Designing an acid-fracturing treatment is similar to designing a fracturing treatment with a propping agent. Williams, et al. presents a thorough explanation of the fundamentals concerning acid fracturing.
The main difference between acid fracturing and proppant fracturing is the way fracture conductivity is created. In proppant fracturing, a propping agent is used to prop open the fracture after the treatment is completed. In acid fracturing, acid is used to “etch” channels in the rock that comprise the walls of the fracture. Thus, the rock has to be partially soluble in acid so that channels can be etched in the fracture walls. As such, the application of acid fracturing is confined to carbonate reservoirs and should never be used to stimulate sandstone, shale, or coal-seam reservoirs. Long etched fractures are difficult to obtain, because of high leakoff and rapid acid reaction with the formation.
Acid-fracturing candidate selection
In general, acid fracturing is best applied in shallow, low-temperature carbonate reservoirs. The best candidates are shallow, in which the reservoir temperature is less than 200°F and the maximum effective stress on the fracture will be less than 5,000 psi. Low temperature reduces the reaction rate between the acid and the formation, which allows the acid to penetrate deeper into the fracture before becoming spent. Because limestone reservoirs are ductile, a low effective stress on the fracture is required to maintain adequate fracture conductivity over the life of the well. In deep limestone reservoirs, in which problems exist with high bottomhole temperature and high effective stress on the fracture, water-based fluids with propping agents can be used successfully to stimulate the formation. In deep dolomite reservoirs that are less ductile than limestones, acid fracturing may work satisfactorily; however, proppant fracturing with water-based fluids may work also.
Acid-fracture fluids with propping agents are not recommended. When the acid reacts with the carbonate formation, fines are always released. If a propping agent is used with acid, the fines plug up the propping agent, resulting in very low fracture conductivity. When deciding to stimulate many carbonate reservoirs, the costs and benefits of an acid-fracture treatment should be compared with a treatment that uses water-based fluids carrying a propping agent. It should not be assumed that acid fracturing works best, because the formation is a carbonate.
There could be a few applications in which acid fracturing could be the preferred treatment in a deep, high-temperature carbonate reservoir. For example, if a high-permeability carbonate reservoir is damaged as a result of drilling operations or non-Darcy flow effects, then a stimulation treatment can be applied to improve the productivity index. In such cases, injecting acid at fracturing rates can improve the permeability near the wellbore, which will reduce the pressure drop caused by skin and/or non-Darcy flow.
In other cases, especially in deep dolomites that contain an abundance of natural fractures, acid fracturing may work better than proppant fracturing. In such reservoirs, it is common that multiple fractures are opened when pumping begins. With multiple fractures, no single fracture ever gains enough width to accept large concentrations of propping agent. Near-wellbore screenouts often occur as the proppant concentration is increased to more than 2 to 3 ppg. In such cases, acid fracturing may work better than proppant fracturing.
Other considerations when selecting acid-fracturing candidates are cost and safety. In deep, hot reservoirs, the cost of an acid-fracturing treatment can exceed the costs of a proppant-fracture treatment. In hot reservoirs, expensive chemicals are required to inhibit the acid-reaction rate with the steel tubular goods and to retard the reaction rate with the formation. Acid must be handled with extreme care in the field. When pumping large volumes of high-strength acid at high injection rates and at high pressures, safety should be the top concern of everyone in the field.
Acid fluids used in fracturing
The most commonly used fluid in acid fracturing is 15% hydrochloric acid (HCl). To obtain more acid penetration and more etching, 28% HCl is sometimes used as the primary acid fluid. On occasion, formic acid (HCOOH) or acetic acid (CH3COOH) is used because these acids are easier to inhibit under high-temperature conditions. However, acetic and formic acid cost more than HCl. Hydrofluoric acid (HF) should never be used during an acid fracturing treatment in a carbonate reservoir.
Typically, a gelled water or crosslinked gel fluid is used as the pad fluid to fill the wellbore and break down the formation. The water-based pad is then pumped to create the desired fracture height, width, and length for the hydraulic fracture. Once the desired values of created fracture dimensions are achieved, the acid is pumped and fingers down the fracture to etch the walls of the fracture to create fracture conductivity. The acid is normally gelled, crosslinked, or emulsified to maintain fracture width and minimize fluid leakoff. Because the acid is reactive with the formation, fluid loss is a primary consideration in the fluid design. Large amounts of fluid-loss additives are generally added to the acid fluid to minimize fluid leakoff. Fluid-loss control is most important in high permeability and/or naturally fractured carbonate formations; thus, long etched fractures are difficult to obtain.
Acid-fracture design considerations
In addition to Ref. 1, two papers provide the technology commonly used today to design acid fracture treatments. There are several unique considerations to be understood when designing acid fracture treatments. Of primary concern is acid-penetration distance down the fracture. The pad fluid is used to create the desired fracture dimensions. Then the acid is pumped down the fracture to etch the fracture walls, which creates fracture conductivity. When the acid contacts the walls of the fracture, the reaction between the acid and the carbonate is almost instantaneous, especially if the temperature of the acid is 200°F or greater. As such, the treatment must be designed to create a wide fracture, with minimal leakoff, with viscous fluids. Fig. 1 illustrates why the design engineer should be striving to create a wide fracture. If a wide fracture is created with a viscous acid and minimal fluid loss, then a boundary layer of spent acid products will reduce the rate at which the live acid contacts the formation at the walls of the fracture. However, as the flow in the fracture becomes more turbulent and less laminar, the live acid will contact the walls of the fracture more easily, and the acid will not penetrate very far into the fracture before becoming spent.
Fig. 1—Acid-flow behavior in the fracture.
Factors such as fracture width, injection rate, acid viscosity, and reservoir temperature all affect acid penetration. Figs. 2 and 3 illustrate how fracture width and formation temperature affect acid penetration in the fracture, respectively. In Fig. 2, as the fracture width increases, the distance that unspent acid will reach in the fracture also increases. The distance increases because, in a wide fracture, there is less turbulence. This results in less mixing as the live acid moves down the fracture; therefore, the viscous and leakoff properties of the fracture fluid should be controlled to maximize fracture width. Fig 3 contains information concerning the effects of:
- Reservoir temperature
- Acid strength
- Formation lithology
It is clear that the use of higher-strength acid increases the penetration distance in the fracture before the acid spending. Also, as temperature increases, the acid penetration distance decreases. As the temperature increases, the reaction rates between the acid and the formation increase substantially. In fact, the reaction rate doubles every time the temperature increases 18°F. Fig. 3 also shows that dolomite is less reactive with HCl than limestone; therefore, acid fracturing may work slightly better in reservoirs that are more highly dolomitized.
Fig. 2—Effect of fracture width on acid-penetration distance.
Fig. 3—Effect of temperature, lithology, and acid concentration on acid-penetration distance.
The problem with acid fracturing that prevents its successful application in many reservoirs involves sustaining fracture conductivity over time. When the acid etches the fracture walls, the resulting fracture conductivity can be several orders of magnitude more conductive than similar treatments that use water-based fluids and propping agents. Fig. 4 presents data concerning fracture conductivity as a function of effective stress on the fracture and rock embedment strength. The embedment strength is easily measured and can be correlated with the compressive strength of the rock. As the compressive strength increases, the rock embedment strength increases. The data in Fig. 4 show that, when the embedment strength is less than 100,000 psi, large fracture conductivities, on the order of 10 to 50,000 md-ft, can be created during an acid-fracture treatment, as long as the effective stress on the fracture is 1,000 psi or less. However, once the effective stress on the fracture exceeds 5,000 psi, the fracture conductivity decreases substantially. As such, in deep limestone reservoirs in which the maximum effective stress on the fracture is much greater than 5,000 psi, an acid fracture will not stay open as the well is produced. In such cases, water-based fluids carrying propping agents should be considered as an alternative to acid fracturing.
Fig. 4—Fracture conductivity in a carbonate reservoir as a function of effective stress on the fracture and embedment strength.
- ↑ 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 Williams, B.B., Gidley, J.L., and Schechter, R.S. 1979. Acidizing Fundamentals, 55. New York: SPE/AIME.
- ↑ Kozik, H.G. and Holditch, S.A. 1981. A Case History for Massive Hydraulic Fracturing the Cotton Valley Lime Matrix, Fallon and Personville Fields. SPE Journal of Petroleum Technology 33 (2): 229-244. 00007911. http://dx.doi.org/10.2118/7911-PA.
- ↑ Pathak, P., Fidra, Y., Avida, H. et al. 2004. The Arun Gas Field in Indonesia: Resource Management of a Mature Field. Presented at the SPE Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur, Malaysia, 29-30 March. SPE-87042-MS. http://dx.doi.org/10.2118/87042-MS.
- ↑ Roodhart, L.P., Kamphuis, H., and Davies, D.R. 1993. Improved Acid Fracturing Treatment Designs Based on In-Situ Temperature Calculations. Presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, 28-30 June. SPE-26185-MS. http://dx.doi.org/10.2118/26185-MS.
- ↑ Settari, A. 1993. Modeling of Acid-Fracturing Treatments. SPE Prod & Fac 8 (1): 30-38. SPE-21870-PA. http://dx.doi.org/10.2118/21870-PA.