Carbonate Stimulation
Carbonate Stimulation
Carbonate Stimulation
Carbonate sequences, those comprising limestone and dolomite formations, present some of
the most difficult challenges facing field operators. Carbonate reservoirs often have large and
highly variable completion intervals, which can greatly complicate stimulation and production
operations. In many cases, these reservoirs exhibit marked vertical and lateral heterogeneity
caused by permeability barriers, natural fractures, and complex porosity distributions. These
variations can be particularly bewildering for engineers who are trying to devise effective
workover and stimulation strategies.
In this article, Steven Davies and Shrihari Kelkar examine the techniques and technologies
that field operators can use to stimulate carbonate reservoirs.
Zone barrier
Zone barrier
Figure 2: Matrix stimulation removes or bypasses damage in the pore spaces between grains and leaves the zone barriers within
the reservoir intact.
A stimulating environment
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Acid
Acid
Figure 3: To hydraulically fracture carbonate rocks, the workover team pumps acid to fracture the formation and to create a nonuniform
etched pattern on the fracture surfaces.
Acid fracturing
Acid fracturing is a hydraulic fracturing treatment
performed in carbonate formations. The objective is to etch
the open faces of induced fractures using an HCl treatment
(Fig. 3). When the treatment is complete and the fracture
closes, the etched surfaces provide high-conductivity flow
paths from the reservoir to the wellbore.
Hydraulic fracturing of clastic rocks, in contrast, uses a
proppant to hold the fracture open and so create a highpermeability flow path along which fluids flow into the well.
To reduce or prevent leakoff (loss of treatment fluids to
the formation), conventional acid fracturing treatments use
multiple stages of nonreactive fluids and acids. This is
designed to minimize the leakoff by increasing the fluid
viscosity. By increasing the acids viscosity, the stimulation
engineer can also slow the rate of reaction between the acid
and the formation, which helps to improve fracture
geometry. Viscosity can be modified by adding a polymer to
the treatment fluid. This technique has proved successful in
many oil fields, but the polymers form a filtercake that can
reduce production, especially in tight formations.
Crosslinking compounds are used to control viscosity.
These are usually metallic salts mixed with a base-gel
polymer fluid, such as a guar gel system, to create a viscous
gel. The crosslinker reacts with the multiple-strand polymer
to couple the molecules and create a fluid with high, but
closely controlled, viscosity. The behavior of the crosslinkers,
which enable the polymer system to operate in a narrow pH
window, can be difficult to predict at high temperatures.
Treatments using crosslinkers should take account of the
conditions needed to break the gel structure to ensure
satisfactory cleanup and disposal.
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(a)
Diversion
Diversion is a technique used in injection treatments, such as
matrix stimulation, to ensure uniform distribution of the
treatment fluid across the treatment interval. Injected fluids
tend to follow the path of least resistance, and this may lead
to inadequate treatment of the least permeable areas within
the stimulation interval.
Using diversion methods, engineers can focus treatment
on the areas that require more stimulation. To be effective,
the diversion effect should be temporary to enable the full
productivity of the well to be restored when the treatment is
complete. There are two main categories of diversion:
mechanical and chemical.
Mechanical methods
Mechanical diversion techniques, such as ball sealers, packers,
and straddle-packer assemblies, are used to divert reservoir
treatments to the target zone. Ball sealers and solid-particle
diverting agents incorporated into the treatment fluid form a
temporary plug in the perforations accepting the most fluid
flow, thereby diverting the remaining treatment fluid to the
less permeable zones (Fig. 4a). Packers and straddle-packer
assemblies function by performing several short treatments
over a longer interval to help ensure even treatment over the
entire zone (Fig. 4b).
Though widely used, mechanical diversion methods may
not always be feasible or recommended. They are often
ineffective for stimulation projects in long horizontal or
extended-reach wells.
(b)
Figure 4: Ball sealers and solid-particle diverting agents create a temporary plug in the perforations that are accepting the most fluid flow.
This forces the remaining treatment fluid to enter the less-permeable zones (a). Packers and straddle-packer assemblies allow the operator
to perform several short treatments over longer intervals, thereby ensuring that treatment is evenly distributed over the entire zone (b).
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Chemical methods
30
800
20
650
10
Water cut, %
Figure 5: When combined with fresh acid, the SDA fluid has a low
viscosity to facilitate pumping. However, once this fluid enters a
carbonate zone and the acid spends, the polymer crosslinks and
the fluids viscosity increases.
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950
pH
56
40
Oil flow rate
Water cut
Viscosity
1100
500
Average production
from 11 offset wells
Water-bearing zones
One of the fundamental requirements for any stimulation
program is that the increase in conductivity is restricted to
the hydrocarbon zone. Acid or fracture stimulation of waterbearing layers adjacent to the reservoir would lead to a
sharp rise in water production with the associated issues of
fluid handling, separation, and disposal. In extreme cases,
stimulation of the water zone could end the economic life
of the well.
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400
Moved water
Post-treatment
Pretreament
Water
320
Oil
Dolomite
240
0
Low
160
Orientation north
Amplitude image
120
240
360
High
0
Pyrite
Gas flow
Gas
Bound water
Oil flow
Water
Lit
Water flow
Oil
ELANPlus volumes
%
1,200
0
DEFT bubb.
1
m3/d
190
m3/d
1,600
80
Zone
Well 1
CT placement with
no diversion
Well 2
CT placement with
foam diversion
Well 3
Bullhead using
gelled acid with
no diversion
Well 4
(Schlumberger treatment)
CT placement with mud and
silt removal acid and
temporarily crosslinked
acid diversion
Figure 7: Combining the MSR* mud silt remover with an iron chelating agent provides good
dispersion of drilling muds and formation silt.
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Current challenges
In many countries across the Middle East and Asia,
horizontal wells have become the preferred approach for
developing carbonate reservoirs. The long sections in some
of these wells present major problems for operators who
want to stimulate their wells.
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Horizontal
section
Horizontal
section
Horizontal
section
(a)
1
Horizontal
section
(a)
(b)
3
Horizontal
section
Horizontal
section
(b)
10: Bullheading acid into a horizontal well tends to concentrate the acid in the heel or toe section of the well and leave the
Figure
remainder of the hole untreated (a). Notches created along the length of the borehole wall tend to fill with acid, which distributes
the effects of the treatment along the well (b).
Horizontal
section
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No leakoff
Reservoir zone
Figure 11: The acid is pumped as a solid, and chemical reaction only begins once it has found its way into the fracture. While acting
as a proppant to hold the fracture open, the solid hydrolyzes and reacts to etch the fracture surface.
The future
The high degree of heterogeneity encountered in
carbonate reservoirs makes them very difficult to
manage. As more of the worlds large carbonate oil
reservoirs mature, operators are turning to stimulation
methods to optimize water or gas injection and extend
the productive life of the field.
Efforts to enhance the stimulation of carbonate
reservoirs will depend to a large extent on what is
achieved in other technical areas. Advances across a
range of disciplines, from petrophysical analysis to
geophysical imaging, will help asset teams to manage
their carbonate reservoirs more effectively. The key to
improving oil and gas production from carbonate fields
is a clear understanding of the reservoirits structure,
lithology, and petrologycombined with an effective
array of stimulation technologies.
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