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Introduction
Improving productivity in these Niger
delta brownfields that produce heavy crude and experience fines migration had
been approached with little or no consideration to such challenges as water
production. Many wells were treated with a conventional mud-acid system, either
with or without a solventsoak treatment. Clay-control agents are no longer used
to stop fines problems because the additive had little effect. Wells with high
water cut were treated only with solvent material, realizing minimal effect.
Foam diversion often had inconsistent results. Other diverting
techniques also proved unpredictable in
this environment. A coating of heavy crude on the formation wall inhibited the
reaction of the mud-acid system with the formation. An acid system or
formulation that would maintain matrix acidizing was needed for
well-productivity problems in the Niger delta. In December 1996, an SRH-RHF
system was used. Data indicated a
consistent production increase with evidence of deep penetration into the
damaged zone. Failures experienced with this system were traced to a shortage of
well information for proper diagnosis and the need for a core-flow test in one
field with three treatments resulting in no increase or a reduction in
production. In the past, acid stimulation was limited to wells with water cut
less than 30%. In late 2001, an
improvement was made in candidate selection, treatment design, foam diversion,
and pumping method for high-water-cut wells and heavy-crude wells. The
high-water-cut limit was increased to 60%. In 2005, a new SRH-RHF system was
developed. Its application in nine wells with heavy or medium crude was
successful.
Reservoir Description
The Niger delta basin is a prolific
hydrocarbon province covering 80,000 sq km. Wells treated with the new SRH-RHF
drain eight different reservoir sands. Most of the treated sands consist of
several sequences of shale and sandstone with mostly medium-to-poorly
consolidated sands. The sandstones are fine-tomedium quartz;
poorly-to-moderately sorted smectite, kaolinite, and illite clays; with
feldspathic and carbonate scale materials. Permeabilities of the treated
intervals ranged from 500 to 2,000 md, and well bottomhole static temperatures
ranged from 125 to 163°F.
Well
Completion
Most
of the operator’s oil wells are dual producers, typically completed with 23/8-
to 31/2-in.
tubing in a perforated cased hole or gravel packs with wire-wrapped screens
inside perforated casing.
Damage
Production impairment is believed to be
heavy-hydrocarbon precipitation, clay swelling, fines migration, wettabil-ity
alteration, and, to a lesser extent, hydrate formation and treatment-fluid
damage. Associated damage mechanism may be scale deposition caused by filtrate
invasion, especially in wells with high water cut, with occasional problems with
emulsions and formation-/treatment-fluid incompatibility.
Fines Migration.
Fines are quartz or clay particles smaller
than 44 μm. The origin of fines is multiple and complex, thus making it
prevalent in most oil fields. Damage caused by fines migration often is worsened
by associated-water production, high oil viscosity, and crude-oil gravity. Fines
cause damage by blocking pore throats and acting as nucleation particles for
heavy-hydrocarbon deposition and emulsion stability.
Reservoir-Fluid-Flow Rate.
There is a critical fluid-flow rate beyond
which the hydrodynamic force exceeds the binding forces holding fines particles
together, and the fines begin to move. A sudden increase in flow rate also could
induce fines migration, such as when choke sizes are changed or not designed
properly. Intermittent gas lift and uncontrolled flowback after stimulation can
induce fines migration. In the case of kaolinite, illite, and nonclay fines that
are attached loosely to formation pores, exceeding the critical flow rate will
dislodge and migrate fines.
Wettability.
Particle wettability and interfacial
forces influence particle mobility. With multiphase flow, particles will move
only when the wetting phase moves. Because fines and clays often are water-wet,
water production or backproduced water-based treatment fluids likely will cause
fines to dislodge and induce mobility. When only oil is flowing, little or no
fines migration exists.
Acidizing.
Injection
of water-wetting treatment fluids or surfactant/solvent can mobilize fines that
are held in place by wettability phenomena or interfacial forces.
Two-Phase
Flow.
Simultaneous flow of water and oil will
cause fines to migrate because water is mobile enough to dislodge the fines.
Local pressure disturbance caused by multiphase flow keeps fines agitated and
reduces the opportunity to develop permanent bridges.
Medium/Heavy Crude.
Many
of the studied wells produce heavy crudewith gravity between 22.3 and 10°API.
The challenges encountered in acidizing heavy crude include high sludge tendency
from treatment-/formation-fluid incompatibility, resulting in a high tendency
for emulsion production after acidizing. Also, viscous crude could inhibit
treatment fluids from reacting with damaging material if the treatment fluid is
not properly designed The resulting low production or insignificant oil gain
often is caused by poor candidate selection, possibly through improper or poor
well analysis. The high-viscosity heavy crude often limits most HF treatments,
especially a nondeep-penetrating HF system, to the near-wellbore region where
most of the HF system is spent on clays having very large surface area compared
to quartz.
Control/Design
Candidate selection involves analysis of
the production-performance history, experience with heavy-crude behaviors, and
good analytical skills. A full systems analysis can establish the
extent and severity of the damage. Also,
the gas/oil ratio, tubinghead pressure, water and gross-fluid production,
bottomhole-pressure (BHP) trend, type of (removable)
skin damage, information on nonremovable damage, and reservoir pressure are
considered in the analyses to assess adequately the feasibility of acidizing.
Most of the treated wells are within a screening envelope for matrix
stimulation. This screening includes economical remaining reserves, productivity
index (PI) <10 (obtained from BHP survey), a flow efficiency (ratio of actual
to ideal PI) <0.5, and PI decline >30%. Good knowledge of the water source
is important in highwater-cut-well stimulation. A full systems analysis,
including cement-bond and porosity logs and production and permeability
profiles, is carried out to establish the source of water and severity of the
damage. Interval mineralogy, reservoir/damage permeability, and frequency and
previous acid stimulations are considered.
Nodal Analysis.
To confirm the presence of impairment and
to characterize potential improved production from these candidates,
nodal-analysis simulations were run in three stages.
• Pressure/volume/temperature matching
enables accurate prediction of fluid properties during vertical lift.
• Gradient analysis obtained from
correct pressure and test data helps to determine the appropriate wellbore
correlation for the prediction of bottomhole flowing pressure.
• Systems analysis quantifies damage and
defines the range of expected production increase.
Fluid Choice.
It
is necessary to evaluate the fluid pumped into the formation to determine the
treatment formulation. In many low-pressure wells, diesel oil or a diesel/xylene
mixture is used for a prestimulation injectivity test. However, the oil-phase
fluid can cause problems when the near-wellbore water saturation is high (as in
high-water-cut wells). The oil-phase fluid will cause the formation to become
more oil-wet and will occupy the pores in water-producing zones. The effect is
reduced oil mobility, increased water and fines mobility, and destabilizing the
foam pad placed to divert the acid system from the water zone or
high-permeability zones. The new approach uses a water-wetting 3% ammonium
chloride (NH4Cl)
salt solution for the injectivity test. Approximately 10 to 20 bbl in excess of
the coiled-tubing (CT) or tubing volume is used. This water-wetting fluid acts
as a hole-conditioning fluid before foam-pad placement. NH4Cl
is compatible with most formations and with acid and foam systems. When
injectivity is low, acid is spotted with CT and injectivity is repeated.
Fluid Design.
Fluid design (or acid recipe) depends on
the damage mechanism and results of core-flow tests if available. Usually,
production impairment in the treated reservoir sands was the result of fines
migration and, to a lesser extent, clay dispersion and swelling. A conventional
acid recipe was designed with a solvent soak for reservoirs with heavy oil or a
history of organic deposits (e.g., wax, asphaltene, and paraffin). The pumping
sequence [solvent soak (an oil phase flowed back before foam or acid), foam,
foam pad, and then acid] resulted in destabilizing the foam in the near-wellbore
region. Use of a soak treatment, without flowback before pumping, retained foam
stability and helped displace or push back the fines. The modified sequence
[solvent (oil-phase injection with a wetting agent and no flowback), foam, foam
pad, and then acid] minimized possible foam contamination by the organic
solvent.
Placement and Diversions.
Several diversion techniques improve
treatmentfluid placement into the zone of interest. Mechanical techniques
include straddle packers, wash cup, and ball sealers, while chemical techniques
use viscous fluids, foam solutions, and oil-soluble resin. Because the pumped
fluid will take the path of least resistance, it is vital to select the
placement method and diversion techniques carefully for stimulating
high-water-cut wells. Most of the studied wells are in highly permeable
heterogeneous reservoirs with a gravel pack across producing intervals that
range from 10 to 50 ft long. Acid placement in a few of the wells was carried
out with CT, while most jobs were performed by bullheading treatment fluid into
the formation. Foam diversion was used in selective stimulation of oil zones
preferential to water zones and to aid the effective distribution of treatment
fluids in zones with a perforated interval greater than 15 ft. Identifying the
water source or point of inflow into the wellbore is essential in designing the
foam pad for diverting acid from the water zone. Matrix stimulation of intervals
having water influx from high-permeability zones in a heterogeneous reservoir
will benefit more from foam diversion. Treatment of a reservoir in which water
influx is from a lowpermeability zone (water encroachment or mature coning
effect) or zones with homogeneous permeability could be achieved by increasing
the foam pad. In this case, the foam is expected to degrade faster in the oil
phase. The volume of foam required is estimated at 25 to 30% of main treatment
volume, and 65- to 70%-quality foam was used.
Maximum Safe Injection Rate and
Pressure.
The
formation-fracture pressure (or maximum surface-pumping pressure) is considered
in the decision. Use of CT is preferred with long intervals (greater than 200
ft) having a permeability contrast greater than 300 md. Preference also is given
to the use of CT for horizontal wells with zones longer than 400 ft. Bullheading
at maximum safe pressure is a suitable approach to short-string-interval
stimulation when the CT cannot access that portion of the wellbore. The rate
available through the CT can be limited especially in some high-production
intervals with high water cut. Most fluids (even foam pad) pumped through CT
degrade before acid injection as a result of the long pumping time at the low
rates and accompanying high CT pumping pressure, leading to stimulation of the
water zone and reduction in acid-penetration depth. A successful treatment was
achieved with the combination of high-rate pumping (bullheading) of treatment
fluids and foam diversion. During high-rate and foam-diversion operations,
production tubing is pickled with 10% hydrochloric acid. The pickling fluid
usually is nitrified and lifted out of the tubing (with a plug set in the
deepest nipple profile) to prevent ferrous scales and rust from contaminating
the stimulation recipe or entering the formation.
New Retarded-HF System.
Retarded acid is a slow-reacting acid
system or an acid system with a controlled rate of reaction. This slowed
reaction with formation-damaging material enables deeper penetration into
damaged zones and prevents formation of damaging byproducts. The SRH-RHF system
is formed both at the surface and in-situ. The HF is generated through slow
release of hydrogen ions by an organic salt, acid, or ester compound with
multiple hydrogen atoms capable of ionizing into solution for replacement
reaction or endothermic reaction. The delayed release of hydrogen assists in
deep penetration of the formation. In 2005, a new acid system was developed that
generates HF from the reaction between ammonium bifluoride and an ester compound
with multiple hydrogenions. The release of the hydrogen ion from this ester is
governed by pH changes, first at the surface and later in-situ. The consumption
of one hydrogen ion will shift the equilibrium and, thus, release additional
hydrogen ions to balance the system. The end product of the ester compound is a
good wetting agent. Its slow reaction reduces fines size and allows longer
reaction time on the formation without deconsolidation.
Laboratory Analysis and Fluid
Selection.
Field
trial by the operator of any new acid system is allowed after detailed core-flow
tests and fluid-compatibility tests confirm that the new acid system is better
than a conventional acid system. Core-flow-test results of the SRH-RHF system
proved that the retarded-acid system has superior performance over regular mud
acid. However, for all the treatments carried out, compatibility tests between
treatment fluid and formation fluids were conducted and recipes were modified
until the sludge and emulsion tendency was eliminated. Fluids were not pumped
until a clean mixture was observed in each case, indicating no insoluble
precipitates formed when commingled.
Analysis
Of the 10 intervals analyzed for this
paper, seven were heavy crude and two had medium crude. They also had water cuts
between 17 and 36%. Seven of these stimulation candidates had been treated
earlier with mud acid before the application of the new SRH-RHF system. The
importance of selection of placement methods, injection-fluid types, and recipe
designs also was part of the analysis.
Technical Comparison.
All of the heavy-crude wells treated with
this new approach demonstrated a significant increase in PI; longer
productivity; and reduced, or minimal increase in, water cut after the
treatment. Skin damage was removed in most cases, while true stimulation
(negative skin) was recorded in two cases. The partial success experienced in
one case could be attributed to poor planning that led to keeping spent acid in
the critical near-wellbore region overnight because of a lack of liquid nitrogen
and loss of lift gas. The reduced water cut and sustained production seen in
most of the wells were the result of the effectiveness of foam diversion and
high-rate pumping along with high-water-wetting, scaleinhibition, and
deep-penetrating characteristics of the SRH-RHF system and fines
stabilizer.
Economic
Comparison.
Fig. 1 shows
that wells treated with this technique had considerable incremental production
compared with marginal gains from previous techniques used on the same wells.
The wells treated with the new SRH-RHF system paid back faster (within 20 days)
than previous mudacid treatments (100 days). The fulllength paper details the
treatments and results of the nine heavy- and mediumoil intervals. JPT
For
a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt.
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