An Overview of Formation Damage

Prévia do material em texto

Introduction
Formation damage is a hot topic these days—with justifiable
reason, as more operating companies move to the exploitation of
more and more challenging oil and gas reservoirs in tighter, deep-
er, and more depleted conditions. Disappointing production or
injection results from an oil or gas well can be related to a number
of factors which may be difficult to diagnose. Some of these may
center about poor inherent natural reservoir quality characteristics,
others about mechanical considerations surrounding the condition
and type of the wellbore obtained, and still others under the nebu-
lous catch-all of “formation damage” which often (and sometimes
unjustly) absorbs the majority of the blame for the poor results of
many projects.
Formation damage in oil and gas wells is difficult to quantify in
many cases. This is due to the inability of the reservoir engineer to
retrieve exact samples and conduct detailed measurements on the
area of interest, usually represented by a volume of rock surround-
ing the wellbore which is generally several thousand meters below
the surface of the earth. However, ongoing research over the years
has allowed the development of a variety of techniques allowing
the use of the available information to obtain a much better indi-
cation of the type and degree of damage which different reservoirs
may be sensitive to, thereby adjusting operating practices to
attempt to minimize or reduce these permeability reducing factors.
This data would include information such as production and pres-
sure data, pressure transient data, log analysis, fluid and PVT data
and core, cuttings, and special core analysis data. The subject of
this brief article is to provide a synopsis of some of the types of
formation damage which commonly present themselves as prob-
lems for many oil and gas producing projects, and review some of
the associated technology being used to overcome these problems.
How Much of a Concern is Formation
Damage?
A technical definition of formation damage would be “any
process that causes a reduction in the natural inherent productivity
of an oil or gas producing formation, or a reduction in the injec-
tivity of a water or gas injection well.” Although the drilling
process often bears the brunt of the blame, formation damage can
occur at any time during the life of a well including completion,
production, stimulation, kill, or workover operations. Often the
problem is ignored due to a combination of ignorance and apathy
with the common rationale that “We don’t care about formation
damage in this reservoir—we can always fracture through it.”
Surprisingly, this pretense may make sense in certain situations,
particularly when the formation is of such low inherent quality that
it is obvious the flow area and driving differential pressure avail-
able for production present in a normal cased and perforated or
open hole completion are insufficient to sustain economic produc-
tion rates, even with a totally “non damaged” well. In this case,
since most drilling and completion related mechanisms of damage
tend to be localized in the near region and may be relatively easi-
ly penetrated by a fracture treatment, more technology and effort
may be associated with attempting to design a stimulation program
that is reservoir compatible and non-damaging, rather than wasting
a large degree of effort and expense on the initial drilling program.
However, in situations where near wellbore damage will be of
prime importance—most notably in open hole completions—the
issue of near wellbore drilling and completion induced formation
damage becomes very significant. This is illustrated in Figure 1.
An Overview of Formation Damage
Mechanisms Causing a Reduction in
the Productivity and Injectivity of
Oil and Gas Producing Formations
D. Brant Bennion is Hycal’s president
and is a project engineer with over 20
years of domestic and international
technical expertise in the area of forma-
tion damage and fluid flow in porous
media. Brant has authored or co-
authored over 170 technical papers on a
variety of subjects, including multi-
phase flow in porous media, formation
damage, underbalanced drilling, fluid
phase behavior and enhanced oil recovery. Brant received his
B.Sc. in chemical and petroleum engineering from the
University of Calgary with distinction in 1984 and is pursuing
his Ph.D. degree. He received Best Technical Paper of the Year
awards from the Petroleum Society in 1993 and 1995. Brant has
been a Director of the Petroleum Society on both the Calgary
Section and National Boards for over ten years and has served
in various capacities such as Continuing Education Director,
Student Affairs Director, Secretary, ATM Technical Program
Chairman, ATM General Co-Chairman and Chairman, and
Chairman-Elect of the Society. He is Chairman of the
Petroleum Society of CIM for 2002 and is also a member of
SPE. Brant is married and has four children.
FIGURE 1: Illustration of formation damage effects in open hole
and cased completions mechanisms of formation damage.
29 Journal of Canadian Petroleum Technology
Mechanisms of Formation Damage
Figure 2 provides a chart summarizing many of the common
formation damage mechanisms to which a reservoir may be sus-
ceptible. Upon first glance, evaluating formation damage appears
daunting with the large number of mechanisms present. How can
one discern what might be the primary and secondary damage
mechanisms that may be operable in a given reservoir with such a
vast array of conceivable candidates to choose from?
The prospect becomes less disconcerting when formation dam-
age is considered from a mechanistic point of view. As can be seen
in Figure 2, there are four primary mechanisms of formation dam-
age:
1. Mechanical
2. Chemical
3. Biological
4. Thermal
Each of these can be further subdivided into discrete sub-mech-
anisms. Technology exists in numerous situations to allow an
accurate determination of the types of damage to which a given
reservoir is susceptible.
Mechanical Formation Damage
Mechanical damage mechanisms are related to a direct, non-
chemical interaction between the equipment or fluids used to drill,
complete, kill, or stimulate a well and the formation resulting in a
reduction in the permeability of the formation. In some situations,
changes in the properties of the reservoir fluids themselves during
production operations may also cause certain types of mechanical
damage. Common mechanical impairment mechanisms would
include:
Fines Migration
This refers to the motion of naturally existing particulates in the
pore system caused by high fluid shear rates. These may include
various types of uncemented clays (dominantly kaolinite and den-
dritic illite, quartz or carbonate fines and rock fragments, mica,
anhydrite, pyrobitumen, etc.). Generally, fines migration tends to
be more of an issue in clastic formations due to the higher con-
centration of potentially transportable materials (such as clays).
The problem can also be present in carbonates though, so careful
FIGURE 2: Common formation damage mechanisms.
FIGURE 3: Effect of wettability on fines migration (illustration
shows a water wet case).
November 2002, Volume 41, No. 11 30
evaluation of the composition and degree of cementation of poten-
tially mobile particles in the pore system is essential.
Fines migration is usually only apparent when the wetting phase
of the reservoir (which wets and encapsulates the fines) is in
motion (Figure 3). For example, in a strongly water wet formation
which is at the irreducible water saturation as seen in Figure 3, oil
or gas production can occur at high rates with limited or no prob-
lem with fines migration. This is due to the fact that there is no
impetus for physical migration since the phase that is encapsulat-
ing the fines is not in motion. It is only when the wetting phase sat-
uration increases to the point where mobility occurs (e.g. water
coning or water breakthrough), that fines migration becomes prob-
lematic.If the formation is non-water wet, problems with fines
migration may be apparent immediately on producing the forma-
tion (as in this case where the wetting phase (oil) will immediate-
ly be mobile).
Reservoirs displaying severe fines migration problems may be
treated by either: reducing production rates (not often a popular
choice); increasing flow area by high density perforating, open
hole completions, horizontal wells, or fracturing to reduce intersti-
tial velocity; or by chemical stabilizers to adhere the mobile clays
to the pore surfaces to reduce the propensity for mobilization(3).
These chemical stabilizers are often high molecular weight poly-
mers and care must be taken in their use so they do not cause dam-
age due to physical adsorption issues.
External Solids Entrainment
This refers to the invasion of particulate matter suspended in
drilling or other fluids which may be injected or exposed in an
overbalanced condition to the rock matrix surrounding the well-
bore. This matter often may consist of a variety of suspended
solids in drilling fluids (weighting agents, fluid loss control agents,
bridging agents, lost circulation materials, and naturally generated
rock flour or drill solids). In most formations, unless permeability
is very high (large fractures and vugs or Darcy-type permeabili-
ties) or overbalance pressures are extreme (in excess of 7-10 MPa),
the majority of this damage is confined to a region generally very
close to the wellbore (1-2 cm in depth). If perforated or fractured
completions are contemplated, this type of damage may not be sig-
nificant. However, as discussed previously, in an open hole or
uncemented liner situation this type of damage may be very severe
as production through this zone of thin, but possibly very severe
damage, is required. Since the majority of horizontal wells fall into
this category, this damage type is often one of the more primary
concerns in the proper design of low damage overbalanced “drill
in” fluids. These fluids may contain a variety of sized bridging
agents and other materials to assist in the rapid formation of a
bridging filter cake. Considerable research has been conducted in
the area of non-invasive filter cake building ‘drill in’ fluids in the
past several years (4 - 6).
The exact criterion for proper particle bridging depends highly
on particle and pore system geometry, wettability, and flow
regime. Generally in turbulent flow conditions (high rate flow),
particles larger than about 25-30% of the pore throat aperture
through which they are being displaced have the capability of
bridging and causing significant reductions in permeability. At
lower flow rates (laminar flow conditions), much smaller particles
(down to 5-7% of the pore throat aperture) have been illustrated to
have the ability to form meta-stable bridges which can reduce per-
meability substantively.
Water injection and disposal operations also fall into the cate-
gory of possible damage due to solids invasion because of the pres-
ence of suspended solids in many injection fluids (produced fines,
corrosion products, scales and precipitates, dead and live bacteria,
etc). The dominant question often asked is how much filtration is
required to avoid large reductions in injectivity due to suspended
solids injection. In general (depending on water quality), filtration
to about 20% of the median (D50) pore throat diameter is usually
adequate to avoid massive and rapid reductions in injectivity due
to suspended solids plugging issues.
Phase Trapping and Blocking
This is related to a combination of adverse capillary pressure
and relative permeability effects. This is illustrated for a low per-
meability gas reservoir in Figure 4. The basis of a phase trap is a
transient or permanent increase in trapped fluid saturation (either
water, gas, or hydrocarbon) in the pore system surrounding the
wellbore, causing a reduction in relative permeability to the phase
which we desire to produce or inject. Frequent circumstances
which may result in phase trapping may include:
• Invasion of water-based fluids/filtrates into regions of low
water saturation and resulting trapping effects on ensuing
drawdown. Certain low permeability gas reservoirs and some
oil wet oil reservoirs often exhibit this tendency;
• Invasion of oil-based fluids/filtrates into zones of low or zero
oil saturation and resulting trapping effects on subsequent
drawdown—a common occurrence in some gas reservoirs and
also in water injection projects where slugs or “skim” oil is
inadvertently injected into a zone previously highly saturated
with water or oil-based fluids are used in dry gas reservoir or
water injection well situations;
• Production of rich retrograde condensate type gases below the
dewpoint pressure resulting in the accumulation and trapping
of a critical retrograde condensate saturation in the near well-
bore region;
• Production of black oils below the bubble point resulting in
the release of gas from solution and the formation of a trapped
critical gas saturation; and,
• Injection of free gas (aerated fluids and foams during poorly
designed UBD operations, non deoxygenated brines, nitrogen
energized fluids, etc.) into a fluid saturated zone resulting in
the creation of a trapped critical gas saturation.
The severity of phase trapping problems is a strong function of
the increase in trapped saturation, depth of invasion, reservoir
pressure available for drawdown, and most importantly, the spe-
cific configuration of the relative permeability curve for the rock
under consideration. Phase trapping has been documented in many
situations to cause severe/total reductions in productivity and is
one of the few types of formation damage capable of causing total
occlusions (100% reduction) in permeability. This makes this dam-
age mechanism problematic, even in the design of fracturing treat-
ments where, in general, fairly large amounts of fracture face dam-
age can often be tolerated due to the large inflow area created dur-
ing a typical fracture treatment.
Phase trap problems are often treated in a prophylactic fashion
by attempting to avoid the use of fluids most prone to trapping in
a reservoir. Even underbalanced drilling operations have been
demonstrated to be affected by phase trapping due to countercur-
rent capillary imbibition effects which can be operative in some
reservoir circumstances. Other techniques used to remove or
FIGURE 4: Illustration of water based phase trapping effects in a
low permeability gas reservoir.
31 Journal of Canadian Petroleum Technology
reduce the effects of phase trapping include the use of surface ten-
sion reducing agents to lower capillary pressure effects that are the
basis for phase trapping. These IFT reducers include various sur-
factants, alcohols, and carbon dioxide. Mechanical techniques for
water block removal would include dehydrated gas injection to
evaporate trapped water as well as formation heat treatment and
other more novel stimulation techniques (7 - 10).
To remove trapped hydrocarbon liquids, consideration is given
to various types of lean or rich gas injection, miscibility removed
entrained liquid, as well as more novel techniques such as in situ
combustion via air injection.
Glazing/Mashing
This refers to direct damage to the wellbore face caused by
bit/heat interactions (glazing) or poorly centralized rotating and
sliding pipe in a poor hole cleaning situation, resulting in the work-
ing of fines and cuttings into the formation face. This damage
mechanism is difficult to simulate on a laboratory basis, but has
been clearly observed on a downhole basis from sidewall and con-
ventional full diameter core samples. This effect is generally min-
imized by proper lubricity at the bit (to reduce glazing which tends
to be most prevalent in pure gas/air drill operations due to heating
effects associated with the poor heat transfer capacity of pure gases
in comparison to liquids). Mashing is reduced by good hole clean-
ing to avoidlarge amounts of solids present in the hole(11).
Geomechanics
The creation of a void space in the reservoir matrix (by the
drilling of the wellbore) removes load-bearing rock and often
results in the distortion of the geomechanical stress regime in a
region directly adjacent to the wellbore. Although this region is
generally fairly small depending on the well orientation and the
reservoir stress field under consideration, either contractile or
compressive stress fields can be induced which may result in a
change in the pore geometry and permeability character in the near
wellbore region (12, 13).
Perforation Damage
The detonation of perforation charges may result in the creation
of a crushed zone and generate mobile fines adjacent to the perfo-
ration tunnel, possibly reducing the permeability in this region (14, 15).
The composition of the perforating fluid, if perforating overbal-
anced, may also have a significant impact on damage effects.
Proppant Crushing and Embedment
This is a damage mechanism which can reduce the effective
conductivity of an artificially generated hydraulic fracture.
Normally a proppant (sand or synthetic) is placed to hold the frac-
ture open after the fracture pressure has been released to maintain
high permeability to the newly accessed portion of the reservoir. At
high closure stresses, conventional sand proppants can be mechan-
ically “crushed” which releases fines, reduces fracture diameter,
and may significantly reduce permeability. Embedment may be
associated with high closure stresses in plastic (soft) formations or
with angular, rough proppants which have minimal point contain
surface area. In both these situations, plastic extrusion of the prop-
pant into the formation face occurs, once again reducing effective
fracture diameter and permeability. Typically, high strength (e.g.
bauxite, carbolite, etc.) based spherical proppants are used to com-
bat these effects.
Chemical Damage Mechanisms
Chemical damage mechanisms fall into three broad classifica-
tions:
1. Adverse rock-fluid interactions
2. Adverse fluid-fluid interactions
3. Wettability alterations in the near wellbore region
Clay Swelling
This is another “classic” mechanism of formation damage and
involves the interaction and hydration of hydrophilic materials,
such as smectite or mixed layer clays, by reaction with fresh or low
salinity water. The expansion and sloughing of these clays can
cause severe reductions in permeability depending on the amount
and location of the clay in the pore system. The problem is espe-
cially severe if the clay is lining the pore throats as only a small
amount of expansion can result in a very large reduction in perme-
ability in this configuration. High salinity fluids, glycols, cationic
polymers and amines, and other inhibitors are often used to main-
tain clays of this type in a contracted or dehydrated state (16 - 18).
Clay Deflocculation
Less understood but often more common in occurrence than
clay swelling, clay deflocculation is caused by a disruption of the
electrostatic forces holding the surfaces of individual clay units
that are attracted to each other as well as the walls of the pore sys-
tem in a bunched or “flocculated” state. A rapid salinity shock,
change in divalent ion concentration from high to low, or rapid
transitions in pH (generally to a more caustic state) can all induce
deflocculation. Kaolinite is an example of non-water sensitive clay
which can be deflocculated under certain situations(19-22).
Deflocculation is inhibited by avoiding cationic and pH shocks.
Chemical Adsorption
Polymers and other high molecular weight materials present in
some fluids may become bound or adsorbed on the surface of the
formation matrix and clays and, by virtue of their large molecular
size, cause restrictions in flow area and hence permeability. This is
especially a problem in lower quality formations as illustrated in
Figure 5. Oxidants, such as sodium hypochlorite or enzyme solu-
tions specifically tailored to attack a given polymer substrate, are
commonly used to reduce and desorb the polymer in these types of
situations.
Formation Dissolution
Certain formation components (halite, various shales, anhy-
drite, etc.) may have limited to high solubility in water-based flu-
ids. This can result in poor gauge hole formation washouts, or col-
lapse in certain conditions, as well as the release of mobile and
potentially damaging fines. Oil-based fluids, inhibited fluids, or
saturated ionic systems are often used to combat these issues.
Paraffins and Waxes
Many oils exhibit low “cloud point” temperatures which can
result in the precipitation of crystalline in non-alkane based solid
hydrocarbons, or “waxes,” from solution in the oil. These solids
can result in the formation of bridging plugs of paraffin at or near
the perforations (common in high drawdown elevated GOR wells
due to localized cooling near the perforations because of Joule-
Thompson expansion effects) as well as in tubing and surface
equipment. Often treated with solvents, diluents, heat, or crystal
inhibitors, wax deposition can be extremely damaging in many sit-
uations (22, 23). Although wax deposition tends to be reversible with
the application of heat, generally a much higher temperature level
is required than the original level at which the paraffin precipitat-
FIGURE 5: Illustration of polymer adsorption effects and low and
high permeability porous media.
November 2002, Volume 41, No. 11 32
ed to fully drive it back into solution in the reservoir oil.
Other Solids
A wide range of organic and inorganic solids may also precipi-
tate from reservoir fluids and result in plugging difficulties down-
hole, in tubing, or surface or injection equipment. Organic solids
would include materials such as asphaltenes, which are high
molecular weight organics, that can be precipitated from oils by
reductions in temperature or pressure, or generated by contact with
incompatible oils, acids or alcohols. Diamondoids, which are the
gas reservoir equivalent of asphaltenes, hydrates, and elemental
sulfur, are other solid species which may precipitate from gases or
oils.
A wide range of inorganic solids and scales can be formed by
mixing incompatible waters, or by changes in temperature, pres-
sure, and pH of a given formation water stream which is being
injected or produced. Scales may be of an acid soluble (calcite) or
insoluble (gyp) nature, and can be toxic and radioactive in certain
situations. A wide range of chemical inhibitors and solvents are
available for various types of solids precipitation problems, and
the selection of the proper handling technique for a given reservoir
often tends to be very situation specific (25 - 28).
Emulsions
Emulsions often occur in oilfield operations. The most common
type of problematic emulsion is the “water internal emulsion” in
which small droplets of water are encapsulated in a continuous
external oil phase (Figure 6). These types of emulsions can exhib-
it very high viscosity (up to 2 – 4 orders of magnitude above clean,
non-emulsified oil) and hence may result in the formation of per-
meability-inhibiting “emulsion block.” Poorly designed spent
acids are a common offender in this area. “Foamy oil” would also
fall into the category of a stabilized emulsion where the oil forms
the eternal phase and small bubbles of trapped gas form the inter-
nal phase. Usually associated with high viscosity “heavy” oils,
these fluids have been documented to have viscosities substantial-
ly higher than non-foamy fluids (29).
Wettability Alterations
Many additives to oilfield fluids, particularly many surfactants,
defoamers, corrosion inhibitors, and some biocides, have polar
adsorptive tendencies which may cause them to establish an oil
wetting condition in the region of the reservoir in which they
invade. Figure 7 illustrates the phenomenon of a near wellbore
wettability alteration. Water wet rock, due to surface frictional
drag effects associated with the motion ofthe water phase, tends to
have fairly low endpoint relative permeability. Conversely if a
rock is oil wet, the water can move easily through the central por-
tion of the pore system, and effective endpoint relative permeabil-
ity and water mobility are often much higher. If a formation is ini-
tially water wet, transition to an oil wet condition is akin to plac-
ing a semi-permeable membrane around the wellbore which tends
to hold oil back and preferentially let water through. This may
result in an undesirable increase in producing water-oil ratio if a
mobile water saturation is present in the matrix (30 – 33).
Although this phenomenon is generally undesirable for a water
wet producing well, there may be cases where a deliberate wetta-
bility alteration is performed to increase water injectivity in a
water wet injection well. This is illustrated in Figure 8.
Modification of the wettability around the injection well (by sur-
factant or organosilane treatment, for example) may create a zone
of enhanced water phase permeability in the near wellbore region,
which may allow significantly higher water injection rates at an
equivalent injection pressure level. This is a common treatment in
low permeability sandstone injection wells.
Alteration of wettability to a more oil wet state in a water injec-
tion and disposal well may also have the benefit of isolating reac-
tive and migratable clay in a non-mobile hydrocarbon phase. This
may reduce problems significantly with clay reactions and migra-
tion in the near wellbore area as illustrated in Figure 9.
Biological Damage
This type of damage refers to problems created by the introduc-
tion of viable bacteria and nutrient streams into a reservoir.
Although most commonly associated with water injection opera-
tions, bacterial contamination has the potential to occur any time a
water-based fluid is introduced into a formation. Most bacteria
grow best at temperatures less than 90˚ C. However, long-term
injection of large volumes of water into deep, hot formations may
result in a reduction in bottom hole temperature to the point where
bacteria may survive and propagate. The three major damage
mechanisms associated with bacterial entrainment include:
FIGURE 6: Water-oil emulsion types.
FIGURE 7: Effect of a near wellbore wettability alteration for a
water wet producing well.
FIGURE 8: Effect of wettability alteration to a more oil-wet state to
improve water phase injectivity.
33 Journal of Canadian Petroleum Technology
FIGURE 9: Wettability effects on clay reactivity.
Plugging-Most bacteria secrete a viscous polysaccharide
polymer as a by-product of their life cycle which may adsorb and
gradually plug the formation.
Corrosion-Some types of bacteria set up an electrokinetic
hydrogen reduction reaction which can result in pitting and hydro­
gen stress cracking on metallic surfaces downhole in tubing or in
surface equipment.
Toxicity-A certain type of anaerobic bacteria, commonly
referred to as Sulfate Reducing Bacteria (SRB), reduce elemental
sulfate which may be present in formation/injection waters and
create toxic hydrogen sulfide gas.
Bacteria problems are often treated with oxidants, such as sodi­
um hypochlorite, which reduce the excreted polymer and eradicate
the bacteria. Various types of biocides are also often used. Due to
the fact that bacterial invasion is a difficult problem to totally cure
if the depth of invasion is significant, a preventative approach with
proper biological control in all introduced water-based fluids is
advisable in most cases (34). Currently, rapid detection kits to mon­
itor SRB activity by measuring hydrogenase levels can be used to
"real-time" monitor the downhole activity level of bacteria and
determine if modifications in biocide concentration or type are
required to control the problem before it becomes severe.
Thermal Damage
Thermal damage mechanisms refer to those associated with
high temperature injection operations (steam injection, in situ
combustion, etc.). These include (35-37):
Mineral Transformations-At temperatures over approximately
180' C, non-reactive clay species may be catalyzed and form
hydratable reactive products which may swell, desegregate, and
reduce permeability. These reactions are most pronounced at tem­
peratures above 250' C.
Dissolution-Mineral solubility increases with temperature.
Long-term dissolution may result in the release of encapsulated
fines or subsequent reprecipitation of the dissolved species when
the hot fluids move further into the reservoir or into production
wells and cool.
Wettability Alternation-Formations generally become more
water wet as temperature increases. However, there are isolated
circumstances of transitions to oil wet behavior on the application
to formations of superheated steam.
Reduction in Absolute Permeability-This has been document­
ed to occur under overburdened conditions at extreme tempera­
tures (in some cases). It is believed to be due to thermal induced
grain expansion and subsequent pore constriction. Thermal stress
cracking and manufacturing of mobile and damaging fines has also
been observed at high temperatures in some isolated studies.
Thermal Degradation-Over 200' C thermal reactions of sul­
fur-bearing compounds in oil and rock, as well as carbonate reac­
tions, may result in the production of large concentrations of
34
hydrogen sulfide, carbon dioxide, and mercaptans. The corrosive
nature and toxicity of some of these by-products can be problem­
atic in many cases.
Formation Damage in Horizontal Wells
Formation damage effects may be magnified in horizontal well
application situations. There are a number of causes of this, some
of them being:
1. Greater length of time is required to drill a typical horizontal
well, resulting in potentially deeper invasion depth (particu­
larly near the heel (first portion) of the wellbore).
2. Most horizontal wells are open hole or uncemented liner
completions. This means that shallow mechanical damage
which generally would not be a concern in a typical cased
and perforated well, now becomes a very significant barrier
to flow in a horizontal open hole application.
3. Due to the large open hole area of a typical horizontal well,
often non-uniform cleanup is obtained due to permeability
variations in the encountered formation. This may result in
the majority of the production being sourced from a small
portion of the horizontal wellbore and the inability to apply
enough drawdown to remove invasive damage from the
remainder of the interval.
4. U tube effects may exert sufficient backpressure to limit flow
in some high permeability-low drawdown situations.
5. In comparison to a vertical well where very invasive stimula­
tion treatments such as hydraulic fracturing or matrix acid
squeezes can be conducted in a relatively inexpensive fash­
ion, similar "deep" stimulations on the large exposed area of
a horizontal well are often prohibitively expensive. This
being the case, most horizontal well stimulation treatments
often consist of tubing conveyed near wellbore washes with
acid or other completion fluids and therefore tend to remove
only very localized damage.
6. Wellbore collapse and geomechanical issues can result in the
failure and loss of all or a portion of the effective length of
the horizontal well.
7. Anisotropic flow effects associated with variations in hori­
zontal to vertical permeability ratio impact the flow of hori­
zontal wells (whereas vertical well flow is impacted solely by
horizontal permeability). Damage effects tend to be increased
in severity the more adverse the horizontal to vertical perme­
ability ratio becomes. This is illustrated in Figures 10 and 11.
Conversely, high natural vertical permeability (e.g. natural
vertical fractures) tends to reduce the severity of damage
effects in a horizontal well situation.
FIGURE 10: Typical damage zone around a vertical well.
Journal of Canadian Petroleum Technology
FIGURE 11: Typical horizontal well damage profile.Evaluating Formation Damage
The potential areas of sensitivity to formation damage for most
reservoirs can be determined by increasing the understanding of
the reservoir. This is often accomplished by obtaining information
from field data, fluid samples, and core analysis methods, including:
1. Wettability
2. Capillary pressure
3. Initial and irreducible fluid saturations
4. Relative permeability character
5. Matrix and clay composition and location
6. Pore size and pore throat size distribution
7. Critical velocity (fines migration testing)
8. Whole mud invasion testing (return permeability testing)
9. Critical filtration testing
10. Salinity and salinity shocking tests
11. Water-water, oil-water, and emulsion testing
12. Scaling and precipitate modelling via geochemical analysis
of fluids
13. Proper knowledge of bubble and dewpoint of reservoir fluids
14. Evaluating cloud and pore point
15. Tests on the wetting properties of the proposed fluids on the
formation
16. Bacterial content and type in injection fluids
17. Potential for thermal damage effects at high temperature.
All of these issues can be evaluated by proper screening work
conducted in the laboratory. Figure 12 illustrates the appearance of
a typical core displacement apparatus used to conduct this type of
work in-house at Hycal Energy Research Laboratories in Calgary,
Canada.
FIGURE 12: Hycal core displacement apparatus
Summary
It can be seen that even when concentrating on only what are
considered to be "major" damage mechanisms, a large host of
potential problems may be present in a given reservoir. This vari-
November 2002, Volume 41, No. 11
ety of problems, however, are not often present in every reservoir.
Some formations are remarkably resilient and stubbornly resist the
efforts of even the most dedicated methods to damage them.
Others are sensitive to even the slightest misstep. A proper combi­
nation of integrating available field and laboratory analysis of the
rock, fluids, and specific practices used in a given situation can
result, in the vast majority of cases, with a considerable reduction
in the risk and potentially a large increase in the productivity of the
subject well. As with most things concerning formation damage, a
small bit a knowledge can go a long way towards allowing opera­
tors to make informed decisions as to the best practices to drill,
complete, and produce wells.
REFERENCES
I. MUECKE, T.W., Formation Fines and Factors Controlling Their
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7007, February 1979.
2. OYENENIN, M.B., et a!., Factors to Consider in the Effective
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3. RAHMAN, S.S., et a!., Prediction of Critical Condition for Fines
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7. BENNION, D.B., et a!., Remediation of Water and Hydrocarbon Phase
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Calgary, AB, June 10 - 12, 1996.
8. WARREN, B.K., et a!., Development of the Pekisko Dolomite in the
Bigoray Field. Issues in Formation Damage Mechanisms, Drilling
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9. HWANG, M.K. and ODEH, A.S., Estimation of Condensate Dropout
Effects on Well Productivity as Skin Changes with Multiplicative
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10. BENNION, D.B., THOMAS, EB., BIETZ, R.E, and BENNION,
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11. BYROM, T.G. and COULTER, G.R, Some Mechanical Aspects of
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35
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17. ZHOU, Z., et aI., Clay Swelling Diagrams: Their Applications in
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Clay in Porous Media by Polyacryclamide; paper SPE 3II09, present­
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20. SCHUERMAN, R.F and BERGERSEN, B.M., Injection Water
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23. HAMMANI, A., et aI., Paraffin Deposition from Crude Oils:
Comparison of Laboratory Results to Field Data; paper SPE 38776,
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24. STRAUB, T.I, AUTRY, S.w., and KING, G.E., An Investigation into
the Practical Removal of Downhole Paraffin by Thermal Methods and
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36
25. MINNSSIEUX, L., Core Damage from Crude Asphaltene Deposition;
paper SPE 37250, presented at the International Symposium on
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26. PIRO, G., et aI., Experimental Study on Asphaltene Adsorption onto
Formation Rock: An Approach to Asphaltene Formation Damage
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27. JORDAN, M.M., et aI., Scale Inhibitor Adsorption and Desorption
Versus Precipitation: The Potential for Extended Squeeze Life While
Minimizing FormationDamage; paper SPE 30106, presented at the
European Formation Damage Conference, The Hague, The
Netherlands, May 15 - 16, 1995.
28. CROWE, c., et aI., Scale Inhibition in Wellbores; paper SPE 27996,
presented at the University of Tulsa Centennial Celebration, Tulsa,
OK, August 29 - 31, 1994.
29. BENNION, D.B., CHAN, M., SARIOGLU, G., COURTNAGE, D.,
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30. SHARMA, M.M. and WUNDERLICH, RW., The Alteration of Rock
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32. CUIEC, L., Effect of Drilling Fluids on Rock Surface Properties; SPE
FE, SPE 15707, March 1989.
33. SANNER, D.O. and AZAR, U., Alteration of Reservoir Rock
Wettability and its Flow Properties Caused by Oil Based and Water
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34. HAYATDAVOUDI, A. and GHALAMBOR, A., A Study of Formation
Damage of Selective Clay and Other Minerals Caused by Bacterial
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35. GUNTER, W.D., et aI., Modelling Formation Damage Caused by
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Advanced Technology Series, Vol. 2., No.2, SPE 23786, April 1994.
36. GUPTA, A. and CIVAN, F, Temperature Sensitivity of Formation
Damage in Petroleum Reservoirs; paper SPE 27368, presented at the
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37. BENNION, D.B., THOMAS, FB., and SHEPPARD, D.A., Formation
Damage Due to Mineral Alteration and Wettability Changes During
Hot Water Injection and Steam Injection in Clay-Bearing Sandstone
Reservoirs; paper SPE 23783, presented at the 1992 Symposium on
Formation Damage Control, Lafayette, LA, February 26 - 27, 1992.
Journal of Canadian Petroleum Technology
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