Acid treatment design

Once you determine that a well is a good candidate for matrix acidizing and have selected appropriate acids, you are ready to design the treatment. Essentially, the design process is a systematic approach to estimating and calculating injection pressure and rate, volumes, and concentrations. Live HF acid usually penetrates only about 6 to 12 in. into the sandstone before spending. If acid can easily reach nearby plugging solids, small volumes of 25 to 50 gal/ft of HF-type acid can dissolve this damage; however, with more severe damage, more time and volume are needed to reach the plugging solids. Effective acid diversion reduces acid volumes needed.

Matrix acidizing design guidelines

The recommended steps in treatment design are:

• Estimate safe injection pressures: determine present fracturing gradient, determine present bottomhole fracturing pressure, and determine allowable safe injection pressure at both the wellbore (at least 200 psi below fracturing pressure) and at the surface (tubing and wellhead pressure limitations).
• Estimate safe injection rate into the damage-free formation.
• Estimate safe injection rate into damaged formation.
• Select stages required for fluid compatibility.
• Calculate volume of each stage required: crude oil displacement, formation brine displacement, acetic acid stage, hydrochloric acid stage, hydrofluoric acid (HF and HCl acid) stage, and overflush stage.
• Select acid concentrations according to formation mineralogy. More detailed procedures with a calculated example are available in McLeod. Table 1 provides a one-page summary and guide to selecting fluid stages and volume.

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  Table 1

Acid type and concentration

Permeability and mineralogy determine the compatible concentration of HCl or acetic acid in the preflush stage and HF and HCl acid in the HF-/HCl-acid stage. Guidelines for proper concentrations are provided in Table 2. The background for the acid-use guidelines in Table 2 is given in Da Motta. These guidelines are not absolutes and probably should be modified according to more recent research. These guidelines were provided as a fairly conservative approach to avoid problems that could occur with 12% HCl and 3% HF that were regularly used prior to 1985. These guidelines helped when no previous experience existed in acidizing a particular formation. Evaluated experience provides the most reliable information. Acid flow tests with cores are reliable when long cores are used. These tests are expensive and, therefore, seldom performed.

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  Table 2

Gdanski show the benefit of preflushing with 10% acetic acid and dissolving chlorite with 10% acetic and 1% HF acid. At temperatures higher than 200°F, Wehunt et al. recommend decreasing HF-acid concentration to 0.1% HF in 10% acetic acid at 380°F. However, at low temperature (less than 125°F), stronger acids are required to remove damage, and secondary and tertiary reaction precipitates are minor.

The guidelines in Table 2 do not specifically address permeability between 10 and 100 md, a range where field results have been erratic. Some treatments are very successful, and some result in little or no change. Proper selection is assisted by:

• Detailed petrographic studies
• Realistic core flow studies
• Reliable geochemical modeling

Pore throat sizes in these moderate-permeability formations are small enough to screen dispersed, undissolved clay-sized fines or spent acid precipitates and cause internal pore plugging. Recent research has helped to better define formation response to acids. As a practical matter, small hydraulic fracturing treatments are simpler and more cost-effective than matrix acidizing in some of these formations with permeability less than 50 md.

The guidelines for low permeability (less than 10 md) were based on treatments in which breakdown with acid probably occurred to open damaged perforations. The lower concentrations prevented massive precipitation in the formation and damage to the isolating cement yet were sufficient to clean up some perforation damage. Such treatments are probably obviated now by the advent of tubing-conveyed perforating.

Retarded HF acids

Retarded HF (RHF) acids offer alternatives to the acids in Table 2, are less reactive with sandstone, and normally result in deep acid penetration into the formation. Three RHF acids that are based on boric acid, aluminum chloride, and a phosphonic acid complex were examined recently with guidance for their use. A newer retarded sandstone acid is based on fluosilicic acid for deeper clay dissolution. Fluosilicic acid can be injected by itself into a sandstone reservoir without causing any damage as long as it is blended into HCl acid or an organic acid. These acid mixtures improved the performance of two Brazilian water-injection wells by removing deep clay damage. A preflush of HCl or acetic acid must be used to dissolve carbonates ahead of the fluosilicic acid to prevent tertiary precipitation of calcium/aluminum fluoride complexes. In sandstone formations with more than 1% carbonate, the cost of sufficient acid preflush may prohibit treatment of damage beyond 2 ft in depth.

Geochemical models

Several geochemical models exist today that provide guidance on acid type and concentration. The acidizing model of Thomas and Fannin predicts dissolution of rock to increase porosity and permeability and incorporates the resistance of a diverting agent to ensure good acid coverage in a layered sandstone formation. The model does not consider precipitation and relies on an expert system to choose appropriate acid types and concentrations. The model of Davies et al. is based on equilibrium chemistry and predicts the improvement in porosity and permeability by rock dissolution. It also predicts the porosity decrease by precipitation of species and the final permeability of the rock around the wellbore as a result of net dissolution. It helps select the volumes of acid required and the optimum acid types and concentrations to maximize well performance.

Gdanski and Schuchart developed a geochemical model for sandstone acidizing that is helpful to engineers dealing with acidizing of sandstone containing sensitive minerals like zeolite and chlorite clay and for formation temperatures above 200°F. Above 200°F, various organic acids are recommended for certain minerals.

Quinn et al. report on the application of a complex kinetic geochemical model to explore the importance of the formation minerals, mineral precipitation, and the effect of acid and injection rate. A new permeability prediction model relates the permeability of a permeable medium to the porosity, grain-size distribution, and the amounts and identities of all detrital minerals present and predicts productivity improvement. The optimal matrix stimulation is a compromise between maximizing the dissolution of the damaging minerals and minimizing secondary precipitation.

An integrated matrix stimulation model by Bartko et al. for sandstone and carbonate formations assists in:

• Determining formation damage, selection, and optimization of fluid volumes
• Provides a pressure skin response of the acid treatment
• Forecasts well productivity

Noteworthy books on Acidizing

Kalfayan, L.J.: Production Enhancement with Acid Stimulation (PennWell Books; 2000, 2007).

Noteworthy papers in OnePetro

Thomas, R.L., Nasr-El-Din, H.A., Mehta, S., Hilab, V., and Lynn, J.D. 2002. The Impact of HCl to HF Ratio on Hydrated Silica Formation During the Acidizing of a High Temperature Sandstone Gas Reservoir in Saudi Arabia. Presented at SPE Annual Technical Conference and Exhibition, 29 September-2 October, San Antonio, Texas. SPE 77370.

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Matrix acidizing

Acid placement and coverage

Acid additives

Controlling precipitates due to acidizing

Acidizing preparations

Conducting the acidizing procedure

Acidizing safety and environmental protection

PEH:Matrix_Acidizing