Figure 1. After core testing of a polymer-free diversion system for acid stimulation, both the low- and high-permeability cores had improved permeability and multiple wormholes. (All graphics courtesy of BJ Services)

Widely contrasting permeability and long horizontal intervals in Saudi Arabian wells complicate the design of matrix acidizing treatments to remove drilling-induced skin damage.

Modern retarded acid systems and new diversion technologies have become typical components of effective stimulation treatments in these wells. Analyzing a large collection of operational case histories provides several design guidelines and best practices for matrix stimulation strategies in Saudi Arabia.

Acid contact

The key to successful skin remediation is ensuring that live acid contacts the complete productive interval and is distributed fairly evenly across the zone. Slow dissolution and effective diversion are particularly critical in long horizontal wells — that is, most of the wells in this analysis.

For example, regular hydrochloric acid will react very rapidly with carbonate formations, especially at high bottomhole temperatures. In a long horizontal lateral, a bullheaded acid treatment might spend itself on the formation near the heel before reaching the desired placement at the toe. As an alternative, coiled tubing (CT) enables pinpoint placement in long, horizontal and deviated openhole intervals. Where additional formation penetration is required, emulsified acid, which dissolves 15 times slower, is employed allowing it to travel further along the well bore and penetrate deeper into the formation before completely spending.

Once the acid reaches the intended interval, the problem of formation heterogeneity requires some means of ensuring that treating fluids reach lower-permeability rock rather than spending solely in the high-permeability sections. Nitrogen foam, wax beads, benzoic acid flakes and gelled polymers have been used to divert acid at the wellbore wall away from high- to low-permeability rock, but shortcomings in these diversion technologies led to interest in using polymer-free surfactants as diverting agents.

For example, BJ’s Divert S fluid has a low viscosity in the concentrated acid, with viscosity increasing rapidly as the acid spends, creating a self-diverting acid system that breaks quickly with high temperature and/or hydrocarbon contact. The fluid's shear-thinning nature also allows it to act as a friction reducer to minimize the surface treating pressure required to pump through small-inside-diameter tubulars, such as CT.

Initial core diversion testing involved pumping 28% hydrochloric acid with 4 %vol/vol of the low-viscosity fluid through high- and low-permeability cores (Figure 1). Diversion and stimulation were both successful, with permeability increasing from 40 to 3,000 mD in the low-perm core and 70 to 2650 mD in the high-perm core, with multiple wormholes.

The fluid builds viscosity when simple inorganic salts cause its molecules to form long rod-like micelles, which entangle to generate a 3-D structure in solution. Hydrocarbons and mutual solvents affect the shape and structure of the micelles and cause dramatic changes in viscosity. This is important because some corrosion inhibitors — critical in acid treatments to avoid damage to tubulars and the potential for sludging and iron sulfide deposition in sour environments — contain solvents that will affect the fluid’s diversion performance.

This diversion technology has been used in more than 60 treatments in Saudi Arabia at bottomhole temperatures from 180º to 225°F (82º to107ºC), at true vertical depths of 7,000 to 8,000 ft (2,135 to 2,440 m), and in intervals up to 11,000 ft (3,355 m) long.

Acid improves injectivity

In an early field operation, the company’s acid was used to remove drilling mud filter cake and other damage from a horizontal seawater injection well (Chatriwala et al., SPE 93536; and Nasr-El-Din et al., SPE 99651). The well was completed open hole with a length of 1,500 ft (458 m) through a carbonate formation comprising calcite with streaks of dolomite and anhydrite, with average permeability of 700 mD. Injection before the treatment had stabilized to about 17,000 b/d of oil at 1,643 psig with an estimated skin of +15 to 24.

Prior treatments in the field used nitrogen foams for diversion because of the large back pressure these foams create when pumped through the formation matrix. For this well, the design called for the use of the fluid to enhance the foam’s viscosity and stability to achieve improved diversion.

The treatment was pumped through coiled tubing and included stages of inhibited 20% HCl at 40 gal/ft followed every 250 ft (76 m) by a 60- to 70-quality nitrogen foam diversion pill with 3% vol/vol of the viscosity enhancing fluid. A post-flush of 3% vol/vol mutual solvent was used to displace the injected acid into the formation and break any remaining surfactant viscosity. The acid was allowed to soak for two hours.

Injectivity after the treatment was 77,000 b/d at 1,180 psig.

Treatment variations

The polymer-free surfactant was later used to divert matrix acid treatments in 23 injection and producer wells (Nasr-El-Din et al., SPE 102828). After rigorous core testing, treatments were designed for a variety of vertical, deviated and horizontal cased and open-hole wells with intervals from 26 ft (8 m) to more than 10,000 ft (3,050 m). Five of the treatments used coiled tubing to provide accurate acid placement; the remainder were bullheaded. In seven treatments, the fluid was foamed. All 23 wells experienced increases in post-treatment injection/production rates.

The treatments used the Dual-Phase Acid system, in which a 30% diesel phase and a 70% acid internal phase are mixed to form an emulsion. The oil-external layer that surrounds the acid droplets shields the acid from the formation, allowing deeper penetration before the acid spends.

The oil phase would adversely affect the viscosity development in the company’s fluid if they were pumped together, so a spacer that contains no mutual solvent is required between the emulsified acid and diversion stages.

For example, in a vertical power water injector, the bullheaded treatment of a 119-ft (36-m) interval involved pumping a sequence of retarded acid, spacer and foam diversion stages (20% HCl pre-flush, 20% HCl-diesel emulsified acid; 20% HCl spacer; 70% quality foamed acid comprising 20% HCl and 1.5 % vol/vol surfactant at 10 gal/ft). The pre-treatment injection rate was 33,000 bbl/D at 1,450 psi. The post-treatment rate rose to 47,000 bbl/D at 1,400 psi.

Best practices

Analysis of a large number of Saudi Arabian matrix acidizing treatments suggested some best practices to maximize treatment results. (Nasr-El-Din et al., SPE 102468):

• Bullheading is not ideal for acid treatment of well bores longer than 500 ft (152 m) because of the difficulty in achieving leak-off into the lower wellbore sections. If leak-off does not occur, only the upper section is treated and a funnel-shaped washout of the well bore will occur, being most severe, and least desirable, at the casing shoe.

• Increasing rate for small treatments is also not ideal because of the likelihood of dilution and contamination among stages and with formation fluids. In such cases, foamed diversion stages may provide instant maximum viscosity and extend small stage volumes.

• Pumping through coiled tubing is the preferred treatment method with fluid stages sequenced in 250-ft (76-m) intervals with adjustments to pumping and pull-out rates to achieve full coverage.

• For extended-reach injectors that cannot be reached with coiled tubing, treatments utilizing a rig are possible. These wells have openhole sections of 5,000 to 11,000 ft (1,525 to 3,050 m) and are typically treated with sequential stages covering 1,000- to 1,500-ft (305- to 458-m) intervals. Unlike the sequences for the short bullheading and coiled tubing treatments, the acid for each stage is displaced into the formation before pulling up to treat the next interval.