To enhance the efficiency of acid stimulation treatments in high-temperature carbonate reservoirs, the industry requires a superior retarded acid system that inherently displays high thermal stability, controlled reaction rate, and acceptable corrosion losses. One of the earliest means of acid retardation was through the addition of polymer gelling agents; however, these sytems commonly lead to formation damage. Alternatively, a commonly used approach to slow down the acid/rock reaction rate is through the use of acid-in-oil emulsions (i.e., emulsified acids). The viscous nature of these fluids, however, leads to unfavorably high friction pressures during the pumping process. Additionally, the thermal stability of emulsified acids is questionable at temperatures exceeding 300°F. Herein, we introduce a novel engineered acid system for stimulation of high-temperature carbonate reservoirs. The proposed technology reduces the free water in the system and consequently prevents full dissociation of the acid. Reducing the free water in the acid system was successfully achieved by engineering the acid formulation in the presence of another organic compound that is readily soluble in the acid. A series of benchtop carbonate dissolution experiments were performed under static conditions at room temperature to identify the optimal engineered formulation needed to achieve the desired retardation effect. The retardation behavior of this system was further supported by reaction rate studies, coreflood measurements and corrosion loss data. The proposed acid system was evaluated at temperatures and pore pressures up to 350°F and 3000 psi, respectively. Experimental results confirmed that the engineered acid system requires only 0.28 PV to achieve a breakthrough (12 inch core), which represents a significant reduction as compared to some reported emulsified acid systems. Importantly, the fluid formulation was systematically fine-tuned in order to impart the desired fluid-property characteristics: low-viscosity (est. 4 cp), high dissolving power (4.16 lb acid/gal), fast wormhole propagation rate, low corrosion loss (<0.05 lb/ft2, 275°F) and high thermal stability (>300°F). The acid system can be readily mixed on-the-fly with existing equipment. This is a desirable feature particularly when it comes to offshore operations as no special preparation methods are required. It is the opinion of the authors that this novel acid system provides the industry with a suitable fluid alternative that may offer the potential to enhance oil and gas production in carbonate reservoirs. The fluid is stable at high temperatures and may have the potential to be used in a broad range of stimulation applications. Importantly, this low-viscosity retarded acid system presents the industry with a novel acid alternative where acid retardation by polymer addition or emulsification in diesel is no longer required.

A stimuli-responsive, sub-100 nm nanoparticle (NP) platform with a hydrolyzable ester side chain for in situ generation of surfactants is demonstrated. The NPs were synthesized via copolymerization of vinyl-laurate and vinyl-acetate [p-(VL-co-VA), 3:1 molar ratio] and stabilized with a protective poly(ethylene-glycol) shell. The NPs are ∼55 nm in diameter with a zeta potential of −54 mV. Hydrolysis kinetics in an accelerated, base-catalyzed reaction show release of about 11 and 30% of the available surfactant at 25 and 80 °C, respectively. The corresponding values in seawater are 22 and 76%. The efficiency of the released surfactant in reducing the interfacial tension, altering wettability, and stabilizing oil−water emulsion was investigated through contact angle measurements and laser confocal scanning microscopy and benchmarked to sodium laurate, a commercially available surfactant. All these measurements demonstrate both the efficacy of the NP system for surfactant delivery and the ability of the released surfactant to alter wettability and stabilize an oil−water emulsion.

A targeted and controlled delivery of molecular surfactants at oil–water interfaces using the directed assembly of nanoparticles, NPs, is reported. The mechanism of NP assembly at the interface and the release of molecular surfactants is followed by laser scanning confocal microscopy and surface force spectroscopy. The assembly of positively charged polystyrene NPs at the oil–water interface was facilitated by the introduction of carboxylic acid groups in the oil phase (e.g., by adding 1 wt % stearic acid to hexadecane to produce a model oil). The presence of positively charged NPs consistently lowers the stiffness of the water–oil interface. The effect is lessened, when the NPs are present in a solution of NaCl or deionized water at pH 2, consistent with a less dense monolayer of NPs at the interface in the last two systems. In addition, the NPs reduce the interfacial adhesion (i.e., the “stickiness” of the interface or, put differently, the pull-off force experienced by the atomic force microscopy (AFM) tip during retraction). After the assembly, the NPs can release a previously loaded cargo of surfactant molecules, which then facilitate the formation of a much finer oil–water emulsion. As a proof of concept, we demonstrate the release of octadecyl amine, ODA, that has been incorporated into the NPs prior to the assembly. The release of ODA causes the NPs to detach from the interface altering the interfacial properties and leads to finer oil droplets. This approach can be exploited in applications in several fields ranging from pharmaceutical and cosmetics to hydrocarbon recovery and oil-spill remediation, where a targeted and controlled release of surfactants is wanted.

Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. The objective of this paper is to introduce an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant, or emulsification by diesel. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid "HCl") with an organic compound that is highly soluble in the acid. It is based on reducing the free water in the system and, consequently, restricting the ionic separation of the proton from the acid. This results in a retardation behavior that is necessary to maintain a controlled reaction for the system used. The retardation behavior testing includes dissolution experiments, compatibility testing (using X-Ray Diffraction "XRD" and inductively coupled plasma "ICP"), coreflood study (at rates of 2 and 5 cm3/min at 300°F and 3000 psi) and corrosion rate testing (conducted at 300°F). Finally, a reaction kinetics analysis (at disc rotational speeds of 250 rpm, 500 rpm, 700 rpm and 1500 rpm) was performed to evaluate the retarded acid performance. The new acid system showed 4 times reduction in the core weight loss due to dissolution in acid compared to plain 15wt% HCl. XRD and Computed Tomography (CT) scans illustrated the acid compatibility with dolomite by forming no precipitation that is attributed to the organic compound used in the system. The proposed acid can create a dominant wormhole pattern requiring only 0.53 Pore Volume (PV) of acid to achieve breakthrough in the Indiana limestone core. It is important to note that emulsified acids require 0.8 PV of fluid compared to 1.4 PV for 15 wt.% HCl acid package. The proposed system was determined to have negligible corrosion rate of 0.002 lb/ft2 after 4 hours exposure at 300°F. Reaction kinetics study proved the delayed acid reaction with calcite by an order of magnitude compared to 32 wt.% HCl. Conventional emulsified acids require expensive energization, through nitrogen (N2) or carbon dioxide (CO2), to overcome frictional losses and meet high injection rates requirement for fracturing and stimulation in deep formations. This novel system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and will offer a cost-effective solution to cover a wide range of applications in matrix or fracturing applications, and high-temperature conditions that require a thermally-stable acid system.

Acidizing treatments are the primary technique to enhance production of carbonate formations. Analysis of historical matrix treatment flowback, and laboratory assessment provide insights on the reservoir response to the acid recipe, and thus, positively enhance the selection of fluid recipes. The objective of this paper is to share an evaluation method to assess the effectiveness of an HCl-based acid recipe through experimental studies and flowback analysis. Gelled, emulsified, and straight hydrochloric acids (HCl) were used to demonstrate the method. Inductively-Coupled Plasma (ICP) was utilized to characterize the liquid flowback samples. HP/HT filter press test was conducted using oil-based and water-based drilling fluids at 150°F to examine the integrity of filter cake and the removal means. Compatibility between crude oil sample and the acid recipe was conducted under reservoir conditions using HP/HT aging cell. ICP analysis was used to correlate the calcium concentration to the magnitude of the rock dissolved by the selected acid recipe. Filter cake removal using water-based and oil-based drilling fluids showed an effectiveness of 90% and 94.8%, respectively. Clear separation was observed between the oil sample and the acid recipe for the slightly gelled and fresh acid formulas. Calcium and magnesium concentration profile in flowback samples indicated the time when spent acid was recovered. Reduction in calcium concentration suggested calcium-based precipitation occurrence. The pH profile, in combination with density measurements, can assess the optimum shut-in and flowback time for full acid spending and retrieval. Steady pH profile at later times of the flowback revealed the presence of carbonic acid. The iron profile analysis was critical to determine the presence of corrosion products and the origin of iron ions in combination with chromium and manganese ions. Dilution factor of sodium and potassium ion concentration was used to determine water cut in acid flowback samples.