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9. STIMULATION BY ACIDIZING
Contents
EXECUTIVE SUMMARY
.........................................................................................................................
9-1
9. STIMULATION BY ACIDIZING
............................................................................................................
9-3
9.1 Introduction
.............................................................................................................................
9-3
9.1.1 Objectives of Well Stimulation by Acidizing
......................................................................
9-4
9.2 Well Acidizing Stimulation Technology
....................................................................................
9-4
9.2.1 Total Skin factor and its use in OMV Petrom for Making
Decision for Acidizing .............. 9-5
9.2.2 Best Candidate Selection Process for Acidizing
.................................................................
9-7
9.2.3 Review of the Most Frequent Damages in OMV Petrom and
General Selection of Treatment
..........................................................................................................................
9-7
9.3 Well Acidizing Methods Applied in OMV Petrom
..................................................................
9-10
9.3.1 Sandstone
........................................................................................................................
9-13
9.3.2 Carbonate
........................................................................................................................
9-15
9.4 Technology Workflow of Best Practices for Fluid Selection,
Treatment Design and Job Execution
...............................................................................................................................
9-18
9.4.1 Sandstone Matrix Acidizing Treatment
...........................................................................
9-18
9.4.2 Applied Sandstone Design Procedure
.............................................................................
9-29
9.4.3 Carbonate Acidizing Best Practices
..................................................................................
9-36
9.4.4 Planning and Job , Execution of Acidizing Treatment
...................................................... 9-45
9.4.5 Job Evaluation and Control
..............................................................................................
9-48
9.5 Configuration of Surface Equipment for Acidizing
...............................................................
9-52
9.6 Fluids and Materials Used for Acidizing
.................................................................................
9-53
9.6.1 Additives (corrosion inhibitors, Iron-Control Agents, Clay
Stabilizers etc) ...................... 9-53
9.7 Quality and Safety Requirements for Acidizing
.....................................................................
9-54
9.7.1 Quality Control
.................................................................................................................
9-54
9.7.2 Health, Safety and Environmental Aspects of Acidizing
.................................................. 9-57
9.7.3 Personnel (Training, Supervision)
....................................................................................
9-59
Appendix 9-A Commercially Available Acid Systems Specification
Details.................................... 9-60
Appendix 9-B Commercially Available Additives and Solvent
Specifications ................................ 9-66
List of Figures
.................................................................................................................................
9-70
List of Tables
...................................................................................................................................
9-72
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References
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EXECUTIVE SUMMARY
EXECUTIVE SUMMARY: 9. STIMULATION BY ACIDIZING
No. Strongly Recommended
1.
Review the well logs, reservoir characteristics and previous
workovers to identify shortlist candidates with damage to the
wellbore, in the perforations and / or within the formations.
Clarify the factors causing skin damage on shortlist candidates and
determine which near wellbore flow restrictions can be removed by
acid treatment.
2. Involve careful consideration of fluid selection, the pumping
schedule, acid placement techniques and on-site treatment
monitoring.
3.
Use developed workflows (Figure 9-10 to Figure 9-16) for proper
fluid selection required for sandstone acidizing.
Mineral Composition > 100 mD 20-100 mD < 20 mD10% Silt and
>10 % Clay>10% Silt and < 10 % Clay>10% Silt and >
10 % Clay
10% HCl 7.5% HCl 5% HCl
4. Reduce the concentration of the HCl if the formation is
partially or totally dolomite and should be lowered wherever
silicate content of the dolomite is high in order to avoid
precipitation. Follow selection workflow in Figure 9-20.
5. In case of high bottomhole temperatures use slower reacting
weak organic acids. Special attention should be paid to the
concentrations of formic acid to avoid precipitation of calcium
formate.
6. Use retarded HCl (by gelling or emulsifying the acid), or
organic acids if bottomhole temperature is high (>120 oC).
7. The cleanliness of all tanks that will hold water or acid
should be verified and the acid tank must be circulated before
pumping. 8. Mix chemicals in recommended sequences. 9. Always keep
foam quality above 70%.
10. Carry out acid pickling of tubing string for all important
(costly) jobs. 11. Put the well into production immediately (no
reaction break) in high temperature wells. 12. Use nitrogen
displacement for gas wells. 13. Use diverting for long (> 25 m)
perforated intervals.
14. Use HBF4 when problems with migrating fines exist, what is
often case in the maturated wells completed with gravel pack.
15. Verify availability and specifications of all fluids
(additives, acid, surfactants, diverters) required to complete the
stimulation job
16. The injection rate and pressure is to be monitored and the
pressure kept below predefined levels (especially breakdown
pressure in sandstone).
17. Fluids pumped during the stimulation job are to be sampled
and analysed for post-treatment review.
18. Real-time formation response to stimulation fluids should be
recorded in a Field-Acid-Response-Curve (FARC) to enable swift
corrective action to be undertaken during the treatment job.
19.
Use standardized treatment report which describes fluid QC data,
pump rates, tubing and annular pressure measurements, types and
volumes of fluids and diverters, deviations from the program,
pumping interruptions and any other problems which influenced the
execution of the treatment job.
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EXECUTIVE SUMMARY: 9. STIMULATION BY ACIDIZING
No. Not Recommended at All
1. To exceed frac pressure during treatment operation.
2. To use HF + KCl or formation brine.
3. If doing foam injection frac pressure is reached do not
decrease foam quality, just stop nitrogen.
4. To start treatment if all fluids which are pre-blended at the
service company facility are not subjected to quality checks.
5. To use diverting for short (< 25 m) perforated
intervals.
6. To use mud acid to treat formations if HCL solubility is >
20%.
7. To start acidizing treatment if sufficient injectivity is not
obtained.
8. To use of HCl preflush after dry tests in exploratory/wildcat
wells.
9. To continue the treatment if the surface pressure rises
sharply or rises continuously for certain volume of acid
(0.5-1m3).
10. To delay the well shut-in time after acidizing treatment in
order to minimize precipitation of reaction product.
11. To use NaCl, KCl, or CaCl2 brines in any HF treatment stages
or in any stage immediately preceding or following HF stages.
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9. STIMULATION BY ACIDIZING
9.1 Introduction
There are two basic stimulation methods which can be used to
eliminate formation damage and increase well productivity: matrix
acidizing and fracturing (hydraulic and acid).
Matrix stimulation by acidizing is injecting an acid/solvent at
below the fracturing pressure of the formation in order to
dissolve/disperse materials that impair well production in
sandstone reservoirs or to create new unimpaired flow channels in
carbonate reservoirs.
In the case of injecting acid below the fracturing pressure the
injected acid dissolve some of minerals present, and hence,
reestablish or increase the permeability inner-wellbore vicinity
(not deeper than 0.1 to 0.3m in sandstone reservoir and 1 to 3 m in
carbonate reservoirs). Matrix acidizing can significantly enhance
the productivity of a well when near-wellbore formation damage is
present, and conversely, is of little benefit in an undamaged well.
Thus, matrix acidizing should generally be applied only when a well
has a high skin effect that cannot be attributed to partial
penetration, perforation efficiency, or other mechanical aspects of
the completion.
The most common acids used in OMV Petrom are hydrochloric acid
(HCl), used primarily to dissolve carbonate minerals, and mixtures
of hydrochloric and hydrofluoric acids (HF/HCl), for attacking
silicate minerals such as clays and feldspars. Other acid
formulations, particularly some weak organic acids, are used in
special applications.
Acid fracturing, resulting from the injection of fluids at
pressures above the formation fracture/parting pressure, is
intended to create a path of high conductivity by dissolving the
walls of the created fracture in a non-uniform way. Acid fracturing
is sometimes used to overcome formation damage in relatively
high-permeability formations. However, carbonate reservoirs of
relatively low permeability may also be candidates for acid
fracturing. In acid fracturing, the reservoir is hydraulically
fractured and then the fracture faces are etched with acid to
provide linear flow channels to the wellbore.
Acid fracturing of relatively homogenous carbonates will produce
smooth fracture faces that will retain little fracture flow
capacity when treating pressure is released. Acid fracturing of
heterogeneous carbonates can develop non-uniform etching of the
fracture face. The area that is not etched acts as a support for
the etched areas, thus providing flow channels in the fracture and
significant increases in well productivity. It is suggested that
laboratory tests be conducted on cores to determine the etching
characteristics of the rock before treating a well. In some
instances, the non-etched area of a heterogeneous carbonate will be
softened by acid and will not support the fracture when treating
pressure is released. The only alternative would be hydraulic
fracturing and propping with sand. Two other problems can exist in
acid fracturing: (1) Un-dissolved fines can significantly reduce
fracture flow capacity if not removed with spent acid and
suspending agents, usually surfactants or polymers will materially
aid in the removal of these fines (2) Emulsions can block the
etched fracture. API RP 42 tests should be performed to select an
emulsion preventing surfactant for the acid treatment.
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Acid fracturing is rarely used in the treatment of sandstones,
because acid, even hydrofluoric acid (HF), does not adequately etch
these fracture faces. However, treatments have been successful in
some sandstone formations containing carbonate-filled natural
fractures. Removal of these carbonate deposits often results in
sufficient conductivity to yield excellent treatment results.
The results of field studies in Sotanga Meoian, Targoviste Rsvad
Gura Ocnitei Meoian III, Calinesti Dacian, Moreni, Gura Ocnitei and
South Dacian, which are in an maturated/advanced stage of
production consisting mostly of high permeability sand layers with
high variation of stability (good to poor ) have been used in
formulating the stimulation acidizing best practices in OMV
Petrom.
9.1.1 Objectives of Well Stimulation by Acidizing
The key objectives of well acidizing in OMV Petrom are to:
Remove near wellbore formation damage and decrease skin factor
Restore damaged matrix permeability in near well-bore reservoir
area Improve matrix permeability in near well-bore reservoir area
Maximize well productivity Remove deposits from well
tubular/wellbore cleanout.
The improvement in productivity of wells that can be realized
with matrix stimulation as shown in Figure 9-1 The plot shows that
acidizing is more effective in restoring the original permeability
by removing formation damage, than in increasing permeability over
its original value. This is used as principal guidance in the
company for selecting the best well candidate for application of
stimulation by acidizing.
9.2 Well Acidizing Stimulation Technology
In sandstone formations, acid treatments aim to remove
near-wellbore flow restrictions and formation damage. The goal of
these treatments is to return the near-wellbore area to its natural
condition. In carbonates, dissolving matrix is one of the
objectives, but bypassing a damage of the nearwellbore by creating
new channels is the primary target.
Usually, wellbore damage is caused by drilling or completion
operations, fines migration, clay swelling or polymer plugging. To
select an optimized fluid system for effective stimulation, the
type of damage and the formation mineralogy must be known. The
structured process of the design of a well acidizing stimulation
job the following main phases:
1. Candidate selection and proper diagnosis of damage type - The
best candidate well for a stimulation treatment is selected,
regardless of the type of stimulation/remediation needed.
Candidates are wells with damage to the wellbore, in the
perforations and / or within the formations which is
acid-removable. If the damage is not acid-removable, then it should
not be acidized and is not a candidate. During this phase, the best
treatment for the type of damage must be determined by assessing
and, ideally, measuring the skin. The economically most attractive
candidate is then selected based upon expected production
gains.
2. Fluid selection - The appropriate fluids, acid types,
concentration, treatment volumes and additives are selected.
Careful thought should be given to the determination of appropriate
additives and combinations for each case.
3. Pumping schedule and execution sequences - The number of
stages and how much to pump in each stage (volumes, rates and time)
are determined.
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4. Acid placement and techniques - detailed simulation of the
acidization process using the planned pumping schedule should be
undertaken, including diversion. A major reason for unsuccessful
acid treatments is that the acid does not go where it needs to go.
Determination of the proper fluid placement method is thus a key
factor in acid treatment design in both carbonates and
sandstones.
5. Treatment monitoring, quality control and on site evaluation
-The actual skin changes resulting from the stimulation treatment
are compared to the predicted results. Quality control steps
(during rig-up, before pumping, during pumping and flowback) should
be implemented.
9.2.1 Total Skin factor and its use in OMV Petrom for Making
Decision for Acidizing
The skin is an important factor to decide whether or not to
stimulate a well and what generic type of treatment would be most
suitable. Since it represents the total additional pressure drop as
compared to ideal conditions, in the near-wellbore region, its
value is the combined effect of several parameters, including
formation damage. To properly interpret the skin and therefore
determine the appropriate remedial action, field engineers must
analyze the contribution of each factor. This analysis should
involve identifying skin damage which could be removed by
stimulation and may result in additional opportunities for
production improvement such as re-perforating. Candidate
identification therefore requires an understanding of the various
skins and recognizing skin damage.
The production of newly completed well or worked-over well may
be lower than expected, due to wellbore damage from the
drilling/completion/workover process, or by mechanical difficulties
in the overall completion process. All of these problems will
result in an additional pressure drop near the wellbore, and thus
affect the skin factor. Therefore, the key to candidate selection
lies in the analysis of the various skin components. In Table 9-1
these skin component characteristics are summarized. Table 9-1
Summarized skin components
Skin Components CharacteristicsS Total skin factor (Horner
skin)
SdamSkin caused by formation damage (positive). It is the
component that needs to be removed with the matrix treatment.
Spart
Skin caused by limited perforation height (positive). It results
from the well not being perforated over the complete reservoir
height, such as to minimise gas or water coning.
Sdev
Skin caused by wellbore deviation (negative). At high deviation
angles, the increased effective length of the reservoir section
open to inflow increases the natural well productivity.
SperfSkin caused by the presence of small perforations (positive
or negative). The skin depends on the perforation size and
phasing.
Sd,perf
Skin caused by reduced crushed-zone permeability around
perforations (positive). Difficult to estimate due to many
parameters that cannot be estimated reliably, like permeability of
crushed zone, actual depth of penetration.
Sperf
Skin caused by gravel packing (usually positive). Theoretically,
it may have a negative value in underreamed, open hole, gravel
packed wells because of the increased effective wellbore
radius.
Sturb
Skin caused by turbulent (non-Darcy) flow, mainly applicable to
gas (positive). It is often caused by flow convergence because of
inadequate dimensions and an inadequate number of perforations.
Figure 9-1 illustrates how the skin factor varies with the
damage ratio, kd/k, and damage zone radius, rd, for a vertical well
with a radius of 0.0762 m. These variables determine the magnitude
of the skin factor and control the well productivity. For instance,
a reduction in permeability to less than one tenth of the initial
value within 0.6 m of the wellbore axis results in a skin factor of
approximately 18.7.
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Figure 9-1 Skin factor as a function of damage radius and damage
ration (kd/k)
The skin effect is a composite variable. The following sources
of the nonideal flow should consider:
Formation damage, Limited entry completions effects, Perforation
effects, Saturation blockage near the wellbore, and Gravel-pack
completion effects.
The composite skin factor can be calculated from well test data.
It is very important to separate the observed skin factor into its
components and to establish which near-wellbore flow restrictions
can be removed by stimulation treatment and which require workover
or recompletion. For good understanding of the skin related
concepts it is enough to consider pseudo-steady flow only.
Figure 9-2 Pressure profile of damaged and undamaged well
Skin, S, is the composite of all non-ideal conditions affecting
flow into the wellbore, and may generally be written, with its main
components, as:
= + + + ++ + (9-1) The last term in the above expression
represents an array of pseudoskin factors. These pseudoskin effects
are generally mechanical, resulting from obstructions to flow or
because of turbulence effect and additional pressure drop. The real
skin due to formation damage is that portion of the total skin that
can be removed by matrix treatments. Sdam describes the
permeability of the damaged to undamaged zones and the damaged
radius, as shown on Figure 9-2.
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9.2.2 Best Candidate Selection Process for Acidizing
Despite the extensive research efforts done by the industry on
the root cause of formation impairment and its remediation by
matrix treatment, the failure rate of matrix acidizing treatments
today is estimated at 60 to 70%. Worldwide, this failure rate
represents a loss of millions of dollars in wasted stimulation
expenditure and missed production. The primary causes for failed
treatments have been poor candidate selection and poor treatment
design with respect to fluid selection and placement. Another
reason for the high failure rate of matrix acidizing treatments is
the lack of proper technology transfer to the field. Because the
industry often sees matrix treatments as low-technology treatments,
little attention is given to design.
Many candidates are normally selected by each Asset and they are
sending for evaluation. The process of candidate selection applied
in Assets includes:
Prepare list of candidate wells, Review of well logs/records,
reservoir characteristics and information on the
completion/previous workovers, Map the productivity of each
well, Establish reasonable upper production potential for matrix
stimulation techniques, Evaluate potential mechanical problems, and
Focus on wells with the highest reward and lowest risk.
The candidate wells are then analyzed by Stimulation Team in
Production Engineering according to the following six criteria:
1. PVT matching in order to select the best PVT correlation to
simulate well behavior when acid is injected.
2. Verification of the remaining reserves and the current water
saturation. 3. Evaluation of an approximate damage type from
history well data and skin factor using
an analytical model (Resestim 7 in house made software or
licensed software Prosper for integrated system analysis).
4. Predict well productivity index (PI) increase after
stimulation job based on new skin. 5. Make production forecast
using material balance equation for oil and gas wells. 6. Estimate
NPV and Cash Flow based on production forecast.
All economically feasible wells are candidates. The design of
the stimulation is made for the economically most attractive
candidates. A system for the selection of the acid should be used
and the calculation of the other design parameters is based on
models/algorithms that will be explained later.
9.2.3 Review of the Most Frequent Damages in OMV Petrom and
General Selection of Treatment
Once damage has been characterized in a well, its origin must be
ascertained to help determine the correct remedial action. Various
types of damage can exist since almost every operation performed on
the well is a potential source of damage. The physical
characteristics of the damage are an essential parameter since this
determines the desired characteristics of the treating fluid. The
physical characteristics of the damage are the main criterion
adopted to categorize the various types of damage indicated in
Figure 9-3 (seven basic types of damages).
Emulsions
The intermixing of oil- and water-base fluids in the formation
often results in the formation of emulsions. Emulsions can have
high viscosity, particularly water-in-oil emulsions. Typically,
they are
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formed due to invasion of drilling/completion filtrate or
treatment fluids into the formation. High pH filtrates from mud or
cement slurry or low pH filtrate from acidizing can emulsify some
formation oils. Similarly, hydrocarbon filtrates from oil-based
drilling or stimulation fluid can form emulsions with some
formation brines. Emulsions are stabilized by surface active
materials (surfactants) and by fines, which are either present in
the "treating" fluids or are generated through the fluid/rock
interaction. Generally, mutual solvents with or without
demulsifiers are used for treating such problems.
Figure 9-3 Formation damage types
Wettability Change
Partially or totally oil wetting a formation reduces the
relative permeability to oil. This may occur due to adsorption of
surface active materials from oil-based drilling, workover or
completion fluids on the rock. This type of damage is removed by
the injection of mutual solvents to remove the oil wetting
hydrocarbon phase, followed by the injection of strongly
water-wetting surfactants.
Water Block
A water block caused by an increase in the water saturation near
the wellbore decreases the relative permeability to hydrocarbons.
Waterblock can form either during drilling and completion
operations through invasion of water-base filtrate, or during
production through fingering or coning of formation water. The
formation of a water block is favored by the presence of pore
lining clays such as illite. The hairy shape and large surface area
of these clays increase the adsorption of water on the pore
wells.
A water block is usually treated by reducing the surface tension
between water and oil (HF acids). Nonaqueous acids (such as
alcoholic acid) are particularly suitable in (gas) wells where a
water block problem is suspected because they also increase the
vapor pressure and reduce the surface tension between water and
gas.
Scales
Scales are precipitated mineral deposits. They can precipitate
in the tubing, perforations and/or formation. Scale deposition
occurs during production because of the lower temperatures and
pressures encountered in or near the wellbore. Scales can also form
by mixing of incompatible waters: formation water and either fluid
filtrate or injection water. Various solvents can be used to
dissolve scales, depending on their mineralogy. The most common
types of scales encountered in a well are:
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Carbonate scale (CaCO3 and FeCO3): CaCO3, is the most common
scale, occurring in reservoirs rich in calcium and carbonate and/or
bicarbonate ions. Hydrochloric acid will radial dissolve all
carbonate scales.
Sulphate scales occurring mainly as gypsum (CaSO4, 2H2O) or
anhydrite (CaSO4). The less common barytine (BaSO4) or strontianite
(SrSO4) is much more difficult to remove but, their occurrence is
more predictable. EDTA will dissolve calcium sulphate. Barium and
strontium sulphates can also be dissolved with EDTA provided the
temperature is high enough and the contact times sufficiently long
(typically 24 hr soaking period is required for a 4000m well with a
BHST of about 100oC
Chloride scales such as sodium chloride: These are easily
dissolved with fresh water or very weak acidic (HCl, acetic)
solutions.
Iron scales such as sulphide (FeS) or oxide (Fe2O3):
Hydrochloric acid with reducing agents and sequestrant will
dissolve such scales and prevent the reprecipitation of by-products
such as iron hydroxides and elemental sulphur.
Silica scales: Generally occurring as very finely crystallized
deposits of opal or chalcedony. Hydrofluoric acid can dissolve
silica scales.
Hydroxide scales such as magnesium (Mg[OH]2) or calcium
(Ca[OH]2) hydroxides: Hydrochloric acid or any acid that can
sufficiently lower the pH and not precipitate calcium or magnesium
salts can be used to remove such deposits.
Contact time is a very important factor to consider in the
design of a scale removal treatment. The major problem when
treating scale deposits is to allow sufficient contact time for the
acid to reach and effectively dissolve the bulk of the scale
material. The treating fluid must contact and effectively dissolve
most of the scale in order for the treatment to be successful.
Organic Deposits
Organic deposits are precipitated heavy hydrocarbons (paraffin
or asphaltenes). They are typically located in the tubing,
perforations and/or the formation. Although the mechanisms of
creation of organic deposits are numerous and complex, the
principal mechanism is a change in temperature or pressure near the
wellbore during production. The heavy hydrocarbon fractions do not
remain dissolved in the oil and begin to crystallize. Cooling down
the wellbore or injecting of cold treatment fluids has the same
overall effect as a temperature drop during production.
The deposits are usually re-dissolved by organic solvents.
Blends of solvents can be tailored to a particular problem, but an
aromatic solvents is an efficient, general purpose solvent,
particularly for paraffins. The addition of a small amount of
alcohols is often beneficial when dissolving asphaltenes.
Organic deposits must not be confused with another type of
deposit called sludge. This deposit is a reaction product between
certain crude oils and strong inorganic acids. Once formed, sludge
cannot be dissolved.
Mixed Deposits
Mixed organic/inorganic deposits are a blend of organic
compounds and either scales or silts and clays. When migrating
fines associated with an increase in water production in a
sandstone reservoir become oil-wet, they act as a nucleation site
for organic deposits. This type of combined deposits requires the
use of a mixed solvent.
Silts and Clays
Damage due to silts and clays includes the invasion of the
reservoir permeability by drilling mud, the swelling and/or
migration of reservoir clays. Clays or other solids from the
drilling, completion or workover fluids can invade the formation.
When the differential pressure is sufficiently large and the
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size of the particles is smaller than the pore throat openings,
they are forced into the pore network and tend to plug the network,
resulting in damage.
When water-based filtrate from drilling, completion, workover or
treating fluids invades the porosity of the reservoir, it can
disturb the equilibrium between the clays and formation water. This
is normally due to a change in salinity, which creates imbalances
in the forces between clays. Smectite clays can swell and
drastically reduce permeability. Flocculated aggregates of
kaolinite can be dispersed, and subsequently block pore throats.
This disturbance of native clays is the most common and, probably
the most important cause of damage.
During production, particles can become dislodged and migrate
with the produced fluids. The particles can bridge near the
wellbore resulting in reduced productivity. When the damaging
particles come from the reservoir rock, they are usually referred
to as "fines". This is a generic term that includes clays
(phyllosilicates with a size of typically less than 4 micrometers)
and silts (silicates or aluminosilicates with a size between 4 and
64 micrometers). These particles are soluble in hydrofluoric acid
mixtures.
Damage due to fines is located in the near wellbore area within
a 0.9 m to 1.2m radius. Damage may also occur in a gravel pack in
sandstones it is removed by treatment with an acid containing HF:
Mud Acids of various strengths or Clay Acid systems. An HCl system
is normally used to remove fines damage in a carbonate formation.
Since the fines are not dissolved, yet are dispersed in the natural
fractures or in the wormholes just created, nitrogen is normally
recommended when the well has low bottom pressure. The nitrogen
will enhance fines removal.
Due to the complexity of the fines problem and its impact on
treatment design this manual contains, in the following two
chapters, detailed information on the removal of fines damage in
sandstones and carbonates respectively.
9.3 Well Acidizing Methods Applied in OMV Petrom
There are two principal matrix acidizing treatment methods used
in OMV Petrom in which applied treatment pressure at the bottom is
lover than formation fracturing pressure are:
1. Sandstone acidizing, and 2. Carbonate Acidizing
Matrix acidizing of sandstones with mud acid is directed at silt
and clay damage removal. A treatment may also be designed to remove
other types of damage, such as: emulsion, wettability change, water
block, organic deposits, and mixed deposits. Samples of the
formation, produced fluids, and possibly even tubing, are important
to ascertain formation damage type and well condition. The
sensitivity of the formation to a treating fluid may result in
deconsolidation due to dissolution of the cementing material.
Precipitates may form from Fe, Na, K dissolved by mud acid. Fines
released during HCl or Mud Acid stages may create damage. Low
permeability wells are very susceptible to this damage
mechanism.
The primary objective of matrix acidizing in carbonates is to
dissolve the matrix, but most of all, to bypass damage, by creating
wormholes and thus to increase the effective wellbore radius and
its average effective permeability. The formation is therefore
actually stimulated (unlike in sandstone reservoirs), and the skin
value is decreased, often to negative values.
Considering the main types of potential damages the general best
practice workflow of well stimulation by acidizing is shown on
Figure 9-4.
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Figure 9-4 Formation damage types and treatment selection
The final fluid selection for treatment
The first step in planning to acidize any type of formation
(sandstone and/or carbonate) is to use key reservoir
characteristics like gross lithology, mineralogy composition and
temperature for fluid selection. The general workflow applied in
OMV Petrom for basic fluid selection is shown in Figure 9-5.
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Figure 9-5 Basic Fluid Selection for Well Acidizing
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9.3.1 Sandstone
Treatment fluid selection in sandstone formations is highly
dependent on the mineralogy of the rock as well as the damage
mechanism. Hydrofluoric (HF) acid is typically used to dissolve the
damaging silicate particles (Figure 9-6). Nonacid systems are
sometimes used to disperse whole mud and allow it to be produced
with the treating fluid. The criteria for selecting the treating
fluid for any treatment stage are mineralogy (solubility of
minerals in acid, clays/silt, iron and zeolites content and other
lithology criteria such as chlorite and glauconite content),
petrophysical properties (permeability) and well conditions
(temperature, formation damage mechanism).
Figure 9-6 Constituents of sandstone which are soluble in HCl/HF
acid systems
HF Reactions in Sandstones
The reaction of HF acid with the damaged matrix occurs in three
steps. Live HF reacts with sand, feldspar and clays, which results
in silicon fluorides and some aluminum fluorides as reaction
products. The HF acid provides the greatest dissolving power during
this phase, while only a small amount of HCl is consumed. The depth
of invasion of the live HF acid is normally 5-15 cm from the
wellbore. The primary stage is the stage that removes skin damage.
The reaction of hydrofluoric acid (HF) on the pure quartz component
of sandstone described by the equations 9-2 and 9-3 results in
silicon tetrafluorid (SiF4) and water:
OH2 + SiFSiO + 4HF 242 (9-2) SiFH 2HF + SiF 624 (9-3)
The stoichiometry of this reaction shows that 4 moles of HF are
needed to consume one mole of SiO2. However, the produced SiO4 may
react with HF to form fluosilicic acid (H2SiF6) resulting in the
silicon hexafluoride anion SiF62-. If the reaction goes to
completion, 6 moles of HF, rather than 4, will be consumed to
dissolve 1 mole of quartz. A complication is that the fluosilicate
may exist in various forms, so that the total amount of HF required
to dissolve a given amount of quartz depends on the solution
concentration.
The most common primary reactions involved in acidizing are
summarized in Table 9-2.
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Table 9-2 Primary chemical reaction in acidizing
HYDROFLORIC ACID - HF Quartz: 4HF + SiO2 SiF4(silicon
tetrafluoride) + 2H2O SiF4 + 2HF H2SiF6 (fluosilicic acid) or SiF4
+ 2F- SiF62- (Silicon hexafluoride anion) Albite (sodium feldspar):
Na AlSi3 + 14HF + 2H+ Na+ + AlF2+ + 3SiF4 + 8H2O Orthoclase
(potassium feldspar): KAlSi3O8 + 14HF + 2H+ K+ + AlF2+ + 3SiF4 +
8H2O Kaolinite: Al4Si4O10(OH)8 + 24HF + 4H+ 4AlF2+4SiF4 + 18H2O
Montmorillonite: Al4Si8O20(OH)4 + 40HF + 4H+ 4AlF2+ + 8SiF4 +
24H2O Calcite: 2HF+ CaCO3CaF2 + CO2 + H2O Note: CaF2 is very low
soluble
FLUOBORIC ACID HBF4 HBF4 + H2O HF +HBF3OH rapid response HBF3OH
+ HF + H2O HBF4 slow reaction
Fluoboric acid-based solution (Clay Acid)
One of the key problems that can occur after acidizing is
migration of fine particles in both, unconsolidated and
consolidated sandstones causing the blockage of the pores, and in
some cases increasing the tendency of forming viscous stabilized
emulsions. Migration of fine particles after reaction with HF is
primarily related to the concentration of HF and its reaction
speed. To avoid undesirable precipitations of secondary products of
reaction, rock deconsolidation and migration of fine particles,
some special acids compositions have developed that can help in
avoiding a problems. The most frequent used is Fluoboric acid
(HBF4)
Fluoboric acid (HBF4) is used to produce HF through the
hydrolysis according to the chemical reaction shown in Table 9-2.
At any time there is only a limited amount of HF acid available and
the probability of forming precipitates of fluosilicates,
fluoalumintes or silica is decreased significantly.. The acid is
consumed by reaction on clay surface minerals followed by
hydrolysis to produce more HF. Because of this, HBF4 is considered
as acid with delayed reaction (retarded acid). If the temperature
is higher than 95 oC, the kinetic of the hydrolysis is rapid. The
reaction of fluoroboric acid with silica is approximately 10 times
lower if temperature is less than 65 oC. A major advantage of HBF4
is its ability to inhibit the migration of fines present in
sandstone by coating the initial surface with borosilicate as a
product of reaction during treatment. Experimental results showed
that when the cores containing pore lining illite have been treated
by HBF4, the poorly crystallized precipitate of KBF4 has been
observed at the outlet of cell and it does not have a damaging
effect. The positive effects of using HBF4 and major advantages of
its application are:
The dissolving potential of clay acid is still high (for
example, 8% of HBF4 is approximately equal to 2%HF).
The borosilicate coating stabilizes fines and makes them less
sensitive.
Because of these HBF4 is recommended always when problems with
migrating fines exist, what is often case in the maturated wells
completed with gravel pack.
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Precipitation of reaction product
When the live HF has been consumed, the secondary reaction
proceeds as the reaction of dissolved silicon fluorides on clay and
feldspar. This reaction releases a large amount of aluminum and
other cations into solution, consumes a large amount of HCl, and
forms silicon precipitates and sodium and potassium fluosilicates,
which can precipitate if the selected HF concentration is too high
relative to the minerals that contain sodium and potassium. The
reaction is complete when the silicon fluorides are no longer
present, which is normally within 1.2 m from the wellbore. The
precipitation of fluosilicates can be very damaging, and is one of
the main causes of HF treatment failures, particularly in
formations containing large amounts of K-feldspar. However, it is
not really a problem if the fluid is kept in motion. If live HF is
shut in during an acid job, severe and permanent damage to the
matrix permeability can result from silica gel precipitation.
Reaction with feldspar, chert, mica and clay components of
sandstones also results in SiF62-anion, but, in addition, produces
a range of aluminum complexes: AlF2+, AlF+2, AlF3, AlF4-, AlF52-
and AlF63s-. The concentration of each aluminum complex depends on
the concentration of free fluoride ions in the dissolving solution.
Some of these products combine with free sodium, potassium, and
calcium ions to produce four compounds with varying degrees of
solubility in the spending acid:
Sodium fluosilicate ( Na2SiF6), Sodium fluoaluminate (Na3AlF6),
Potassium fluosilicate ( K2SiF6), and Calcium fluosilicate (
CaSiF6).
Matrix treatments are always designed to prevent the formation
of these compounds in order to remove any risk of precipitation.
The tertiary reaction proceeds as the reaction of dissolved
aluminum fluorides on clay and feldspar. The tertiary reaction is
slower than the secondary reaction and it is much faster on clays
than on feldspars. However, it is an important reaction that must
be considered, because it causes further reduction in the HCl
content of the spent HF. Once the acid is consumed,
alumino-silicate scaling occurs, within a distance of 1.2 m to 1.8
m from the wellbore. There are many precipitation reactions that
take place during an HF sandstone acidizing job. These reactions
are unavoidable, but their effect on stimulation response can be
minimized with proper fluid selection and treatment design In Table
9-3 damaging HF reactions in sandstones resulting in precipitation
are summarized. Table 9-3 Damaging HF reactions in sandstones
Reaction Precipitate(s)
HF + carbonates (calcite, dolomite) Calcium and magnesium
fluoride (CaF2, MgF2) HF + clays, silicates Amorphous silica
(orthosilicic acid) (H4SiO4) HF + feldspars Sodium and potassium
fluosilicate (Na2SiF6, K2SiF6) HF + clays, feldspars Aluminum
fluorides (AlFn3-n) Aluminum hydroxides HF + illite clay Na2SiF6,
K2SiF6 Spent HF + formation brine, seawater Na2SiF6, K2SiF6 HCl-HF
+ iron oxides and iron minerals Iron compounds HF + calcite
(calcium carbonate) Calcium fluosilicate
9.3.2 Carbonate
There are two basic types of acid treatments applicable to
carbonates in OMV Petrom. They are characterized by injection rates
and pressures. Acid treatments with injection rates below formation
fracturing pressure, called matrix acidizing and acid treatment
with injection rates above fracturing
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pressure (called acid fracturing, see Chapter 11). Matrix
acidizing is applicable only to formation exhibiting formation
damage. In the case of naturally fractured formations acidizing at
matrix rates even in an undamaged carbonate formation may result in
an acceptable stimulation response.
Whereas the purpose of sandstone acidizing is to dissolve the
damage, the primary objective of matrix acidizing in carbonates is
to dissolve the matrix, but most of all, to bypass damage, by
creating new channels and thus to increase the effective wellbore
radius and its average effective permeability. The dissolution of
carbonate rocks by acid results in rapid generation of irregularly
shaped and empty channels called wormholes, as shown in Figure 9-7.
Because of the randomness of porous media, it had been shown that
during dissolution two neighboring pores can coalesce if
sufficiently enlarged. It is difficult to model or predict the
development of wormhole formation in a real rock as the mineralogy
will never be 100% carbonate.
Figure 9-7 Various Wormhole structures
The formation is therefore actually stimulated (unlike in
sandstone reservoirs), and the skin value is decreased, often to
negative values.
Acids used in carbonate acidizing and chemistry of reactions
Commonly used acids to stimulate carbonate formation are:
Hydrochloric (HCl), Acetic (CH3COOH)/ week organic acid, and Formic
(HCOOH)/week organic acid.
Carbonate acidizing solely with HCl, is not complicated by a
tendency for precipitates to form, as is the case for sandstone
acidizing. The reaction products CaCl2, MgCl2 (dolomites) and CO2
are readily soluble in water. Therefore, the formation of a
precipitate or a separate CO2-rich phase is generally not a
problem. Under comparable conditions weak organic acids react more
slowly than hydrochloric acid and they can be used instead of HCl
when high bottomhole temperatures (above 200oC) prevent efficient
protection against corrosion. Acetic acid is easier to inhibit than
formic acid and is used more often. Table 9-4 illustrates the
maximum protection times with corrosion inhibitors at various
temperatures and acid concentrations. Table 9-4 Maximum protection
time for different acids and temperatures
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The following factors affect the spending rate of acid in
carbonate formations: temperature, pressure, acid type, acid
concentration, acid velocity, reaction product and formation
composition (structure and mineralogy). Acetic and formic acids
react with CaCO3 to form calcium acetate and formate. The formic
acid concentration must be limited to about 10% as calcium formate
precipitates above that level. Acetic acid can be used at higher
concentrations, as calcium acetate remains soluble, but best
practice is to use not more than 10% acetic acid. None of the
organic acids react appreciably with SiO2. They react with iron
compounds or minerals containing iron. Acetic acid forms a complex
with iron in solution and helps prevent iron precipitation up to
60oC. In reservoirs with high iron content, it is necessary to cut
back on HCl concentration or substitute part or all the HCl with
acetic acid. Chelating agents, such EDTA (ethylendiaminetetraacetic
acid), are even weaker acids than acetic and formic acids. For
example, 9% disodium EDTA solution has the approximate dissolving
power of 2.2% HCl. It is not common to use chelating acid in matrix
acidizing because of their cost relative to the common acids (HCl,
acetic and formic acid) and lower dissolving power. The summarized
chemical reactions of HCl and organic acids with carbonate are
shown in Table 9-5. Table 9-5 The reaction of HCl with
carbonates
HYDROCHLORI AClD Calcium carbonate : 2HCl + CaCO3CaCl2 + CO2 +
H2O Dolomite: 4HCl + CaMg(CO3)2 CaCl2 + MgCl2 + 2CO2+ 2H2O
Siderite: 2HCl+ FeCO3 FeCl2 + CO2 + H2O
Organic Acids Calcium carbonate and Acetic Acid : 2CH3COOH +
CaCO3Ca(CH3CO2)2 + CO2+ H2O Dolomite and Acetic Acid: 4CH3COOH +
CaMg(CO3)2Ca(CH3CO2)2 + Mg(CH3CO2)2 +2 CO2+ H2O Calcium carbonate
and Formic Acid : 2HCOOH + CaCO3Ca(HCO2)2 + CO2+ H2O Dolomite and
Formic Acid: 4HCOOH + CaMg(CO3)2Ca(HCO2)2 + Mg(CH3CO2)2 + 2CO2+
H2O
However, despite the simplified chemistry, HCl acidizing of
carbonates is a difficult process to model. The reason for this is
the high rate at which the reactions take place as compared with
that of HF with the various minerals prevalent in sandstones.
Wormhole growth depends on the acid injection rate, the diffusion
rate and the formations surface reaction rate. Wormholes will only
form if the diffusion rate determines the overall spending rate,
which happens if the acid/rock reaction rate is high. The diffusion
rate determines the rate at which acid travels from the bulk of the
fluid to the rock surface as shown on Figure 9-8. The treatment
objective is to form the longest and deepest penetrating wormholes
as possible. Wormholing efficiency under expected downhole and
surface treating conditions is a major criterion in fluid
selection. Images shown in Figure 9-9 are neutron radiographs of
cores acidized under different conditions. Experiments have shown
that the quantity of rock dissolved, i.e., the acid penetration
depends on acid velocity. One advantage of wormhole formation is
that the near-wellbore damage can be bypassed and the effective
treated zone becomes much larger than in sandstone acidizing (for
the same amount of rock dissolved) or in matrix acidizing of
carbonates using slow reacting acids when
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the kinetics is limited by surface reactions. In addition,
problems of deconsolidation in the near-wellbore area are less
severe.
Figure 9-8 Wormholing controlled by diffusion
Major wormhole structure possibilities can be categorized, as a
function of injection rate and acid/rock reactivity, as
follows:
Face dissolution (no Wormholing), Conical (single channel with
limiting branching), Dominant wormholes (primary channels with some
branching), Ramified wormholes (extensive branching), and Uniform
dissolution.
Figure 9-9 Various Wormhole structures (Fredd and Fogler, SPEJ,
1998, 1999; Hoefner and Fogler, AlChEJ, 1998)
9.4 Technology Workflow of Best Practices for Fluid Selection,
Treatment Design and Job Execution
9.4.1 Sandstone Matrix Acidizing Treatment
Fluid Selection for Acidizing Treatment
Fluid selection for each stage of the treatment must take
account of all of the parameters previously discussed: dissolution
of damage, compatibility with rock minerals and reservoir fluids
and potential damaging reaction products. Since silts and clays are
the component minerals that react with HF acid to cause potentially
damaging precipitates, the higher the silt and clay content, the
greater the risk of precipitation. Increasing the HCl:HF ratio is
one way to retard precipitation. HCl increases the dissolving power
of the HF and low-HF content reduces the precipitation of silica.
Therefore, as the silt and clay content of the formation increases,
the recommended HCl: HF ratio also increases. The
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presence of HCl sensitive clays will also affect the type of
acid chosen. X-ray diffraction (XRD) analysis is the most common
test used to determine formation mineralogy. In OMV Petrom two
different models for acidizing fluid selection are in use:
Model 1: Use mineralogy composition and rock/reservoir
permeability. Model 2- Use mineralogy composition and
temperature.
Formation solubility in both HCl and HCl: HF can be used to
approximate the total silt and clay content. The difference in
these solubilities correlates well to silt and clay content by XRD
analysis as seen in Table 9-6. Solubility information, however,
does not indicate the type of clay present. Table 9-6 Solubility of
Common Minerals in Acid
*Insoluble (IS), High (H), Moderate (M), Low (L), Very Low
(VL),
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Model 1-Sandstone Acidizing Workflow
Model 1- Preflush/Overflush stage Fluid Selection
Using mineralogy composition and reservoir permeability workflow
for selecting the best fluid for pre-flush treatment is shown in
Figure 9-10 and summarized Table 9-7 if the content of carbonate is
less than 20%, HCl is used as a preflush to an HF acid. Normally
the greater the permeability, the lower the chance of creating
fines migration damage during the HCl preflush.
Since clay and silt type materials may react with HCl to produce
mobile fines, the HCl concentration decreases with increased fines
content. The clay content is the dominating species due to its
large surface area and cation exchange capacity (CEC).
Figure 9-10 Model 1 Preflush/Overflush Fluid Selection
Table 9-7Model 1 Preflush Fluid Selection
Mineral Composition > 100 mD 20-100 mD < 20 mD10% Silt and
>10 % Clay>10% Silt and < 10 % Clay>10% Silt and >
10 % Clay
10% HCl 7.5% HCl 5% HCl
At the presence of HCl sensitive minerals, like chlorite,
glauconite and zeolites it is advisable to keep the pH low to so
all reaction products dissolved and the selected fluid for preflush
should be corrected according to the following practices shown in
Table 9-8.
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Table 9-8 Model 1 Preflush /Overflush fluid selection including
presence of HCl sensitive minerals
Zeolites Chlorite+Galuconite Silt and Clay
>2 Any Any Any 10% Acetic
>=2 >6 Any Any 10% Acetic
10% Silt and >10 % Clay Any 5%HCl+5%Acetic
100 10%HCl+5%Acetic
0-2 10 % Clay 20-100 7.5%HCl+5%Acetic
0-2
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Figure 9-11 Model 1 Main/Base Treatment Fluid Selection
Table 9-9 Model 1 Main/Base Treatment Fluid Selection
Mineral Composition > 100 mD 20-100 mD < 20 mD10% Silt and
>10 % Clay 13.5% HCl +1.5%H9% HCl +1%HF 4.5% HCl +1%HF>10%
Silt and < 10 % Clay>10% Silt and > 10 % Clay
12% HCl +2%HF 9% HCl +1.5%HF 6% HCl +1%HF
If 4-6% chlorite/glauconite then use 8%, then use 10% acetic
acid and organic mud acid If 5% Zeolite then use 10% Acetic Acid
preflush and overflush to 10% citric acid / HF. Formations with
more than 2% zeolites are considered sensitive and use the above
flowchart for acid selection. For moderate zeoloite compositions,
acetic acid is used as the acid preflush and overflush and is added
to the conventional mud acid formulations with the HCl. The organic
acid is to keep the pH low, acting like a buffer in these acid
solutions. Reaction products are more soluble in low pH. For higher
zeolite compositions, acetic is also used for the preflush and
overflush, but organic mud acids made with citric acid are
recommended. The workflow (Figure 9-12, Figure 9-13 and Figure
9-14) and Table 9-10 lists the recommendations based on these
parameters.
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Figure 9-12 Main Treatment Fluid Selection including presence of
high sensitivity Clays and Zeolites
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Figure 9-13 Main Treatment Fluid Selection including presence of
high sensitivity Clays, Chlorite and Glauconite
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Figure 9-14 Model 1 Main/Base Treatment Fluid Selection
including presence of high sensitivity Clays, Zeolites and
Glauconite
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Table 9-10 Model 1 Main/Base Treatment Fluid Selection including
presence of high sensitivity Clays, Zeolites and Glauconite
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Model 2-Sandstone Acidizing Workflow
Model 2- Preflush/Overflush stage Fluid Selection
The formation temperature is an important factor because it
influences the efficiency of corrosion inhibitors and the reaction
rates. Several treating fluids decrease reaction rates at high
temperatures and provide deeper live-acid penetration. The
workflows shown in Figure 9-15 and Figure 9-16 as well as in Table
9-10 and Table 9-11 can be used as guidance for fluid selection for
Preflush/Overflush and Main treatment.
Figure 9-15 Model 2 Preflush/Overflush Fluid Selection including
presence of high sensitivity Clays, Zeolites and Glauconite
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Table 9-11 Preflush /Overflush fluid selection including
presence of HCl sensitive minerals and temperature
Model 2 Main Treatment Fluid Selection
Figure 9-16 Model 2 Main Treatment Fluid Selection including
presence of high sensitivity Clays and reservoir temperature
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Table 9-12 Main Treatment Fluid Selection including presence of
HCl sensitive minerals and temperature
9.4.2 Applied Sandstone Design Procedure
A sandstone acidizing design procedure in OMV Petrom consists of
the following distinct stages:
1. Tubing pickling stage/wellbore cleanup
Wellbore cleanup is commonly used to remove scale, paraffin,
bacteria or other materials from the tubing, casing or gravel-pack
screen. The injection string (production tubing, drill pipe or
coiled tubing) should be cleaned (pickled) prior to pumping the
acid treatment. The pickling process may be multiple stages,
consisting of solvent and acid stages. An acid pickling job of
tubing/casing can be done by simply spotting around 2.4 bbl/1000
feet (1.2 lit/m) of 3-20% HCl down the tubing and up the annulus. A
typical pickling solution is a 7.5% HCl solution containing an iron
control agent and corrosion inhibitor. Often the same acid mixed
for use in the HCL preflush may be used as the pickling
solution.
2. Preflush
Non-Acid
A water displacement stage, consisting of 3-5% NH4Cl solution,
depends on concentration of smectite, illite, kaolinite, chlorite
and feldspar, according to:
Concentration%=3+(%smectite*0.3+%illite*0.12+%kaolinite*0.08+
%chlorite*0.12+%feldspar*0.05)
This is considered to displace formation water containing
bicarbonate and sulfate ions. Typical volumes are 500 to 1000 l/m
(40 to 80 gal/ft)
Acid preflush
The main purpose of the standard preflush with 5%-15% HCl is to
dissolve carbonate constituents of the reservoir. This is to
prevent the possibility of forming CaF2 as a mud acid precipitation
product.
Numerous acidizing jobs in OMV Petrom have proved that the best
practices is to execute pre-flush with at least 50% of the volume
of acid fluid for base/main treatment.
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Typical volumes are 620 to 1240 l/m (50 to 100 gal/ft) and it is
preferable that the preflush penetrates the same distance as the
HCl/HF mixture.
Organic acids, such as acetic and formic, should be used in
conjunction with, or instead of, HCl in sensitive formations the.
Although they will dissolve the carbonate, they work more slowly
and are especially applicable for high temperature conditions. When
pumping organic acids as stand-alone fluids, they should be mixed
in ammonium chloride rather than fresh water. Organic acids also
act as a low-pH buffer and chelating agent that helps minimize the
tendency of iron compounds to precipitate as the acid spends.
However, they do not dissolve iron scale or prevent clay
swelling.
If iron and carbonate contents are high, both an acetic acid and
HCl preflush can be used. If carbonate content is not high (less
than 5%), then the organic acid can be applied only, without using
HCl preflush. The best practice in OMV Petrom is to use 10% acetic
acid contain 5% NH4Cl. Ammonium chloride is added for clay
stability as use of acid without the addition of NH4Cl could cause
clays swelling.
3. Main Treatment
The main acid phase is commonly a mixture of HCl/HF. Volumes may
range from 120-3000 l/m (10-250 gal/ft) and more common volumes
used in OMV Petrom are in the range 120 to 240 l/m (10 to 20
gal/ft). Volume is somewhat arbitrary, but should have a logical
dependence on formation permeability, acid sensitivity, type and
severity of damage and length of the treated interval. Risks
associated with acidizing-such as fines migration, precipitation of
reaction products, and rock deconsolidation-normally can be
controlled (if not minimized or eliminated) by use of proper
volumes and concentrations of acids.
Mud Acid should not be used in formations with > 20% HCl
solubility. Pore lining clays will be dissolved by mud acid. Thus,
an abundance of chlorite in the pore throats may result in iron
control problems. High permeability formations may experience deep
invasion of particulates (drilling mud, barite, etc.).Low
permeability formations will not experience severe particle
invasion but will be more sensitive to damage by precipitates.
Sludge or emulsion tendency of crude will dictate the use of a
specific acid system. Treatments in gas wells include mutual
solvents or alcohols. High temperature decreases live acid
penetration and increases corrosion rates. Wells with low bottom
hole static pressure (BHSP) should be treated with energized/foamed
fluids.
The well shut-in time after treatment should be minimized to
reduce precipitation of reaction product. It is mandatory to avoid
using NaCl, KCl, or CaCl2 brines in any HF treatment stages or in
any stage immediately proceeding or following HF stages.
4. Overflush/Aterflush
Overflush (or afterflush) is an important part of a successful
acidizing treatment. The purposes of the overflush are:
Displace nonreacted mud acid into the formation, Displace mud
acid reaction products away from the wellbore, Remove oil-wet
relative permeability problems caused by some corrosion inhibitors,
Redissolve HF precipitates, if an acidic afterflush is used.
Typical overflushes for mud acid treatments are: Water
containing 3 to 8% ammonium chloride, Weak acid (3 to 10% HCl) in
the cases when HCl is used as preflush fluid. Acetic acid in the
same concentration as HCl if formation mineralogy and temperature
do not
allow application of HCL. Alternatively, 3-8% of NH4Cl solution
can be used. Nitrogen (gas wells only and only following a water or
weak acid overflush).
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Usually, the Overflush/Afterflush treatment can be performed
with the same fluid concentration as used in the preflush. The
typical volumes of 360 to 1200 l/m (25-100 gal/ft) are also very
similar to those used in the preflush. The same fluid and
concentration can be used in most cases. In gas wells, and
sometimes in extremely water-sensitive formations, nitrogen is an
effective overflush. The afterflush should occur immediately after
the main acid injection in order have the most beneficial effect
and to minimize precipitation of Si (OH)4. Wells should be put on
production immediately after the treatment. In such case, the
afterflush volume should be at least the same as the main HCl/HF
volume. In cases when wells have to stay closed in for some time
(which is to be avoided), the afterflush volume should be at least
twice the HCl/HF volume in order to displace the reaction products
to a distance where their influence is negligible (1 to 1.5m radial
penetration). Certain chemicals (additives, inhibitors, iron
complexing agents) may be used in addition to the basic solution of
acid or NH4Cl in order to reduce problems with emulsion and sludge
formation or prevent corrosion and scale precipitation. A large
overflush is necessary to prevent the near-wellbore precipitation
of amorphous silica. At formation temperatures of 95 C or higher,
amorphous silica precipitation occurs when the mud acid is pumped
into the formation. The precipitate is somewhat mobile at first,
but may set as a gel after the flow stops. It may be diluted and
dispersed far enough from the wellbore to reduce its harmful
influence if it is kept moving by the overflush.
Diversion techniques
One of the main reasons that acid treatments fail is that the
injected acid is not correctly placed and does not have full
contact with the damage. Selection of the proper fluid placement
method is a key success factor in acid treatment design in both
sandstones and carbonates and acid diversion is a challenge that
has to be faced in either lithology.
As acid is pumped, it flows preferentially along the most
permeable path into the formation. The treated zone is commonly not
adequately converged by the injected acid due to significant zone
heterogeneities caused by big variations in zone properties. The
acid opens high permeable zones even more, and less permeable,
damaged zones are almost guaranteed not to receive adequate
treatment. Some technique to divert the treatment fluid toward more
damaged formation or damaged perforations is therefore mandatory.
To approach full damage removal, acid must be diverted to the
sections that accept acid the least that is, those are most
damaged
There is a variety of diversion techniques, but there are three
basic methods of acid placement (diversion techniques) as shown in
workflows (Figure 9-17 and Figure 9-18 ):
Mechanical placement o Packer isolation system , o Ball sealers
(Not used in OMV Petrom) o Coiled tubing
Chemical diversion o Bridging and plugging agents (inert
materials in the of large sized particles from 10-
100 mesh, such as silica sand, water soluble agents like rock
salt and benzoic acid, oil-soluble agents such as resins etc.)
o Particulate diverters (small particle size, commonly below 0.1
mm and those can be water-fine grade of benzoic acid and oil
soluble- blends of hydrocarbon resins)
Foam Diversion (The most useful in gas well acidizing, in gravel
pack completions and generally more effective in
higher-permeability formations with deeper damage)
Gels (more reliable than foam, but could be damaging, because
higher concentration, gels will stay unbroken and therefore will
not be completely cleaned up causing. This will damage the
perforations. Commonly used is Hydroxyethylcellulose-HEC).
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Figure 9-17 General Workflow for choosing a diversion method for
matrix acidizing
Treatment fluid can be directed exclusively toward a
low-permeability zone using injection string (tubing, drillpipe or
coiled tubing equipped with mechanical packers). Flow can be
blocked at individual perforations taking most of the treatment
fluid by injecting ball sealers that seat on the perforations. In
sandstone, microscopic agents such as oil-soluble resins can create
a filter cake on the sand face. Chemical diverters such as viscous
gels and foams created with nitrogen are used to block high
permeability pathways within the matrix. The requirements on any
diverting agent are stringent. The agent must have limited
solubility in the carrying fluid, so it reaches the bottom of the
hole intact, it must not react adversely with formation fluids, it
must divert acid. Also, the used diverter agent must be able to
cleaned up rapidly and thereby avoid harming production. Ball
sealers drop into the rathole as soon as injection halts or, if
they are of the buoyant variety, they are caught in ball catchers
at the source. Benzoic acid flakes dissolve in hydrocarbons.
Oil-soluble resins are expelled or dissolved during the ensuing
hydrocarbon production. Gels and foams break down with time.
In practice, acid and diverting agents are pumped in alternating
stages: first acid, then diverter, then acid, then diverter, and so
on. The number of stages depends on the length of the zone being
treated. Typically, one acid diverter stage combination is planned
for every 5-8 m of formation.
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The current diverter technologies work sporadically and many
times do more harm than good. Recent work shown that even when a
diversion technique such as ball sealers is applied properly, over
one third of the perforation become permanently blocked because the
balls become lodged in the perforation. Chemical diverters often
misused or do not meet expectations rock salt is sometimes used by
mistake with HF acid producing plugging precipitates, and so-called
oil-soluble resins are infrequently only partially soluble in oil.
It is necessary to choose properly the non-damaging diversion
techniques whose effectiveness can be proved and documented. Foam
and the use of inflatable packers on coiled tubing are viable
techniques for positive diversion.
Figure 9-18 Diversion selection workflow
Injection pressure and rate strategy- Design model
Additional reservoir parameters (fracture gradient, porosity,
height, etc.) are required to calculate/estimate injection pressure
and rate constraints for the acid.
The acid use for the main treatment stage should be injected at
a pressure that will not cause fracturing of the formation. In
cases of very severe damage, the pressure may need to be increased
above the fracturing pressure for a short period of time, but
should be returned below fracturing pressure as quickly as
possible. Application of this injection strategy during any
treatment stage will allow removing damage more successfully.
Maximum allowable injection pressure at the surface to avoid
formation breakdown is defined by Eq. 9-4.
FS - P + P - ) HFG ( = P frhmpinj k)j,(i,max (9-4)
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And maximum required hydraulic power of pump (Eq. 9-5) unit for
performing acid treatment job is:
(kW) P Q=P inji maxmax67.1 (9-5)
Where: FG- Formation fracture gradient (bar/m) Hmp- Mid
perforation depth (m) Ph Hydrostatic pressure of fluid treatment
column (bar) Pfr Pressure drop due to friction (bar) FS-
Engineering design safety factor, usually can be taken in the range
20-30 bar Pi - Injection pressure (bar) P Pumping unit required
power (kW)
The mMaximum injection rate that could be achieved, according to
the Paccaloni model is defined by Eq.9-6.
=3.72105
(9-6) Where:
Qimax maximum injection rate of acid (m3/min) K reservoir
permeability (mD) Hmp average well depth (m) injfl viscosity of
injection fluid (mPas) rb radius of injected fluid bank* (m) rw
well radius (m) Radius of injected fluid bank can be roughly
calculated from the amount of stimulating fluid injected and the
available pore space, using the following equation (Eq.9-7): = (1 ,
) 2 2 (9-7) Where: porosity (frac) So,g r- residual saturation of
oil or gas (frac) Sowc connate water saturation (frac) Normally,
the volume of treatment fluid pumped during matrix acidizing is not
large and it is sufficient if the fluid penetrates the formation
about 1-1.4 m, for which can assumed that rb changes only slightly.
From numerous acidizing jobs it was found that for practical and
quick estimation, an arbitrary rb =1.2 m (assuming that acid
penetration will be under steady-state flowing conditions)
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Acid treatment volume and rate guidelines
Table 9-13 Acid treatment guideline
Table 9-14 Recommended volume of treatment fluid
Additives
Additives are added to the different stages of a treatment to
prevent excessive corrosion, sludging and/or emulsions, provide a
uniform fluid distribution, improve clean-up and prevent
precipitation of reaction products. Additives are used not only for
the main treatment but also, in pre-flushes and over-flushes to
stabilize clays, disperse paraffin or asphaltenes and inhibit scale
or organic deposition. Additive selection is primarily dependent on
the treating fluid, the type of well, type of damages, bottomhole
conditions, the type of tubular and the placement technique. Since
there is a large number of an additive available, which vary
between contractors, the choice of additives can be rather
difficult. Additives are always required, but it is important that
only necessary additives be used. Of all these additives, a
corrosion inhibitor is the only one that should always be applied.
Also, a sequestering agent, for the prevention of iron hydroxide
precipitation is often required. Although proper fluid selection is
critical to the success of a matrix treatment, the treatment may be
a failure if the proper additives are not used.
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The most frequent additives used in OMV Petrom are: Corrosion
Inhibitors, Surfactants (Emulsifiers, Deemulsifiers,
Nonemulsifiers), Clay Control/Stabilizers, Fines-Fixing Agent
(FFA), Mutual Solvents, Iron Control Agents, Alcohols, Anti-sludge
Agents, Friction Reducers, Non-Emulsifiers, and Foaming Agents.
9.4.3 Carbonate Acidizing Best Practices
Fluid Selection for Carbonate Acidizing
As the physics of carbonate matrix acidizing is complex and
considering the complex nature of wormhole formation, a proper
selection of the acidizing system and concentration is very
important in the first step in designing carbonate acidizing. There
is an optimum combination of acid (or reactive fluid) injection
rate and degree of reactivity (or retardation) for each formation.
The key criteria for proper acid system selection for carbonate
acidizing are temperature, mineralogy and petrophysics/reservoir
properties. The goal of proper acid system selection is to optimize
of acid penetration and the structure of the newly created
channels.
Temperature strongly influences inhibition of the acid. At high
temperature (150 oC), organic acid are preferred because they are
less corrosive than HCl.
Mineralogy refers to whether the carbonate formation is pure
limestone or partially (or totally) dolomite. Greater than 20 % HCl
must be avoided in dolomites due to the potential precipitation of
by-product. In case where silicates (quartz, feldspars or clays)
content in the dolomite is high (up to 50%, as shown in Figure 9-19
then the HCl should be inhibited with HF.
Figure 9-19 Impure dolomite: Quartz grains (white crystals)
scattered in the dolomitic matrix (brown crystals of dolomite)
When the insoluble minerals are class or fines, dissolution of
the rock matrix will result in the release of insoluble fines and a
special blend of 7.5% - 15% inhibited acid special clay dispersing,
suspending and chelating agents should be applied. In dolomite
carbonate formations containing anhydrate
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(anhydrous calcium sulfate), anhydrite will first dissolve in
HCl but gypsum (hydrated calcium sulfate) will quickly
reprecipitate because of its low solubility. In such formations,
the best practice is to use an acid system with good chelating
properties in order to minimize problems (inhibited blend of HCl
with good chelating properties or non-acid system with chelating
and clay suspending agents). Diversion is required to improve fluid
placement. Apart from small treatments to remove near-wellbore
damage, for which neat HCl acid (with necessary additives) can be
used, (lightly) gelled acid is used in most carbonate matrix
treatments. This is done to improve zonal coverage of the acid, to
retard the acid reaction rate, or to improve its fines-suspending
properties. Some relevant aspects of the various acid systems are
discussed below.
Petrophysics/Reservoir Properties such as distribution, type of
porosity and reservoir permeability have a strong influence on the
extent of the damage and on penetration of acid. Reservoirs with
high permeability (K>50 mD) can be severely damaged by the
invasion of solid particles and inhibited HCl with HF intensifier
or emulsified HCl acid (70% of HCl and 30% of oil/diesel) can be
used to remove damage. In naturally fractured carbonate formations,
damage by solid particles occurs in the fracture. A proper acid
treatment fluid enlarges the fractures and allows clean-up of the
fracture network. An inhibited blend of HCl with good chelating
properties could be an appropriate solution for this application
due to its good suspending properties.
Lightly gelled acids various strengths of HCl with low
concentrations of gellant (< 0.5%) for friction reduction.
Gelling provides a viscosity of 1-3 cp at ambient temperatures.
These systems are applicable for high-rate matrix treatments.
Gelled acid systems various strengths of HCl with higher
concentrations of acid gelling agents (2-3%) to provide higher
viscosity. These might range from 30 to 40 cp at ambient
temperatures, resulting in an enhanced zonal coverage and reduced
fluid loss. Systems that contain HCl, a gelling agent and a
pH-sensitive crosslinker are called in-situ crosslinked acid. These
are marketed as Zonal Coverage Acid (ZCA) by Halliburton and
Self-Gelling Acid Diverter (SGAD), by Schlumberger. After
crosslinking at a pH of 2-3, the gel will break upon further
spending of the acid at pH values above 4. The systems can be built
to work in HCl acid at strengths from 5-28% acid. The self-gelling
acid system is particularly suited for treatments in horizontal
wells.
Emulsified acid systems oil outside phase acid systems have been
successfully used in situations where a retarded reaction rate is
needed to create deeper acid penetration and wormholes. Because of
their retarded nature, they can be pumped at low rates, which is
beneficial in heterogeneous formations. Also their high viscosities
result in better zonal coverage.
Energized and foamed acid systems in reservoirs where the
reservoir energy is low, some form of additional energy may assist
in the unloading of the fluids introduced into the formation.
The physics of matrix carbonate acidizing is more complicated
than in sandstone because of the wormholing phenomena. Development
of a simplified workflow that could cover all possible variations
is difficult and the proposed workflow is intended as an initial
guide. Best practice is that fluid selection for carbonate
acidizing is be made for each individual treatment. In general, the
fluid that gives the deepest penetration for the expected pumping
and reservoir conditions is the fluid that should be used.
Selection of a base acid in an integrated approach requires
consideration of some of the key parameters (permeability, type of
carbonate ,Fe content, bottomhole temperature in relation to
corrosion and reactivity of the formation) influencing on physics
and chemistry of carbonate matrix acidizing, as shown on Figure
9-20.
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Carbonate Acidizing Fluid Selection Workflow
Figure 9-20 Fluid selection workflow for carbonate acidizing
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Design procedure for Carbonate Acidizing
For a carbonate matrix stimulation treatment to be successful,
it is important to acidize under conditions that will lead to the
formation of deep penetrating wormholes that bypass formation
damage, whilst using minimal acid volumes at optimal injection
rates. Results from studies on efficient wormhole formation
indicate that the injection rate should be increased, or the
overall dissolution rate decreased (by changing the fluid type) as
the depth of penetration increases. If such detailed planning is
not feasible, then it is recommended to pump acid at the highest
possible rate and pressure, whilst staying below fracturing
conditions. Table 9-15 shows a schematic of dissolution as a
function of surface reaction and diffusion rate as well as of acid
injection rate.
Table 9-15 Wormhole structure
Common sequences for performing carbonate matrix acidizing
are:
1. Pickling of the injection string, 2. Preflush, 3. Main
Treatment, and 4. Overflush.
Pickling
The injection string usually should be picked prior to pumping
of acid. The best practice for pickling injection string in OMV
Petrom is to use acid of 5-15% HCl containing an iron control agent
and a corrosion inhibitor. If there are some organic deposits in
the injection string then pickling of injection string can be done
with acid and an aromatic solvent and surfactant.
Preflush
If there are organic deposits (such as paraffins and asphaltenes
with high molecular weight) in the wellbore tubular and
near-wellbore zone then a carbonate preflush with an solvents
(xylene or another) should be applied to remove organic deposits.
In a limited number of cases in OMV Petrom, the preflush also
served to displace oil from the near-wellbore and to prevent the
formation of emulsion or sludge. Mutual solvents such as EGMBE
(ethyleneglycol monobutylether) or others that are in liquid state
and are water-and oil-miscible should be used. The common practice
in the gas wells is to use various surfactants (anionic, cationic,
nonionic, amphoteric) up to a maximum concentration of 1.5% in
order to reduce the surface tension between acid solution and
gas.
Main Treatment
The main treatment stage is commonly performed with 15% - 28%
HCl. Selection of the treatment volumes depends upon the
anticipated depth of damage and reservoir porosity. The recommended
volume of treatment fluid varies within a broad range (1203700
lit/m) whereas most treatments
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involve volumes is in the range of 310-1850 lit/m. The radius of
acid penetration can be estimated using formation porosity and the
injected volume of acid. The penetration of acid in carbonate
formations is not uniform due to the heterogeneous nature of the
depth of acid penetration and the required fluid volume has to be
estimated by matching numerical model and laboratory test
results.
Overflush
The purpose of the overflush is to displace the acid. Fresh
water (additivated with NH4Cl) is the most common overflush fluid.
Filtered crude oil and diesel may also be used in oil wells but are
not preferable because of possible incompatibilities with acid.
Nitrogen gas is an effective overflush, especially in gas
wells.
Diversion Techniques for carbonate acidizing
Successful matrix treatments require uniform vertical
distribution of the treating fluid. Improper placement exacerbates
heterogeneity, as shown in Figure 9-21. Good placement is
particularly difficult in carbonates because acid can bypass damage
relatively easily. This damage bypass can result in negative skins,
thus any pathway that preferentially attracts acid to begin with
(such as natural fractures, high permeability thief zones, or
depleted zones) will become an even stronger sink for acid as that
zone becomes highly stimulated. Moreover, in wells with long
openhole intervals, spending of acid along the wellbore will
partially spend the acid that reaches the extremes of the openhole
section, thus, jeopardizing the objective of achieving good zone
coverage with acid.
Figure 9-21 Improper acid placement in carbonate formation
In carbonate reservoirs, in principle, two main diversion
techniques (mechanical and chemical) can be used to improve fluid
placement.
Mechanical Packers, Ballsealers (Not used in OMV Petrom), Coiled
tubing.
Chemical Chemical diverters (insoluble in acid but soluble in
oil, in powder state-benzoic acid,
rock salt, polymer systems, ). Foam diversion (foam agent with
acid foamed with nitrogen). Self-diverting acid (chemicals which
transform into gel in the consumed acid solution,
thus preventing the channeling of acid in layers with maximum
permeability). In situ-crosslinked acid (Not used in OMV
Petrom)
The technique is often ap