Using acids to improve well performance by removing or bypassing damage has been a common practice for a long time—nearly as long as the existence of the oil industry itself. In 1895, the Ohio Oil Company used hydrochloric acid [HCl] to treat wells in a limestone formation. Production from these wells increased by several fold—and unfortunately so did casing corrosion. As a result, acidizing to stimulate production disappeared for about 30 years.
But acid treatments for sandstones required a different approach. HCl does not react easily with minerals that reduce sandstone permeability, but hydrofluoric acid [HF] does. Early attempts using HF in sandstones failed because of plugging from secondary reactions. This problem was overcome in 1940 with a combined HF-HCl treatment. The HF in the acid combination dissolves mineral deposits in sandstones that hinder production, while the HCl controls precipitates. These acidizing techniques have evolved over subsequent years, but the goal has not changed—create or restore production pathways close to the wellbore in a new or existing well. Well acidizing, more commonly referred to as matrix acidizing, is one of two intervention methods used to restore flow in an oil or gas formation. The other route—hydraulic or acid fracturing—creates fractures to allow relatively distant accumulations of oil and gas to flow to the wellbore. Acidizing works on the formation near the wellbore to bypass damage or to dissolve it. The choice of fracturing or acidizing to stimulate production depends on a multiplicity of factors that include formation geology, production history and intervention goals. Well-intervention techniques such as matrix acidizing play an important role in helping operators produce all they can from their fields. Pressure on acidizing experts to develop new treating formulations and techniques is coming from several directions. One important need is extension of acidizing to high-temperature environments. Use of conventional mineral acids such as HCl and HF at higher temperatures— above 93°C [200°F]—leads to reaction rates that are too rapid. These fast rates cause the acid to be consumed too early, reducing its effective - ness, and may cause other problems.
Acidizing in limestone reservoirs experienced a rebirth in 1931 with the discovery that arsenic inhibited the corrosive action of HCl on wellbore tubulars.1
Acidizing in Limestone: 2HCl + CaCO3
CaCl2 + CO2 + H2O
Carbonate core Acidizing in Dolomite: 4HCl + CaMg(CO3)2 MgCl2 + CaCl2 + 2CO2 + 2H2O
> Carbonate acidizing. Limestone and dolomite cores treated with HCl develop macroscopic channels called wormholes (red). These channels are the result of the reaction of HCl with the calcium and magnesium carbonates in the cores to form water-soluble chloride salts.
Furthermore, as regulations tighten, there is a greater need within the industry for fluids with reduced environmental and safety risks.2 Conventional mineral acids such as HCl and HF are difficult to handle safely, corrosive to well bore tubulars and completion equipment, and must be neutralized when returned to the surface. Additionally, as the bottomhole temper ature increases, corrosion-inhibitor costs rise rapidly because of the high concentrations required— particularly with some exotic tubulars currently used in well completions. Finally, conventional sandstone acidizing techniques typically involve many fluid treatment steps, increasing the potential for error.
This article will focus on matrix acidizing and discuss how this technology has been extended to higher-temperature environments through development of new fluids and techniques. Case studies from Africa, the USA, the Middle East and Asia demonstrate how these techniques are being successfully employed around the world.
Different Formations— Different Acidizing Chemistry
The first consideration in matrix acidizing any particular well—high-temperature or not—is formation lithology. Carbonate reservoirs are mostly acid soluble, and acid treatment creates highly branched conductive pathways called wormholes that can bypass damage. Conversely, in sandstone reservoirs, only a small fraction of the rock is acid soluble. The goal of acid treatment in sandstones is to dissolve various minerals in the pores to restore or enhance
permeability. The chemistry and physics for treating both types of reservoir have been extensively studied and are well-understood. Carbonate reservoirs—principally limestone and dolomite—react easily with HCl in moderate-temperature environments to form wormholes (above). The reaction rate is limited primarily by the diffusion of HCl to the formation surface. Wormholes in carbonate reservoirs increase production not by removing damage, but by dissolving the rock and creating paths through it.
The formation of wormholes in carbonates is explained by the manner in which acidizing affects the rock. Larger pores receive more acid, which increases both their length and volume. Eventually, this extends into a macroscopic channel, or wormhole, that tends to receive more acid than the surrounding pores while it propagates through the rock. The shape and development of wormholes depend on acid type as well as its strength, pump rate and temper - ature—plus the lithology of the carbonate. Under the right conditions, worm holes can grow
1. Crowe C, Masmonteil J, Touboul E and Thomas R: “Trends in Matrix Acidizing,” Oilfield Review4, no. 4 (October 1992): 24−40.
2. Hill DG, Dismuke K, Shepherd W, Witt I, Romijn H, Frenier W and Parris M: “Development Practices and Achievements for Reducing the Risk of Oilfield Chemicals,” paper SPE 80593, presented at the SPE/EPA/DOE Exploration and Production Environmental Conference, San Antonio, Texas, March 10−12, 2003.
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