Quantifying the effects of mud
systems and available cleanup techniques
makes possible an informed choice, specific
to the reservoir and well being drilled.
For help in preparation of this article, we would like to
thank Sarah Browne, Michael Burnham and Dan Ryan,
BP Exploration Operating Company Limited, Aberdeen,
Scotland; Lindsay Fraser, Dowell, Houston, Texas, USA;
and Paul Way, Schlumberger Cambridge Research,
Cambridge, England.
VISPLEX is a mark of Schlumberger.
Spring 1997
The clear objective for any well is that it
should perform to the full potential of the formation it penetrates and remain stable
throughout its lifetime. This goal is best
achieved by avoiding formation damage in
the first place, but in most cases this is not
possible. However, if damage is unavoidable,
a correlation can be drawn by looking at fracturing treatments in vertical wells. During
fracturing jobs, wells may sustain near-wellbore damage similar to drilling-induced damage. But this damage may be largely ignored
because induced fractures extend thousands
of feet into the formation, exposing more of
the reservoir to a conductive flow path and
significantly improving productivity.
Horizontal wells penetrate up to 6000 ft
[2000 m]—even more than most induced
f ractures—into a reservo i r, exposing the
wellbore to an area of producing formation
at least an order of magnitude greater than
would be achieved with a vertical well. This
opens up two opposing factors that drive
horizontal well productivity.
Because of their huge flow area, horizontal wells can withstand higher levels of
damage than vertical wells and still deliver
higher production rates. Conversely, drilling
times for horizontal sections are generally
much longer than for vertical wells in the
same formation, giving drilling mud more
time to enter the formation and potentially
causing more severe formation damage.
Also, lower drawdown pressures in horizontal wells may reduce cleanup efficiency.1
Therefore, some reduction in permeability
may be permissible in horizontal wells, as
long as the wellbore extends far enough into
the formation to ensure sufficient flow area.
At the same time, other aspects of the
drilling fluid, like its effect on well drillability, may be brought to the fore. The trick is
knowing which drilling fluids to select to
maximize drilling rate while minimizing risk
to the formation.
For too long, decisions about drilling fluids
h ave been made in isolation. Now, the
industry is developing a strategy that brings
together the domains of the reservo i r,
petroleum and drilling engineer with that of
the fluids engineer. At the heart of this work
is the development of a real understanding
of how drilling fluid damage affects productivity, with the goal of developing a reservoir
engineering tool for drilling fluid design.
1. Renard G and Dupuy JG: “Influence of Formation
Damage on the Flow Efficiency of Horizontal Wells,”
paper SPE 19414, presented at the 9th SPE Formation
Damage Control Symposium, Lafayette, Louisiana,
USA, February 22-23, 1990.
Browne SV and Smith PS: “Mudcake Cleanup to
Enhance Productivity of High Angle Wells,” paper SPE
27350, presented at the SPE International Symposium
on Formation Damage Control, Lafayette, Louisiana,
USA, February 7-10, 1994.
Beatty T, Hebner B, Hiscock R and Bennion DB: “Core
Tests Help Prevent Formation Damage in Horizontal
Wells,“ Oil & Gas Journal 91, no. 31 (August 2, 1993):
64-70.
3
Formation Damage—Invasion of
the Production Snatcher
From a mud standpoint, a well may be
divided into two sections. In the first—from
the surface to top of the reservoir—the two
key drivers are health, safety and environmental (HSE) constraints, and drilling cost.
In the second section—the reservoir—HSE
concerns remain of central importance, but
the cost factor is usually overshadowed by a
need to minimize formation damage. Of
course, a prerequisite in both sections is that
the well be drillable with the mud of choice.
Formation damage is considered to be
anything that impairs the permeability of
reservoir formations, reducing injectivity or
hydrocarbon production. Damage can
occur during all stages of well construction,
during remedial treatments and during production.2 This article concentrates on the
relationship between drilling fluids and formation damage.
In reality, all reservoirs are damaged to
some extent by drilling fluid. The important
issue is whether this damage significantly
affects well productivity. One way of quantifying formation damage is to use the damage skin factor (right). Typically, a poorly
constructed damaged well will have a positive skin of 20 to 500; a good unstimulated
well will have a skin of plus five to minus
unity; and a well that has been fracture stimulated will have a large negative skin.
Today, most vertical wells are completed
using a cemented liner that is then perforated. This is not the case for horizontal wells
that are most often completed barefoot—that
is open hole—or using prepacked sand control screens, slotted liners or predrilled liners
where drilling mud may have a greater
impact on the productivity of a well. There
are at least two reasons for this effect.
First, oil and gas must be produced
through the filter cake and mud filtra t e induced formation damage because there
are no perforations that reach beyond the
damaged zone. Second, sand control completions such as prepacked screens may also
be plugged by the mud (see “How Drilling
Fluid Reduces Producibility in an Openhole
Horizontal Well,” page 6).
4
■Damage skin surrounding a wellbore. The skin factor may be
represented as a dimensionless pressure drop. The magnitude of
this factor depends on the ratio of the undamaged and damaged
permeabilities in the formation, and on the depth of damage,
which is related both to the depth of invasion and fluid loss.
Drilling fluid selection for reservoir drilling
in horizontal and high-angle wells is a complex process. Obviously, the choice of mud
should ensure that the well is drillable, and
a wide range of well and formation factors
influence this selection. The effect of
drilling fluid systems on factors such as hole
cleaning, torque and drag, wellbore stability, and stuck pipe is central to success or
failure (see “Stickance Tester: Predicting a
Mud’s Performance,” page 10).
The next and increasingly important factor
influencing selection is the HSE aspect of a
drilling fluid. Some fluids may not be usable
in certain situations because of company or
regulatory policy. Then come the cost and
impact of the drilling fluid on productivity.
This article focuses on the interplay of these
final two factors.
Understanding the Real Effects
of a Drilling Fluid
While there appears to be a broad consensus on the mechanisms of formation damage, there is growing divergence over how it
may be combated or avoided. The need to
cost effectively eliminate or at least minimize formation damage, so that productivity
is maximized, has spawned a specialized
area of fluid design for reservoir drilling and
ushered in a host of what are called “drill-in
fluids.” Most drilling fluid companies have
developed drill-in fluids to allow effective
cleanup following reservoir drilling.
One development has been the introduction of mud systems with a solid phase,
which makes up the filter cake, that may
subsequently be removed by washes or
breaker fluids circulated into the well before
completion to dissolve or partially break the
filter cake. Theoretically, these treatments
reduce the pressure required by formation
fluid to break through the filter cake once a
well is put on production, ensuring an even
flow across the productive part of the horizontal interval. In practice, their action is
never uniform across the wellbore and such
treatments substantially increase drilling
costs and complicate field operations.
Oilfield Review
above treatments. For example, sized-salt
systems incorporate magnesium peroxide
that when exposed to acid releases hydrogen peroxide, which degrades polymers. A
variety of solvent and surfactant fluids is
available to treat oil-base mud (OBM) filter
cakes, breaking down the oil-wetting character of the cake and allowing it to disperse
in the aqueous, or mixed-phase wash fluid.
As with polymer breakers, this treatment
m ay also be used in combination with
additives that dissolve the cake.
These treatments are not without problems.
Washes may cause significant losses of treatment fluid to the formation. These invading
fluids, and the resulting filter-cake residues,
may cause significant additional formation
damage—the opposite of what is intended. If
the losses are severe, it will be necessary to
use expensive and time-consuming lost-circulation treatments that may themselve s
cause damage. Also, severe losses could
eventually lead to well-control incidents.
Treatment of some OBM filter cakes produces viscous sludges that cause formation
damage. Polymer sludges may also result
from treatment of WBM filter cakes. Acid
breakers may cause corrosion problems.
An alternative is to do away with washes
and breakers altogether and back-produce
the drilling fluid through the completion
hardware (see “Bringing in Wells Without a
Cleanup,” page 16). Another approach is to
minimize particulate invasion of the formation in the first place by creating a filter cake
that may be more easily “lifted” by formation fluid during flowback. An example of
such a system is a bentonite/mixed-metalhydroxide (MMH)/sized-carbonate system.
MMH fluids are highly thixotropic, and labo ratory tests show that they have a low
potential for formation damage, lay i n g
down a predominantly external filter cake
and thereby avoiding the need for deeppenetrating washes (above left).3
■Minimizing particulate invasion. VISPLEX
filter cake (A) on the
external surface of a
core (top). Between
rock grains (B),
unblocked pores—on
the order of 30 microns
(µ) wide—may be seen
immediately below filter cake (C). At higher
magnification, a filmlike bridge of bentonite
and mixed-metal
hydroxide (D) over the
pore throat is highlighted (center). After
exposure to KCl-polymer mud, internal filter
cake (E) is apparent
between the rock
grains (bottom). The
unusual behavior of
the VISPLEX fluid may
explain the low level
of permeability impairment seen in laboratory and field evaluations of this system.
(continued on page 8)
Saturated salt muds with salt crystals sized
to bridge across the formation and form a significant part of the filter cake are a typical
example. After drilling, this cake is washed
with an undersaturated brine that dissolves
the salt, promoting filter-cake cleanup. Alternatively, calcium carbonate may be used as
the weighting and bridging agent in both
water-base and oil-base muds. In this case,
the filter cake may then be treated with a
mild acid to dissolve the carbonate. Also, cel-
Spring 1997
lulosic products that are frequently used for
fluid-loss control or as bridging agents may
be dissolved—although often only partially—
using dilute acids or oxidizing agents such as
sodium hypochlorite.
Enzyme breakers have been developed for
some wa t e r-base muds (WBM). Th e s e
enzymes are designed to attack polymers
and may be used alone or with one of the
2. Krueger RF: “An Overview of Formation Damage and
Well Productivity in Oilfield Operations,” Journal of
Petroleum Technology 39, no. 2 (February 1986):
131-152.
3. Fraser LJ, Williamson D, Enriquez F Jr and Reid P:
“Mechanistic Investigation of the Formation Damaging Characteristics of Mixed Metal Hydroxide Drill-In
Fluids and Comparison With Polymer-Base Fluids,”
paper SPE 30501, presented at the 70th SPE Annual
Technical Conference and Exhibition, Dallas, Texas,
USA, October 22-25, 1995.
5
How Drilling Fluid Reduces Producibility
in an Openhole Horizontal Well
There are at least four dif ferent mechanisms for
1 to 100 microns (µ) are believed to be most dam-
drilling fluid to damage horizontal well pr oducibil -
aging, since particles smaller than 1 micron are
As sand control completion har dware is run into
ity both inside the formation and in the wellbor e.
normally strongly held to the surfaces of lar ger
the well, it fills with the fluid in the well. Mud will
Mud-solids invasion and internal filter cake—
Drilling fluid damage to completion hardware—
mineral grains by Van der Waals forces and are
flow or filter through the screen as a result of
difficult to dislodge. Particles above 100 micr ons
surge pressures created while running into the
into the formation—on the order of a few millime-
are larger than most por e-throat diameters and so
well. During this process, solids in the mud may
ters—bridging across or plugging pore thr oats
cannot migrate any great distance. It is usually dif-
partially or completely plug the screen. Suscepti-
Drilling fluid solids will invade a short distance
(next
page, top left). 1
ficult to carry out successful remedial tr eatments
bility to mud damage will vary widely, depending
flow unless it is removed by treatment or flushed
An internal cake will r estrict
to remove damage caused by formation fines.
on completion type—prepacked screens are par-
out during production. The damage potential of
Sometimes even these treatments can cause fines
ticularly vulnerable due to internal plugging
mud solids depends on the size of particles r ela -
to become mobilized—by dissolving inter granular
page, bottom left).
tive to the size of the pore throats in the for mation
cements—or can leave reaction products that are
being drilled. Shape, flexibility and degree of dis-
themselves damaging (next page, top center).
persion of particles are also important. Possible
Changes in wettability—When oil-base mud fil-
exceptions are highly flexible particles like ben-
trate invades a water-wet formation, surfactants or
(next
Damage profile from a polymer mud—A polymer
mud may damage formation permeability in several
ways. For example, mud solids may invade and
create an internal filter cake; fines can be mobilized
tonitic clays that can deform suf ficiently , allowing
certain types of polymer in mud filtrate may change
and block pores inside the formation; and cer tain
them to penetrate pores smaller than the diameter
the wettability of the rock. Displaced for mation
polymers carried inside the rock may adsorb onto
of the clay sheets. As a guideline, par ticles
water forms droplets in the pore spaces and thus
the rock and change the wettability, while lar ger
between one-sixth and one-third of the diameter of
affects hydrocarbon production. In fact, oil-wetting
polymers can also block pore spaces. Each of these
a pore throat may invade a significant distance
agents are specifically designed to make weighting
processes invades to a dif ferent depth, cr eating
into the rock before bridging pore throats; par ticles
agents and drilled solids particles hydrophobic, so
more or less damage. A damage profile is more
less than one-sixth of the por e-throat diameter
it is inevitable that, if free surfactant enters the
useful than a simple average because it helps
generally do not bridge.
rock in the mud filtrate, the rock is also likely to
explain the consequences and mechanisms of inva-
become oil-wet. Permeability damage caused by
sion (next page, bottom center). In this case, the dam-
Mud-filtrate invasion—Mud filtrate may interact
chemically and physically with the for mation
wettability change is generally assumed to be per-
age profile decreases in severity away from the
causing significant damage—for example, mobi-
manent. However, because of the low fluid-loss
wellbor e. If a formation is not susceptible to fines
lizing formation fines or changing formation wet-
rates of oil muds, the depth of damage will often be
damage, then this graph will be dif ferent.
tability due to adsorption of mud surfactants onto
small. Wettability change generally has a gr eater
the par ticles.
influence on production in tight rocks that contain
Formation-fines mobilization—When water-
small-diameter pores (next page, top right).
base mud invades a rock containing oil, fines
Undisplaced whole drilling fluid—Large-scale
mobilization following filtrate invasion may be
flow loop tests have shown that when screens are
triggered by a salinity change, by a chemical
uncentralized, mudcake and debris are left on the
deflocculant in the filtrate, or by high fluid-flow
low side of the hole even after aggressive cleanup.
velocities in the pore space. Migrating fines may
Whole fluid left behind in the annulus can pack off
cause extensive damage by blocking pore thr oats.
on the completion har dware during pr oduction.
In most formations, mobile particles ranging fr om
Also, for wells with low drawdown, the high gel
1. Francis PA, Eigner MRP, Patey ITM and Spark ISC: “Visualisation of Drilling-Induced Formation Damage Mechanisms
Using Reservoir Conditions Core Flood Testing,” paper SPE
30088, presented at the SPE European Formation Damage
Conference, The Hague, The Netherlands, May 15-16, 1995.
strength of drilling mud could prevent or r estrict
flow from part of the horizontal section (next page,
bottom right).
6
Oilfield Review
Spring 1997
7
■The effects of washes on breakthrough pressure. Data collected
by a joint industry study reveal a wide variation between the
effectiveness of different mud systems when washes are used to
remove or destabilize a filter cake. However, contrary to expectations, more breakers were found to increase breakthrough pressure than reduce it.
■The effects of washes on permeability damage. A joint industry
study showed that, in some cases, washes significantly reduce
damage levels; in others, washes increase damage.
The continuing debate on the pros and
cons of washing versus back-production of
filter cake in openhole completions has, at
least in part, been driven by the philosophies of individual companies. However,
new studies into cake properties and damage mechanisms are now providing better
information for decisions.
For example, a joint industry study of mud
cleanup in horizontal wells fully examined
the role of common washes and breakers.4
Small-scale core experiments tested six mud
systems and various breakers. Surprisingly,
more of the breakers increased the backflow
pressure required to break through the filter
cake than reduced it (top). In no case was
8
all filter cake removed. In displacement flow
tests, effectiveness of washes on the low
side of horizontal wellbores also proved to
be limited because of the presence of stagnant whole mud, and large amounts of
residual mudcake and debris.
Another role of breakers is to remove
mud-induced damage from the near-wellbore region. In this case, performance varied for different mud systems—significantly
reducing near-wellbore damage for some
muds and increasing damage in others
(above). For some mud systems there was a
correlation between treatments that induce
high losses and high levels of damage with
the wash fluids carrying damaging material
such as fines or partially degraded polymer
deep into the formation.
The high cost of specialized drill-in fluids
means that attempts to drill a well with zero
skin may take up a significant proportion of
well budgets. However, any savings in the
mud cost have to be weighed against the
risk of reducing productivity rather than preserving it. There is much to be gained by
defining the optimum amount of formation
damage that may be tolerated for a given
well in a given situation.
But what is the optimum skin factor for a
well? The answer is not simple. In some settings a considerable skin factor may have little effect on flow. The joint-industry study
referred to above confirms that some horizontal wells can tolerate a significant level
of mud damage before productivity is significantly impaired. In others, only low skin
factors may be tolerated, but these conditions cannot be ach i e ved economically
using available mud systems. Reservo i r
ch a racteristics, well profile, completion
design and economics all dictate the optimum skin factor.
A further determinant is the future role of
the well. In an exploration well, where the
o b j e c t ive is to find rather than produce
hydrocarbons, a moderate skin may be
acceptable. However, in a marginal development with a limited number of wells and
tight margins, low skin may be of
paramount importance. Many high-angle
wells are targeted to intersect multiple sand
bodies. For these wells, the main objective
is ensuring that all potentially productive
sections of the well may flow so that
reserves access is maximized. Other wells
are drilled truly horizontal to maintain a
constant standoff with gas or wa t e r. Th e
main driver in these wells is an even drawdown to minimize coning.
Therefore, distribution of the damage is
also important. As part of an extensive study,
BP confirmed that the percentage of the
i n t e r val flowing, and distribution of the
flowing intervals over the length of a horizontal well may have a larger impact on
Oilfield Review
■How distribution of
flow affects flow efficiency. The first well
schematic (top) illustrates 50% of the formation flowing from
a single interval in
the heel of the well.
The second well
schematic (middle),
also shows only 50%
of the well flowing.
However, this time,
flow is divided into
six evenly spaced
flow intervals across
the length of the
well. The graph (bottom), based on data
gathered by BP,
shows how increasing the number of
flowing intervals
increases the flow
efficiency of a well
even though the
total percentage of
the well contributing
to the flow remains
constant.
■The impact of
near-wellbore permeability reduction
on flow efficiency. A
small reduction in
the near-wellbore
permeability—in
this case up to
about 30%—has little effect on flow
efficiency and the
differences in depth
of damage are not
significant. However, when permeability reduction
reaches 60% and up
to about 80%, the
effect on flow efficiency becomes profound and the differences in depth of
damage become
more marked.
Spring 1997
productivity than the reduction in permeability around the well (left).5 This work,
carried out in Sunbury, England, produced three key findings:
• If a given percentage of filter cake is
removed to allow a well to flow, it is
better for this percentage to be distributed over a large number of smaller
intervals, instead of having all the flow
concentrated in a single, large interval.
• The cleanup need not be complete.
Rather than remove the filter cake,
increasing its permeability to at least
0.1 md is sufficient—filter-cake permeabilities are typically 10-2 to 10-6 md,
depending on fluid type, differential
pressure and solids content.6
• Damage by deep invasion of filtrate—
on the order of feet—causes only a
small reduction in productivity as long
as the reduction in permeability is not
too great (below left).
Studies such as this one by BP illustrate
a central truth. There is no single best
t e chnique for the cleanup of uncemented horizontal wells. The completions engineer has a range of options that
must be assessed for each field and each
well strategy. The only way of knowing
which is best is to understand the drilling
fluid and its interaction with the formation and completion hardware. Practical
options will vary depending on issues
such as environmental legislation, operational risk or logistics—for example, a
complicated wash strategy may not be
possible if there is insufficient storage
capacity on the rig. There is also, quite
clearly, no guarantee of success.
Thus, although the objective of any
drilling fluid design should be to deliver
a well with no formation damage,
drilling and production pra c t i c e s
inevitably lead to some damage that may
not be removable. But if the well still
produces to its full potential, this damage
could be termed “affordable.” As yet, this
concept of affordability is not widely
reflected in industry practices.
(continued on page 11)
4. Ryan DF, Browne SV and Burnham MP: “Mud
Cleanup in Horizontal Wells: A Major Joint Industry
Study,” paper SPE 30528, presented at the 70th SPE
Annual Technical Conference and Exhibition, Dallas,
Texas, USA, October 22-25, 1995.
The work was undertaken as a joint industry project
by Amoco, BP, Chevron, Norsk Hydro, Saga, Shell,
Statoil and TBC Brinadd.
5. Early work in this field is reported in:
Goode PA and Wilkinson DJ: “Inflow Performance of
Partially Open Horizontal Wells,” paper SPE 19341,
presented at the SPE Eastern Regional Meeting, Morgantown, West Virginia, USA, October 24-27, 1989.
6. For example, in a typical wellbore, a cake of 0.1-md
permeability and thickness of 3 mm gives a skin of 5;
a cake of 0.01 md gives a skin of 56.
9
Stickance Tester: Predicting a Mud’s Performance
Stuck pipe during drilling operations is a major
nonproductive cost to the industry. 1 Stuck-pipe
incidents are generally divided into two main categories: mechanical and dif ferential sticking. Which
of these problems is more dominant depends on
where drilling is taking place. In the North Sea,
mechanical sticking is the main problem; in the
Gulf of Mexico, it is dif ferential sticking.
Mechanical sticking includes a large number of
mechanisms, including hole collapse and key
seating. Dif ferential sticking is the most common
single mechanism and occurs when part of the
drillstring becomes embedded in the mud filter
cake and is then held there by hydrostatic pr essure, which exceeds the formation pr essure. As
such, it can occur only where a filter cake has
been established—across permeable for mations.
The pipe usually becomes stuck when it is stationary adjacent to a permeable zone and there is a
significant mud overbalance. The likelihood of differential sticking increases with the length of permeable section being drilled—making extendedreach and horizontal wells particularly vulnerable.
When it comes to preventing dif ferential sticking,
the nature of the rock cannot be changed. High overbalance pr essures may also be needed to maintain
well control or wellbore stability. However, it is possible to modify mud composition and pr operties.
■Stickance tester. The body of the device is a double-ended, high-temperature, high-pressure (HTHP) mud
filtration cell. The top end cap has been modified to allow the entry of a spring-steel wire through an o-ring
seal set in the center of the cap. A new entry port has been drilled to allow the cell to be pressurized. Inside
the cell, the steel wire is connected to a 1.5-in. [3.8-cm] polished steel ball that rests on the filter medium at
the bottom of the cell. The end of the wire protruding from the cell is attached to an electronic torque gauge.
Recently , a better understanding of dif ferential
sticking led to the development of a new labora-
tinely carried out on drilling fluids. Although addi-
A high-temperature, high-pr essure (HTHP) fil-
tory test tool to help design mud systems that
tional tests do exist, SCR r esear chers have devel-
tration cell was converted to create a stickance
avoid dif ferential sticking. Work carried out by
oped a new technique to measure filter-cake pr op-
tester (above). In this test, a filter cake is built up
resear chers at Schlumberger Cambridge
erties that can be related to a fluid’s propensity to
around a polished steel ball inside the cell. The
Resear ch, Cambridge, England has concentrated
encourage dif ferential sticking. The technique is
force needed to rotate the ball is used to quantify
on the nature of mud filter cake—in par ticular
designed as a low-cost, simple test that may be
the nature of a filter cake.
thickness, lubricity and str ength. 2
carried out at wellsites.
A true measure of filter-cake pr operties is not
currently included in the suite of standard American Petroleum Institute (API) measurements r ou-
10
Oilfield Review
Quantifying Affordable Damage
■Typical plot in which
the stickance is given by
the slope. Good reproducibility has been
achieved as long as consistent operating practices are employed.
A test is carried out by placing the filter medium
of time (t 3⁄4) to account for the buildup of filter cake
representing a permeable formation in the cell.
around a spherical object. This plot usually gives a
The filter medium is usually filter paper, although
straight line, the slope of which is the dif ferential
cores, sand packs and simulated fractured for ma-
sticking tendency—stickance (above).
tions may also be used in future versions of the
Using this apparatus, SCR r esear chers have
device. The cell is filled with drilling fluid, the top
established mud formulation and engineering
end cap is installed and the ball and torque gauge
guidelines to reduce the risk of dif ferential stick-
are set in position. The cell is then placed in a
ing. Fur ther, treatment options for field muds have
standard HTHP heating jacket. The mud is heated
been investigated to help avoid sticking. The stick-
to the desired temperature and then pressurized as
ance tester is now being pr epared for deployment
if a normal HTHP fluid-loss measurement were
in field laboratories so that these services may
being made—typically a dif ferential pr essure of
become generally available.
500 psi [3445 kPa] is used.
As filtration proceeds, a filter cake is built up on
the filter medium and around the steel ball. At precisely noted intervals—about every 5 minutes—
the torque gauge is rotated and the force needed to
free the ball from the filter cake is measured. This
measur es both adhesion of the ball to the cake and
the force needed to break this bond. T orque data
are plotted as a function of the thr ee-quar ter power
Spring 1997
1. Bailey L, Jones T, Belaskie J, Orban J, Sheppard M, Houwen
O, Jardine S and McCann D: “Stuck Pipe: Causes, Detection
and Prevention,” Oilfield Review 3, no. 4 (October 1991):
13-26.
2. Reid PI, Meeten GH, Way PW, Clark P, Chambers BD and
Gilmour A: “Mechanisms of Differential Sticking and a
Simple Well Site Test for Monitoring and Optimizing
Drilling Mud Properties,” paper IADC/SPE 35100,
presented at the 1996 IADC/SPE Drilling Conference,
New Orleans, Louisiana, USA, March 12-15, 1996.
To make sense of the notion of affordability,
it is necessary to understand the consequences of damage. Although new production logging techniques are being developed, it is still difficult to extract from
horizontal well tests all the information
needed to make the required judgements.7
Therefore, the productivity effects of formation damage caused by drilling fluid invasion—or indeed the magnitude of the damage itself—are usually unquantified.
The need to close this knowledge gap has
been addressed in work carried out by
r e s e a rchers at Schlumberger Cambridge
Research (SCR), Cambridge, England. Using
core-flood experiments, they are determining the formation-damage effects of drilling
fluid invasion. Data from these experiments
are then used in accurate reservoir simulations that model the effects of this damage
on productivity (see “How Core-Flood Tests
Are Carried Out,” next page).
New analytical expressions have been
developed that relate damage to the production potential of the formation. From the
mud, all information on filtration, invasion
and cleanup is channelled into the calculations through the skin factor. Fo r m a t i o n
damage expresses itself through large positive skin values and hence lower productivity index (PI) values and lower flow efficiencies—that also take account of well
geometry, formation thickness, permeability
anisotropy, reservoir location, length of the
wellbore and proximity of other wells.8
To help determine the return, in terms of
PI, from an incremental improvement in the
performance of a mud, numerical simulations using data generated by these analytical expressions model the effects of damage
on well producibility. These simulations
assess the implication of damage on reservoir producibility, the implications of
incomplete penetration of the damage if a
well is to be perforated (having assessed the
depth of damage from cores), and effects of
incomplete filter cake removal if a well is
not perforated.
(continued on page 14)
7. Bamforth S, Besson C, Stephenson K, Whittaker C,
Brown G, Catala G, Rouault G, Théron B, Conort G,
Lenn C and Roscoe B: “Revitalizing Production Logging,” Oilfield Review 8, no. 4 (Winter 1996): 44-61.
8. Flow efficiency is defined as the flow rate with skin
divided by the flow rate without skin, at the same
drawdown pressure.
11
How Core-Flood Tests Are Carried Out
Over the years, various core-flood experiments
have been per formed to assess formation damage
by using equipment that measures per meability
changes in rock cores before and after exposure to
drilling fluid. Researchers at Schlumberger Cam-
■Core-flood equipment
for initial permeability
measurements. Detail of
the core holder shows
how the rock sample is
locked into place.
bridge Research (SCR), Cambridge, England have
carried out extensive tests, building up a wide
range of data. The experimental pr ocedure may be
divided into three stages:
Stage One: Sample Preparation and Initial Permeability Measurement. The equipment at SCR
tests rock cores that are 25 mm in diameter and up
to 32 mm long. Cores are placed under vacuum to
remove entrapped air and then saturated in brine
or simulated formation water—this may be unnecessar y if well-pr eser ved reser voir core is used.
Once prepar ed, the core sample is fir mly
mounted in the sample holder so that there is a
seal between the rubber sleeve and the core. The
core holder is fitted into a standard high-temperature, high-pr essure (HTHP) fluid-loss cell body
12
Oilfield Review
that is then filled with the test fluid to be used for
Stage Two: Core Exposure to Test Fluid in a
the permeability measur ement—generally
Static or Dynamic Filtration Environment. Filtra -
kerosene, crude oil or brine. Finally, a standard
tion—establishing a filter cake—may be per-
HTHP end cap is secured in place.
formed under either static or dynamic mud flow.
The valve stem at the top of the cell is then con-
The filtration phase may be set for a specified
nected to a 2.5-liter [0.7-gal] r eser voir of test fluid
period of time or until a pr edeter mined volume of
that may be pressurized. The fluid passing thr ough
filtrate is collected and may be per formed at tem-
the rock is collected and its volume logged as a
peratur es up to 150°C [302°F] and pr essures to
function of time (previous page).
550 psi [3790 kPa].
Permeability measurements are made by opening the valve stem at the top of the cell to pr essur-
To perform filtration under static conditions, the
cell is filled with 200 mL mud, the standard end
ize the fluid inside. The valve stem at the base is
cap is refitted and a pr edeter mined pr essure dif-
opened to start flow through the sample, and the
ferential is applied from a gas source. As with the
data logging is star ted.
permeability measurement, the volume of fluid
Test fluid is allowed to flow through the sample
collected is logged as a function of time. Test con-
at a fixed pr essure. The volume of fluid collected
ditions are varied to mimic r eser voir temperature
versus time is logged until a constant flow rate is
and expected mud overbalance pr essure.
reached, indicating that the core has r eached
To perform a dynamic filtration test, a paddle
residual water saturation. Experience has shown
stirrer is installed in the cell a fixed height above
that for most rocks this constant rate is r eached
the core after the mud has been poured into the
when approximately 100 pore volumes have
cell. The cell is then made up and placed back into
passed through the core.
the HTHP heating jacket and the paddle is r otated.
At the end of the measurement, flow is stopped
by opening up the regulator and locking off the
Finally , filtration is r estar ted. Once again, filtrate
volume is r ecorded as a function of time (right).
valve stem at the base of the cell. After the fluid
This stirrer generates a range of flow conditions
reser voir and cell are depressurized, the top end
from turbulent, where little or no external filter
cap is removed and the cell is emptied of fluid in
cake forms, to laminar, which leaves filter cakes
preparation for the mud-filtration phase.
similar to those formed under static conditions. At
Data may now be combined with fluid viscosity
and core size to calculate sample per meability:
Permeability =
flow rate x fluid viscosity x sample length
the end of the filtration phase, the cell is depr essurized before rotation of the paddle is stopped to
ensure that no filtration occurs under dif ferent
.
operating conditions.
■Schematic of equipment for initial permeability
measurements with the stirrer installed for dynamic
filtration tests.
cross-sectional area x pressure
Spring 1997
13
■Simulating produced fluids flowing through a damaged reservoir.
■Flow before and after
filtration. Typically the
initial flow (blue) quickly
reaches a constant, while
the return flow (red) may
take a significant time to
stabilize as damage
caused by the drilling
fluid may be cleaned up
to some degree before a
steady state is reached.
Stage Three: Return-Permeability Measure-
ing the direction of test fluid flow through the
ment. Following filtration, another measure of
core—the equivalent of producing the for mation
core permeability is made to determine the level
(top). The same pr essure is used as in the initial
of formation damage caused by the mud. The stir-
permeability measurement, although there is often
rer is removed and any remaining mud is pour ed
a significant time delay before a steady flow rate
away. The cell is then filled with test fluid, and the
is reached (above). The change in per meability
end cap is fitted and sealed with a valve stem. The
before and after filtration may then be calculated.
cell is inverted and replaced in the stand, r evers -
14
To understand how much damage is tolerable, the undamaged PI of a well must be
k n own. Herein lies a major snag. Th e
undamaged PI in horizontal wells is often
unknown because it is difficult in horizontal
well tests to acquire reliable data for the
productive length of the well and the damage skin factor. This difficulty is due to wellbore storage—where fluid compressibility
masks pressure changes—and the short
d u ration of early-time radial flow from
which skin is calculated (next page, top).
Although a sensible baseline for well prod u c t ivity simulations should ideally be
drawn using existing horizontal wells in the
same field, the data uncertainty outlined
above renders this sort of reference information unreliable. Therefore, since understanding the PI of vertical wells is more straightforward, SCR researchers use a vertical well
in the same formation as a reference.9
Starting from the influence of formation
thickness and anisotropy on the skin factor,
researchers derived relationships that compare the flow efficiency of a horizontal well
with that of a vertical well fully penetrating
the same producing formation.10 A novel
expression has been derived that calculates
the length of horizontal section required to
create a well with the same skin factor as
the vertical reference well. The expression
combines all the geometric, reservoir, and
formation damage information necessary to
assess effects on flow efficiency of the horizontal well.
The degree to which an increase in skin
affects productivity of a horizontal well
depends on its drainage area, which introduces the concept of “neutral skin.” At neutral skin, production from both the horizontal well and its vertical reference is equally
impaired. With a skin value below neutral,
production from the vertical well is disproportionately reduced compared to its horizontal “sister” well. With skin greater than
the neutral value, the horizontal well suffers
a larger proportional production decrease.
Altering the horizontal well—for example
making it longer or increasing the drainage
radius—may mitigate this effect, and advantages of a horizontal well over a vertical
equivalent may be enhanced (next page,
bottom). This knowledge helps establish the
minimum length or drainage area required
for a horizontal well. For a given geometry,
sensitivity of a horizontal well to skin can be
assessed and thus the level of affordable
damage inferred.
9. Renard G and Dupuy JG, reference 1.
10. Even if a vertical well has not been drilled, an
approximation of its PI may be estimated using
available reservoir information.
Oilfield Review
■Consecutive flow regimes observed for horizontal wells.
• Early-time radial flow is the first radial flow period (in the vertical plane), which ends when the effect of the top or bottom
boundary is felt. For horizontal wells, this regime is short and difficult to identify because of wellbore storage effects. This is unfortunate as it is the only regime in which formation skin damage may
be deduced directly from a well test.
• Late-time radial flow is the second radial flow period (in the horizontal plane) that develops if the reservoir is sufficiently large and
wide compared to the length of the well. The well behaves like a
point source in the middle of the formation.
• Intermediate-time linear flow develops if the well is sufficiently
long compared with reservoir thickness—where the spread of
flow beyond the ends of the well is negligible compared to its
length. If the well is not long, there will be a long transition
between early-time radial flow and the next regime, bypassing
this one.
• Late-time linear flow—the second linear flow period—begins
when the pressure transient has reached all lateral extremities.
■Ratio of lost production from horizontal and vertical wells as a result of
damage skin factors plotted for three similar wells with different drainage
area radii: 1000, 2000 and 4000 ft. For a given well, the neutral skin value is
found at the intersection of the curve describing (qH /qV)lost as a function of
skin with the horizontal line (qH/qV)lost =1. Below this line, the incremental
effect on flow rate of increasing skin will be greater for the vertical reference
well than for the horizontal well. Above the line the opposite is true and
increasing skin will have a more deleterious effect on the horizontal well
than on the vertical well. This effect is mitigated by increasing the drainage
radius of the well, as can be seen from the graph, where a well with
drainage of 4000 ft remains below neutral for greater skin factors than do
equivalent wells with smaller drainage radii. Therefore, placing many horizontal wells together in close spacing—thus reducing the horizontal drainage
ratio—increases the susceptibility of individual wells to formation damage.
Spring 1997
15
At the same time, the drilling fluid must not
damage well productivity by either completely stopping flow from any reservoir section or significantly increasing near-wellbore
pressure drop and thus reducing well PI. For
this reason, the effects of mud filtrate on the
formation and the back f l ow pressure
required to break through the mud filtrate
and establish production must also be tested.
For BP, tests like these now form an integral part of developing the overall well completion plan. In essence there are three
components in a design loop: mud system
optimization to fit the reservoir; cleanup
strategy to ensure selection of the simplest
technique that leaves no significant mudrelated productivity impairment; and sand
control screen specification to best accommodate anticipated downhole needs.
■Reducing the impact of an oil-base mud. Core-flood testing, carried out by BP with
reservoir core under downhole conditions, showed a 99% permeability impairment.
Laboratory work revealed an incompatibility between the synthetic-base oil and the
emulsifier that caused precipitation in the rock pore throats. Changing the emulsifier
and then reducing its concentration cut permeability impairment to 70% and 36%,
respectively. In fact, the field sample showed only a 12% reduction in permeability,
which had a negligible effect on well productivity.
Bringing in Wells Without a Cleanup
Three possible options exist when dealing
with the drilling fluid prior to completing a
horizontal well with an uncemented liner or
screen:
• displace mud with a low-solids or solidsfree, clear fluid
• displace mud with a breaker system
• design the mud already in the well to flow
harmlessly through completion equipment
and bring the well into production without cleanup.
For its part, BP has begun to use completions programs that, where pra c t i c a l ,
employ the latter option—back-producing
drilling fluid through prepacked screens.11
Integral to this strategy is a desire to eliminate the complications and expenses associated with the other two strategies, while
avoiding any chance that a breaker might
actually decrease rather than increase permeability. By opting for simplicity, the company reasons it is cutting risk.
11. Browne SV, Ryan DF, Chambers BD, Gilchrist JM
and Bamforth SA: “Simple Approach to the Cleanup
of Horizontal Wells with Prepacked Screen Completions,” paper SPE 30116, presented at the SPE European Formation Damage Conference, The Hague,
The Netherlands, May 15-16, 1995.
16
However, BP is reducing risk only if the
drilling fluid system can effectively flow
through the prepacked screens without leaving permanent damage. Also, the well must
flow, lifting sufficient filter cake to enable full
productivity. Critical to both of these objectives is quality control of the drilling fluid in
the field—ensuring that it meets specifications established by laboratory work.
From this, BP has drawn up a series of
guidelines. For example, solids loading must
be below a critical level to avoid any logjam effect that could occur as the fluid
passes through the screen; particle size distribution must be carefully controlled as just
a few percent of large particles bridging in
the screen may allow the many smaller particles to form an impermeable cake; and
particle cohesiveness must be limited as
e ven fine particles—such as weighting
agents—may agglomerate into much larger
particles. The total volume of mud that will
be flowing per unit area of screen should be
calculated and an excess used in the laboratory tests; the field mud actually used to drill
the horizontal section should also be tested
on the screens (above).
Completing the Picture
Many of the steps described above are not
novel. What is new is a much clearer acceptance that drilling fluid design is one part of
a much bigger process. To understand how
a reservoir will perform implies deep knowledge of the number and type of wells
needed; their length, angle and completion
type; and how they will perform—including
anticipated pressure drawdown and water
coning. Drilling fluid design is an integral
part of all of these.
There is a wide range of available fluids. To
select the right one means that the mud and
drilling engineers must talk to many other
specialists—reservoir geologists, production
chemists, drillers, completions engineers and
logging engineers—to establish their objectives. The task then is to choose a drilling
fluid that, in addition to meeting HSE needs
and achieving the primary objective of ensuring the well can be drilled, helps achieve
these shared objectives. In the end, this
means delivering a well that has sustained no
more than an acceptable level of damage.
The key is knowing what this acceptable
level is and how a given mud will affect a
given formation in a given drilling situation.
This need for understanding has been driving
research at BP Sunbury, SCR and elsewhere.
The final piece needed to complete the picture is an assessment of actual results over
the lifetime of wells. This process is only just
beginning, but when complete, drilling engineers will know that although zero damage
is preferable for horizontal wells, permeability reduction is sometimes allowable.
—CF
Oilfield Review