1. Was the correct type of drilling mud used.
2. What was the fluid loss of the mud whilst drilling through the zone of
interest.
3. Did lost circulation occur. How many barrels of mud were lost to the
formation.
4. Was lost circulation material used. If so, how much and what kind.
5. Are there extreme washouts in the production zone.
7.1.1 Drilling Formation Damage Mechanisms.
1. Invasion of mud particles into the formation which includes clays,
barite, other weighting agents, lost circulation materials and cuttings.
2. Drilling and cement filtrate damage may result in polymer plugging,
scale formation, surfactant altered wettability damage, clay swelling,
clay dispersion, asphaltene deposition, and oil-mud sludging
7.2 Drilling Mud Damage.
Shallow formation damage, commonly called skin damage, results when
incompatible fluids and solids invade the formation. On new wells, mud solids and
filtrate from the drilling fluid cause most of this contamination.
The mud filter cake deposited on the exposed formation face during drilling
operations consists of solid drilling mud particles and some drill cuttings. This filter
cake forms a cylindrical barrier of reduced permeability around the wellbore.
Generally, the penetration into the formation of drilling solids seldom exceeds a very
few inches in non vugular or unfractured formations.
7.2.1 Removing Drilling Mud Damage.
Laboratory tests show that acid treating solutions are most effective for removing
this type of shallow formation damage. Although the acid usually dissolves only part
of the mud solids, it effectively penetrates and disperses the remaining insoluble
solids by reacting with the formation to which they are attached.
In removing skin damage at the wellbore, small treatment volumes at low pressures
and injection rates generally are employed. Low rates allow the treating fluid to move
radially and uniformly into the damaged zone for more effective clean-up.
In designing a mud removal treatment during initial well completion several factors
should be considered.
- · Type of mud.
- · Acid Solubility of the formation.
- · Type of formation.
- · Length of perforated or open hole interval.
Acid solutions recommended for treating wellbore damage caused by various types
of drilling muds are presented in (Table 5). Whilst this table can be used as a guide,
laboratory flow tests on representative cores and fluids at corresponding
temperatures should be conducted whenever possible. For example, emulsion
testing will determine the correct concentration of surface acting chemicals to be
used in the treating solution.
7.3 Drilling Fluid Damage in Horizontal Wells.
Damage around a horizontal wellbore is neither radial nor distributed evenly along its
length. Variations in permeability (anisotropy), create an elliptical damage profile
normal to the wellbore (Figure 9). The exposure time to fluids during drilling and
completion operations will result in a truncated elliptical cone of damage along the
length of the well (Figure 10), with the base of the cone nearest the vertical section
of the wellbore.
Diversion is often difficult to achieve in horizontal section (acid tends to take the path
of least resistance), even when using mechanical diverting aids or coiled tubing.
Taking the large quantities of acid required for matrix stimulation of horizontal
sections into account, it is often desirable to consider only partial damage removal.
This will result in the creation of a stimulated zone with improved permeability
surrounded by a collar of damage (Figure 11). However, distribution of the
stimulation fluid along the length of the well is still important, particularly when
considering the nature of the damage distribution.
When stimulating with coiled tubing, the rate of tubing withdrawal and the volume of
fluid pumped into each section of the hole should take into account the identified
shape of the damage cone present, and the type of formation to be stimulated. For
sandstones, the stimulation fluid injection should mimic the shape of the damage
cone, and a truncated cone of improved permeability should result with acid volumes
and tubing withdrawal rates being closely related to porosity. For carbonate
reservoirs, the stimulation profile under matrix conditions will be dendritic, with a
wormhole network extending radially from the wellbore. The volume of acid and
withdrawal rate of the coiled tubing will be related to the expected radial wormhole
porosity created.
7.4 Cementing Considerations.
1. Did lost circulation take place during cementing. If so, how much was
lost and was it lost to the production zone.
2. Was KCl or salt used in the cement slurry. (Clays, shales and
formation water compatibility).
3. What was the fluid loss of the cement slurry.
4. Is there a good bond (to pipe and formation) across, above and below
the productive zone (CBL).
5. Are there any channels in the cement (CBL, CET).
6. What type of cementing preflush was used.
7.5 Lost Circulation Materials (LCM).
1. Determine if HCl Soluble.
- · CaCO3 dissolve in 15% HCl (1.84 lbs per gallon of acid)
- · FeCO3 dissolve in 15% HCl (2.12 lbs per gallon of acid)
2. Determine volume of LCM pumped.
3. Calculate additional volume of HCl required to completely remove the
material, this volume should be added to the required volume
calculated to achieve a 2.0 ft radial penetration.
4. Acid soaks are often helpful.
5. Auxiliary nitrogen or carbon dioxide is usually required to ensure even
distribution of the acid.
7.6 Perforating Considerations.
1. Was the casing and tubing cleaned (pickled) prior to perforating. (Mill
varnish, iron oxide scale).
2. Was too much pipe dope used.
3. Was the perforating fluid filtered. If not what was the solids content.
4. Was the well perforated overbalanced. If so, with how much differential
pressure.
5. Was the well perforated under-balanced. If so, with how much
differential pressure.
6. What is the theoretical depth of penetration of the charge used.
7. What is the shot density. Did all the shots fire.
8. Were charge size and shot density the correct choice for the
lithological characteristics.
7.6.1 Perforating Damage Mechanisms.
1. Perforating Overbalanced with dirty fluids.
2. Perforating Under-balanced with dirty fluids.
3. Inadequate depth of penetration, especially if penetration beyond the
cement sheath is not accomplished.
4. Perforation debris, compacted or crushed zone which results in
reduced permeability.
5. Diameter of perforations and the number of shots per foot. Perforation
jobs should be designed to achieve as near to an open hole
performance as possible (normally 12 SPF minimum). Inadequate SPF
will put an undue stress on the formation matrix and cause sand
production.
7.6.2 Perforating Treatment Options and Design Criteria.
1. Utilisation of perforation wash tool. The higher the shot density the
shorter the effective wash zone must be. For example at 12 SPF wash
6.0 inches at a time.
2. Make sure that the perforating fluid was filtered, examine and retain
samples if possible. If the fluids average particle size exceeds 10.0
microns, then a mud acid job is required. This is especially true prior to
a Gravel Pack since this would result in "locking" the damage in place.
3. HCl acid soaks are usually ineffective at removing perforation damage
unless the HCl solubility is greater than 20%.
7.7 New Completion Considerations.
1. Was the well killed. If so, what was the kill fluid.
2. How much volume of kill fluid was used. Was this volume completely
produced back.
3. Was the kill fluid filtered. If not, what was the solids content.
4. Was the kill fluid tested for compatibility with the crude oil or with crude
oil from an offset well.
5. Was the well circulated clean to Total Depth prior to being put on
production.
6. Were any surfactants added to the kill fluid for surface tension
reduction. Were any other chemicals used.
7.7.1 Completion Damage Mechanisms.
The most common cause of completion fluid damage is dirty fluids resulting from
poor filtration practices and fluid incompatibility.
7.8 Work-over Considerations.
1. Refer to completions questions.
2. Has scale inhibitor been used. If so, is it still effective.
3. Have acid treatments been performed in the past. If so, what did they
consist of and how much volume was pumped.
4. How were the previous jobs pumped.
5. Has diverting material ever been used. If so, how much and what kind.
6. Were previous treatments successful. If so, how successful in terms of
production increase.
7. Have the production increases from previous acid treatments been
long term.
8. Has the zone been previously fracture stimulated. If so, what volume
and type of fluid were pumped .What type and volume of proppant
were used. What were the treatment results.
9. What was the obtained fracture height.
10. Is the production equipment still operating properly.
7.9 Disposal Wells Design Considerations.
The unique aspect of disposal well treatment is that the formation damage can be
isolated easily by analysing the plugging agent at surface.
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