kind of clay sensitivity (Swelling, migrating, water entrapment).
2. Are iron bearing minerals present and in what volume.
3. Are feldspars present and in what volume.
4. What is the solubility in HCl Acid.
5. Is the formation consolidated or unconsolidated. What is the matrix
binding or cementing material. Is the formation susceptible to sand
production.
6. Is the formation geology homogeneous vertically and horizontally.
What is the horizontal and vertical permeability (Anisotropy)
7. What is the porosity.
8. What is the water saturation.
9. Is there a distinct oil/water contact. Is there a distinct oil/gas contact.
10. What is the crude oil API gravity. What is the crude oil viscosity at
down hole conditions.
11. What are the paraffin and asphaltene contents of the crude oil.
12. Does the crude have natural emulsifying tendencies.
13. What is the formation brine pH.
14. Does the formation water have a scaling tendency.
15. What is the bottom hole static temperature (BHST).
16. What is the reservoir pressure (BHP)
17. What is the bottom hole frac pressure (BHFP).
9.1 Mineralogy Design Factors.
1. If solubility in hydrochloric acid is greater than 18%, use HCl only.
Do not use hydrofluoric acid (HCl:HF). (See Table 14, page 67)
2. If solubility in hydrochloric acid is greater than 10%, then the standard
HCl volume of half the HCl:HF volume is usually adequate.
3. If the total clay content of the formation is less than 5.0%, then use
7.5% HCl : 1.5% HF.
4. If the total clay content of the formation is greater than 5.0%, then use
12% HCl : 3.0%. HF.
5. If iron bearing minerals are present (chomasite, siderite, haematite or
pyrites), use iron control additives at volumes determined from core
tests or spent acid returns. (Total iron in parts per million divided by
five will give an estimate of the ferric iron content).
6. Presence of iron bearing minerals will cause asphaltene precipitation.
The use of anti-sludge additives or solvent preflushes depending upon
the severity of the sludging potential.
7. If chlorite clays are present, increase the iron control additive
concentrations in the HCl preflush
.
8. If illite clays are present and the permeability is less than 120 md,
reduce the surface tension to at least 30 dynes per centimetre.
9. If the feldspar content is less than 20 %, use 12% HCl : 3% HF.
10. If the feldspar content is greater than 20 %, use 7.5 % HCl : 1.5 % HF.
11. If the formation is susceptible to de-consolidation, use low strength HCl
and HCl : HF concentrations.
Clays and silts may remain to plug the permeability after sandstones and "dirty"
limestones or dolomites have been acidized. Suspending Acids (e.g. MMR acid)
have therefore been developed which "suspend" these undissolved particles,
thereby helping to remove them from the formation. Fines stabilising agents (FSA-1)
have also been developed to “lock” the fines, in particular clays, in the formation
matrix.
The special suspending agents (MMR agents) can be added to many of the different
acid treating systems that are designed for the removal of specific damage
mechanisms for example:
- · MMR Acid for fines suspension.
- · Sequestering acid for iron.
- · One Shot Acid for hydrocarbon deposit removal.
Both hydrochloric acid (e.g. Clean-up Acid) and hydrofluoric acid systems (e.g. Mud-
Sol) have been developed for the suspension and removal of formation fines and
invasion particles from mud etc.
9.1.1 Mineralogical Analytic Procedures.
Core Tests.
- · Immersion Test : Oil/Water sensitivity.
- · Clay Swelling Test.
- · X-ray Diffraction : Bulk mineralogy and 2.0 micron clay analysis.
- · Scanning Electron Microscope : Microtecture and mineralogy.
- · Polarising Microscopy : Mineralogy of coarse-grained materials, and best method for study of grain-pore cement relationships.
Utilisation of 2 micron and bulk X-ray diffraction enables a catalogue to made of
index rock properties. This data can be cross-matched with geographic data to
formation make-up as well as treatment options.
9.3 Permeability Design Factors.
1. Acid Volumes see Table 12.
2. If the permeability is less than 120 md reduce surface tension of acid
and flushes to 30 dynes/cm2 or less to prevent water blocks.
3. If present, multiple permeabilities should be considered when
designing diverter/acid stages for proper diversion and volume control.
1) Volumes should be selected based on core tests.
2) Volumes can exceed 100 gallons per foot if necessary without releasing excessive fines.
3) Volumes can be modified if indicated by field test results
4) Use acid for perforation cleaning only.
Laboratory and pilot test data are converted for field use by expressing the
recommended treating volume as gallons per square foot (see Figure 6, page 23). In
the laboratory a known volume of treating fluid is flowed across a given crosssectional
area of a core sample. The are to be treated in field applications is
determined by the radial area of the edge of the treating radius. Once the radial area
is determined, it is multiplied by the recommended treating volume (in gallons per
square foot) and by the height of pay zone interval to be treated. In order to simplify
these area calculations Figure 13 can be used.
Example :
Treating Radius = 5.0 feet
Recommended Treating Volume = 20 gallons per sq.ft.
Treated interval = 10 feet
From Figure 13 Gallons per foot of treated interval = 630 gallons
Volume of HCl:HF required = (630 x 10) = 6300 gallons
In estimating the damage radius of a well in the absence of well test data the
following can be used as a guide to estimate treating volumes and pump rates:
- · Permeability is 5.0 md or less - assume damage zone thickness to be 3.0 inches. (Refer to Table 12).
- · Permeability is greater than 5.0 md - assume damage zone thickness to be 6.0 inches. (Refer to Table 13).
9.4 Porosity Design Factors.
In sandstone matrix acidizing, the formation porosity is used for volume calculations
only:
1. The post-flush or overflush volume should be calculated for 4.0 to 5.0
feet of radial penetration based on porosity.
2. Porosity can be used to determine penetration of the live HCl if the
solubility in HCl is known. If HCl solubility is greater than or equal to
10.0% then the standard HCl volume of half the HCl:HF volume is
usually inadequate to prevent precipitation of reaction by-products.
3. HCl volume is based on HCl solubility. The HCl preflush volume should
be sufficient to remove all HCl soluble material in a two foot radius
from the wellbore.
4. HCl:HF volume requirements should be calculated based on a four
hour contact time. Any longer contact time in the near wellbore area
will result in damaging precipitates
.
Where the formation damage is suspected to be shallow (0 to 2.0 feet) an estimate
of the treating volume of acid required can be obtained from Figure 14 based on
treating radius and formation porosity.
Where it is suspected that damage is deep (greater than 2.0 feet) the following
equation can be used to estimate the volume of acid required:
9.5 Reservoir Solubility.
As a general rule, formations of less than 10.0 per cent solubility are not usually
stimulated with hydrochloric acid. However, hydrochloric acid may be applied to any
type of formation to remove "skin damage". Nevertheless, there are exceptions to
this rule. For example, if the soluble section of the formation is a sand consolidating
material, acidizing results may be less effective than when limestone or dolomite
"stringers” are present. This is true even where the limestone or dolomite is of low
solubility.
Limestone and dolomite formations react at high rates with hydrochloric acid and at
moderate rates with formic and acetic acids. The reaction of sandstone formations
with these acids, however, is limited to the amount of calcareous material present in
the formation. Hydrofluoric acid on the other hand, reacts with sandstone, silt, clay
and most drilling muds, and has been found to be effective in stimulating sandstone
reservoirs.
Note, that all acid stimulations using hydrofluoric acid should be preceded with a
preflush and followed with a post-flush to prevent precipitation of reaction byproducts.
Formulations for the acid treatment of sandstone reservoirs based on
carbonate content are given in Table 14.
Factors to be considered when choosing the appropriate acid strength are:
- · Reaction time of active acid within the formation.
- · Corrosion of tubular goods.
- · Formation Solubility.
- · Reaction product effects.
- · Sludging and emulsion forming properties.
- · Etch pattern on the formation
- · Compatibility of demulsifier with formation and other products in the treating solution.
be acid soluble. Solubility is a measure of that fraction of the formation that will react
with an acid treating solution expressed as a percentage. Although no theoretical
basis has been developed for the figures given in Table 16, there is general
agreement that low formation solubilities call for low acid strengths and high
formation solubilities call for high acid strengths. The figures in Table 16 summarise
current field practice.
9.6 Acid Insoluble Organic Deposits.
Acid insoluble organic damage can occur in all phases of the life cycle of a well,
which include:
- · Drilling and Cementing.
- · Completion and Work-over.
- · Production.
9.6.1 Drilling and Cementing.
Organic deposits can form where:
1. Thermodynamic cool-down occurs, and the formation fluids reach their
cloud point with insufficient BHT for thermal recovery.
2. Utilisation of aliphatic oil-based muds can result in asphaltene
precipitation.
3. High pH filtrate upsets the double-bonded electrolyte which stabilises
the asphaltene/maltene aggregate.
9.6.2 Completion and Work-over.
Organic deposits can form due to:
1. Thermodynamic effects, as with Drilling and Cementing.
2. The use of high chloride brines, which can result in the creation of
nucleation sites for the branching of paraffins and asphaltenes.
3. The use of incompatible solvents (such as diesel), which can cause the
instantaneous precipitation of asphaltenes.
9.6.3 Production.
When a virgin reservoir is initially completed, the formation fluids are in complete
physical and chemical equilibrium. However, as production begins, the “light ends”
(solvent) are preferentially produced, leaving the heavier molecular weight
components (solute) behind. Therefore the longer a well is produced, the higher will
be the probability of acid insoluble organic deposition.
9.6.4 Organic Deposit Damage Mechanisms.
1. As water production increases, chloride nucleation and maltene
stripping result in paraffin and asphaltene deposition.
2. The longer the well is produced, the higher the thermal sensitivity
becomes.
3. Deposition naturally occurs in the production phase, in-situ, as a result
of Brownian Motion and shear diffusion.
4. Asphaltene coking can occur at elevated temperatures.
9.6.5 Organic Deposits Treatment Options.
1. Pump 25 to 50 gallons per foot of xylene and/or toluene combined with
appropriate commercial solvents, dispersants or inhibitors, (Paravan
Treatments) as indicated by solvent solubility tests. Soak times of four
hours or more are often required.
2. If diversion is needed and/or Auxiliary acid treatments are to be
pumped, then water dispersible paraffin and asphaltene solvents
should be included.
9.6.6 Organic Deposit Analytical Procedures.
1. Thermodynamic modelling, using gas/liquid chromatography, can aid in
determination of cloud point (damage potential) and melting point
(thermal recovery). Solvent extraction is also an accepted method.
2. Solvent solubility tests utilising samples of sludge or synthesised
sludge can be carried out. The sludge can be packed onto preweighed
stainless steel screens or melted onto the sides of preweighed
jars. The sludge is then soaked in various solvent-chemical
systems for 4 hours. The solvent is then removed, the sludge dried and
weighed. The optimum system can be determined by this method.
3. Water dispersibility tests. The acid system is treated with waterdispersible
solvents. Sludge samples are then added to the sample jar
and heated to melting point. The samples are then placed in a shaker
and dispersibility and sludge prevention are monitored.
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