For most of the 20th Century, acidizing oil and gas wells to optimize production was a notoriously fickle proposition, with unacceptably erratic results in primary and remedial applications, alike.

The first comprehensive studies of matrix acidizing in sandstone were published nearly 30 years ago, and results of research into acid-stimulation of carbonate media more than two decades ago. Yet, the success rates of acid-stimulation treatments in some sandstone formations were persistently unpredictable—as low as 30 percent in some instances—well into the 1990s. Similarly, production increases achieved in carbonate reservoirs often were difficult to sustain. In addition, because acidizing treatments generally were viewed as relatively low-tech procedures, candidate selection and treatment design didn't always receive adequate consideration, compounding both the frequency and magnitude of failures.

Importance of mineralogy
The reliability and effectiveness of acid-stimulation technology began to change for the better in the mid-1990s, driven by improved understanding of the complex chemical and physical reactions of minerals with acidizing fluids. Findings in the lab, including both fundamental and applied research, and results of field work all have confirmed that—whether in a sandstone or carbonate reservoir, a mature field, deepwater environment, or high-temperature reservoir—reliably achieving long-term production increases from acidizing requires a thorough understanding of the formation mineralogy.

Essentially, the producibility of a given well may be impaired either by the natural characteristics of the reservoir rock and fluids or by damage resulting from drilling, completion or production operations. Acid stimulation is not a solution to poor reservoir quality; however, a full range of acid treatments is available to help boost production. Matrix acidizing treatments can improve connectivity with the near wellbore region. Or, we can achieve deeper penetration of live acid which, in carbonate formations, can result in negative skins as significant as -3 to -5. Finally, fracture acidizing treatments can be designed that penetrate deep into lower permeability rock.

The design of any acid-stimulation treatment should begin with a thorough evaluation of the characteristics of the targeted formation. The composition, structure, permeability, porosity, and strength of the rock must be determined, along with formation temperature and pressure and the properties of reservoir fluids.

Carbonate Reservoirs
The heterogeneous nature of many carbonate formations means extreme variability of rock properties—even different types of rock—can exist in a single interval, complicating efforts to evaluate mineralogy and design acidizing treatments that can achieve durable production increases. Each mineral reacts differently when it comes in contact with a given acid, and reaction rates in specific applications vary depending upon such variables as acid concentration, treatment temperature and injection pressures.

Hydrochloric acid (HCl) is the most commonly used acid in carbonate acid-stimulation treatments. A typical acidizing treatment consists of a base acid solution of 15% to 28% HCl with required additives. Treatment volumes for matrix acidizing range from 25 gallons to 200 gallons per foot (gal/ft) of targeted interval, pumped at the highest rate possible without fracturing the formation. Treatment volumes for fracture acidizing range from 100 gal/ft to 500 gal/ft pumped at fracturing rates along with an acid-diversion technique to ensure effective zonal coverage. Two additives—a corrosion inhibitor and a surfactant—should be included in every carbonate acidizing treatment.

Wormholing—a preferred objective in many carbonate matrix acidizing jobs—can enable large permeability increases by forming highly conductive channels in the treated formation. The process of wormholing depends mainly on three parameters: surface reaction rate, acid diffusion rate, and acid injection rate. For any given set of reservoir conditions, a critical acid-injection velocity exists; injection rates below critical velocity results in compact dissolution (in which acid spends on the face of the formation), while injection rates greater than critical velocity will result in wormholing.

Sandstone Reservoirs
Sandstone acidizing presents a somewhat different set of challenges. Deleterious side-effects of acidizing in sandstone formations—such as clay swelling, fines migration, gel formation or particle precipitation—may be minimized or avoided altogether by designing hydrofluoric acid (HF) stimulation treatments with compatible chemical and physical properties. Smectite and mixed illite-smectite clays are among the most water-sensitive clays, while illites and chlorites are less prone to ion exchange. Also of concern when acidizing sandstone is the presence of illite, potassium feldspars, sodium feldspars, and zeolites, because these compounds can contribute to the formation of matrix-blocking precipitates.

Clay swelling can occur when acidizing fluids exchange ions with formation minerals, choking off production by obstructing the matrix, unless care is taken to sustain the salinity of the injected fluid after ion exchange. Many water-sensitive clays contain potassium chloride (KCl) and sodium chloride (NaCl) ions that can be exchanged with ions in injected fluids to lower the salinity of the fluid. For example, when a 3% ammonium chloride (NH₄Cl) acidizing fluid flows across a typical ion-exchanging clay, the fluid becomes 3.3% NaCl, a brine too weak to prevent clay swelling, thus requiring a 5% NH₄Cl or equivalent solution.

Sandstone 2000^SM Service
Since its introduction, Sandstone 2000 service has significantly improved the reliability of acidizing sandstone intervals. At last report, about 90 percent of wells treated using the service have responded with two- to four-fold production increases.

The Sandstone 2000 acidizing system achieves such results reliably by imposing a rigorous analytical framework over the process of determining the most effective conditioning system, proper HF/HCl base-acid blend, correct fluid volume, and optimum pumping rate for a given application. Knowledge of the many mineralogically based obstacles is combined with the analytical procedures and a new generation of acidizing fluids and additives to create stimulation programs that fit the specific characteristics of sandstone formations.

The foundation of Sandstone 2000 service is a series of tailored acidizing systems that can be adapted easily to help speed and simplify the acidizing-fluid design process:

• Sandstone Completion™ acid, the safest Sandstone 2000 acid system for stimulating most sandstone formations when mineralogy and nature of damage are uncertain. The system provides maximum HF dissolving power without secondary precipitation.
• Fines Control™ acid, a patented retarded-reactivity, acidizing process that penetrates to remove deep damage caused by fines and swelling clays.
• K-Spar™ acid, which helps increase production in formations with high potassium feldspar and illite content by reducing fines migration and near-wellbore damage over a wide range of temperatures.
• Volcanic™ acid, a new organic-HF acid system that can be used to replace HF fluids that produce severe secondary precipitation; protects formations sensitive to HCl, is compatible with HCl-sensitive minerals such as chlorite or zeolite, can be used in high-temperature reservoirs, and helps avoid sludging of crude.
• Silica Scale™ acid - designed specially to remove silica scale from geothermal wells.

The integrated Carbonate 20/20 service focuses on identifying the rock properties of the zone to be stimulated with either a matrix or a fracture treatment, based upon formation-evaluation data such as well logs, core evaluation, and drillstem tests.

To help simplify the acidizing-fluid selection process, Carbonate 20/20 provides a series of versatile, fit-for-purpose acid systems designed to deal with most conditions encountered in carbonate formations around the world:

• Carbonate Completion Acid™ (CCA), a totally soluble system applicable to most well conditions.
• Carbonate Stimulation Acid™ (CSA), a gelled system that minimizes fluid loss and slows reaction rates.
• Fines Recovery Acid™ (FRA) for low-solubility formations, which also aids fluid recovery.
• Carbonate Emulsion Acid™ (CEA), an ultra-retarded formulation that enhances acid penetration and encourages efficient formation of wormholes.
• Hot Rock Acid™ (HRA), based upon a formic acid-acetic acid blend that is considered the acid system of choice when corrosion or formation compatibility problems preclude the use of HCl.
• Zonal Coverage Acid™, a viscous gelled acid with a controlled crosslinker for effective diversion

STIM2001™ software package
Results of formation evaluations using both Carbonate 20/20 and Sandstone 2000 services provide input data for the STIM2001 matrix simulator, a solutions-oriented software package that can effectively guide the selection of potential candidates for many types of stimulation, including acidizing, fracturing and reperforating.

Developed through collaboration by Shell International and Halliburton, STIM2001 software can evaluate the reasons for lost production in one well or a series of wells, and then rank the wells studied according to the best value for each stimulation-dollar spent. The system can determine the skin value of a given well (or wells), the damage mechanisms in play, applicable treatments and/or remedies, and the ideal production rate. It can guide fluid selection, recommend fluid diversion programs, simulate fluid flows in both sandstone and carbonates (including wormholing), and automatically generate reports based upon single-entry data.

Halliburton's new carbonate and sandstone acid-stimulation processes and the STIM2001 simulator are examples of the new, highly engineered products and services that are helping bring new levels of precision and cost-effectiveness to matrix acidizing. Many new base acids and additives are now available that can be combined in hundreds of formulations to fit the specific characteristics of intervals to be treated. The company stresses that obtaining optimum results from any of the various formulations and procedures depends on thoroughly understanding formation mineralogy.