Various types of breaker systems are used for viscosity degradation of fluids in fracture stimulation operations. Achieving improved fracture conductivity is one of the key advantages of using effective breaker systems, but there could be an increased risk of poor proppant placement and premature screenouts resulting from early viscosity reductions as the fluid is exposed to temperature. To resolve this issue, a controlled release of the breaker over a period of time is very desirable.This paper highlights the controlled release of encapsulated oxidizers and chelating types of breakers that are effective in bottomhole static temperatures (BHSTs) up to 275°F. Oxidizers without encapsulation begin to decompose fluids at low to moderate temperature, which can lead to a rapid decrease in gel viscosity before completion of the fracturing operation. Neat chelating breakers can absorb the crosslinker rapidly; thus, little to no crosslinking action would be present, even at moderate temperatures. A newly developed encapsulant makes oxidizers and chelating agents viable for reducing the crosslinked viscosity gradually with temperature.The new encapsulant is a blend of selected polymers that release the active breaker through diffusion. It is possible to optimize the release rate of a breaker by simply adjusting its ratio in a polymer blend. The controlled release of a breaker through an encapsulant was evaluated at 200°F under static conditions. The dynamic rheology of fracturing fluids was also studied as a function of encapsulated breaker concentration in temperatures up to 275°F. The results derived from this investigation are of significant importance to the oilfield industry.

No abstract

High-temperature acidizing operations are challenging because of the highly corrosive nature of acids. Hydrochloric (HCl) acid has an especially high reaction rate, which increases the rate of tubular corrosion. In addition to the type and concentration of acids, factors such as temperature and metallurgy influence the rate of corrosion. To meet increasing demand for deeper stimulation at high temperatures, emulsified acid is predominately used. It contains acid in the internal phase and oil in the external phase, forming an invert emulsion. The outer oil phase creates a barrier for acid, allowing its slow release for reaction with reservoir rock. Emulsified acid systems provide several advantages compared to plain acid. The oil barrier especially helps with preventing corrosion by significantly reducing the contact of acid with the metal tubular. High fluid viscosity helps reduce fluid loss, distributes the acid more uniformly in the formation, and reduces the rate of corrosion. Selection of the proper corrosion inhibitor(s) is one of the most important criteria for high-temperature acidizing. The use of intensifier(s) with the inhibitor enhances the corrosion inhibition significantly. This makes it possible to use a higher concentration of HCl acid at temperatures as high as 350°F, thus enhancing the fluid efficiency. In this work, several corrosion inhibitors and intensifiers are studied at varied acid strengths and temperature conditions. To achieve good corrosion control, a synergy is required between corrosion inhibitors and corrosion inhibitor intensifiers. At the same time, they should not negatively impact the emulsion stability. A new emulsified acid system was developed using HCl acid strength up to 28%. High corrosion control imparted by inhibitor-intensifier synergy coupled with the slow reaction rate of emulsified acid makes this blend unsurpassed for use in extreme high-temperature conditions up to 350°F. This emulsified acid system has the potential for use in the Khuff formation of Saudi Arabia with the addition of a H2S scavenger. Testing with a commercially available scavenger exhibited good compatibility with the blend.

Because the world demand for energy is expected to continue growing, exploration is turning to deeper and high-temperature reservoirs. Such reservoirs include fields with high bottomhole static temperatures (BHSTs), such as the Ursa (250°F) and Thunder Horse (280°F) in Gulf of Mexico (GOM). Acid stimulation of such reservoirs at high temperature is a challenging task. Emulsified acid systems are expected to perform better in reservoirs with BHSTs ranging from 275 to 375°F compared to nonretarded acids and gelled acid systems. However, fluid stability and the inhibition of corrosion are major challenges to overcome for successful implementation of this technology. Emulsion instability and the corrosion rate are interrelated, and both increase with higher temperature. Also, fluid stability decreases as a result of corrosion of the metal surfaces. At the same time, an excessive addition of corrosion inhibitor destabilizes the fluid system. Hence, the proper selection and balance between the corrosion inhibitor and emulsifiers are required. Three different types of corrosion inhibitors were evaluated, and an emulsified system was designed with proper optimization of various ingredients, including corrosion inhibitor, an intensifier, and a cationic emulsifier. The system was tested for stability and corrosion loss with static corrosion test using P-110 coupons. After reviewing the literature, it is believed that this emulsified system is the only one to pass static corrosion tests at 275°F for 4 hr and remain stable at 300°F for 2 hr with 28% acid strength. This enables the acid stimulation of carbonate reservoirs having BHSTs up to 300°F while reducing the corrosion rate. As per the study, the effect of the intensifier was different to that found in plain acid, suggesting possible interactions of the additives with the emulsifier. Because fluid stability and the rate of corrosion are interrelated, they should be evaluated together, especially for designing emulsified acid systems for stimulation of very high-temperature carbonate reservoirs. IntroductionAcid is predominantly used to remove damage near the wellbore and to stimulate the well, which in turn improves the rate of hydrocarbon production (Sayed et al. 2012). In a carbonate reservoir, acid is mainly used to create linear flow for acid fracturing and to create wormholes. An emulsified acid is mainly used for matrix acidizing because it lowers the diffusion rate by two orders of magnitude. The first reduces the acid transfer rate, caused by an increase in the viscosity of the fluid. The second disperses the acid phase into the oil, which results in a slow reaction when it contacts the carbonate reservoir (Buijse and Vandolmen 1998). When using emulsified acid, the inhibitor components adsorb to the metal surface and can undergo polymeric-type film forming on the metal surface because of reactions initiated by the hydrogen radicals (Navarrete et al. 2000). The corrosion inhibitor system is selected based on the metallurgy, acid type, acid concentration, tempera...

No abstract