Acid treatments are often followed by an overflush, either diluted HCl or ammonium chloride [NH4Cl], to remove the treatment- reaction products from the near-well volume. A treatment normally includes injection of a diverter followed by a repetition of these three stages.
reacts with clays, leaving behind a glassy borosil- icate coating that cements and stabilizes clay particles.6
A wide variety of acid formulations is available, and the best treatment for a given formation depends on the characteristics of that formation.7
The new Virtual Lab geochemical simulator provides a tool that helps guide the selection based on formation parameters and treatment chemicals. The simulator models reac- tions and indicates the amount and location of dissolution and precipitation of mineral species.
The primary reaction between aluminosili- cates and HF from ClayACID and mud-acid treatments yields fl uosilicic acid [H2SiF6], along with several aluminum-fluorine complexes. In the presence of sodium and potassium, and under certain conditions of temperature and acid concentration, precipitation of compounds such as sodium fl uosilicate [Na2SiF6] and potas- sium fluosilicate [K2SiF6] can occur. In the presence of additional aluminosilicates, H2SiF6 can react to produce amorphous silica [H4SiO4] as a secondary reaction. Amorphous silica can also result from tertiary reactions of aluminum fl uorides with aluminosilicates.8
Amorphous silica and the other compounds listed above can block pores when they precipi- tate. A successful treatment design must minimize the precipitation of these compounds in the formation, particularly in the critical matrix.9
Simulated Reactions 6 5
Retarded acid 12/3 mud acid
4 3 2 1 0 0.5 Radius, m 1.0 1.5 0
The reaction of HF with minerals in sandstones is slow, and the secondary and tertiary reactions that generate precipitates are even slower. The outcome of an acid treatment depends strongly on the amount and location of the precipitates. Therefore, predicting the results of a treatment requires knowledge not only of the equilibrium reaction products, but also of the reaction kinetics of the acid in the formation. Reaction kinetics determine the rate at which the concentrations change as the system approaches equilibrium. The composition at equilibrium depends on the stability of the species at the given conditions and is calculated from thermodynamic data. Both kinetic and thermodynamic parameters must be known for all reactive fluids and minerals to predict the amount and the location of dissolved and precipitated minerals around the wellbore. Past practice has been to obtain specific reaction information through core-plug tests. Ideally, a core should come from the well and formation that is to be acidized, but it often comes from a nearby well. Outcrop samples and samples formed of packed sand mixed with clay minerals have also been used, but matching a specific formation mineralogy and sedimentol- ogy may be diffi cult.
Model parameters: 149° C
Kaolinite, 10% Calcite, 3%
Quartz, 87% Porosity, 20%
Although a core-flow test can provide vital information for designing an acid job, there are two inherent problems with such tests: the core plug is too short and the radial geometry around a wellbore is not honored (left). Most core plugs are only a few inches long. Reaction products fl ow out of the core before the secondary and tertiary reactions can occur and can generate precipitates. Use of 3-ft long cores has been recommended to alleviate this prob- lem.10
However, obtaining sufficient formation
> Acid cleanup in core and near-well formation. A short core plug represents a small part of a treatment volume in a formation. At the length scale of a short core, the permeability appears to improve after a 12% HCL and 3% HF (12/3) mud-acid treatment, but reprecipitation damages formation permeability just beyond that length. The retarded acid results in better permeability over the treatment volume extending 0.9 m [3 ft] or more. Permeability (k) is plotted as a ratio to the far- eld, undamaged permeability (k0), which is shown for comparison with the treated permeabilities (dashed line).
material for long cores is diffi cult. Analog outcrops or sandpacks can provide suffi cient material, but at the expense of potentially poor matches to for- mation mineralogy and sedimentology. Long linear cores do not address the geome- try problem. As injected fluid flows out from a wellbore, the cross-sectional area that it flows through increases proportionally to the radius. With the same volume fl owing through a larger cross section, the fl ow rate decreases away from the wellbore. For an 8-in. diameter wellbore, the
fl ow rate 3 ft into the formation is only 10% of the rate at the sandface. This slower flow rate strongly impacts the location of precipitates from secondary and tertiary reactions (next page).
60
Oilfi eld Review
Wellbore
k/k0
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