Barium Sulfate, barite is commonly introduced into the oil and gas wells during drilling when used as weighting agent but it also can be formed at wellbore tubular during production as scale. After drilling, the barite in the wellbore and in the filter cake can cause erosion of well tubing during production, and should be removed. Dissolving and removing barite is a challenge because of its low solubility in water and hydrochloric acid. It can be removed by mechanical approaches, which includes scarping and jetting with foamed or viscose fluid to carry the heavy barite solid. In this study, a new barite dissolving formulation was evaluated for its dissolving power and as barite and barite-based drilling fluid mud-cake removals. The dissolution rate at dynamic condition and in the presence of calcium carbonate was also evaluated for more than 72 hours reaction time. The study-testing scheme aimed to identify: the optimum solid to liquid ratio for maximum solubility, optimum soaking time at downhole temperature and solubility of mud-cake at optimum ratio and soaking time. Careflooding was also carried out to determine the rock-dissolver interaction. The interaction between stimulation chemicals and formation rock is essential in order to understand these chemicals efficiency. The study results showed the average barite and mud-cake solubility was 276 and 167 lb/1000 gal in 24 hours at 270°F, respectively. 60% of the dissolved barite occurred in the first 5 hours soaking time. In the presence of calcium carbonate, the dissolution rate was dropped by almost 40%. The reduction started to be significant after 8 hours of soaking. Multi-stages treatments using 10 gallons of the dissolver per 1.0 lb of barite with 5 to 8 hours soaking time are expected to be more effective than one-stage treatment with a long soaking time.

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Hydrochloric (HCl) crosslinked gelled acid systems have been extensively used in acid fracturing and matrix acidizing to help achieve acid diversion during stimulation treatments. These systems also help control fluids leakoff and help retard the acid reaction to allow deeper acid penetration. Currently, many in-situ crosslinked gelled acid systems generally consist of polymers, an iron crosslinker, and a breaker agent, in addition to other additives. This paper discusses an alternative crosslinker that provides effective diversion with minimal residuals at temperatures up to 275°F. A non-iron-based crosslinker has been developed for in-situ high-strength gelled acid systems that vary between 5 to 20 wt% HCl acid. The coreflooding experiments were effectively conducted for permeability ranges of up to 70 md. This system showed a stable fluid at downhole conditions, initially building viscosity between a pH range of 1.5 to 3.0. Then, as acid continues to further react with calcium carbonate and the pH becomes higher than 3, the crosslinked fluid begins to break down and the fluid viscosity decreases. Several experiments were conducted to assess the performance of this novel system. Additionally, corrosion tests were performed to evaluate the treatment fluid corrosion rate at a temperature of 275°F. The testing results show that the evaluated gelled acid system is stable at temperatures up to 275°F. The system profile as a function of pH showed the ability to provide diversion during different stimulation treatments. Additionally, the coreflood results showed that the new gelled acid is capable of forming wormholes without any significant associated formation damage caused by the gel. The effect of corrosion inhibitors on this system at 300°F, along with other additives, was also investigated.

Calcium sulfate inorganic scale deposition is a major challenge that can block tubulars and hinder flow assurance during hydrocarbon production and water injection operations. This scale can form when high sulfate water gets in contact with water containing high content of calcium ions. Dissolving calcium sulfate is problematic due to its low solubility in water and common inorganic acids. Many scale dissolvers exist in the industry; however, the dissolving performance varies significantly when applied to calcium sulfate field samples. The main objective of this study is to evaluate the efficacy of three commercial calcium sulfate dissolvers for possible applications in the field. Field scale samples were characterized using X-ray diffraction and scanning electron microscopy with energy dispersive spectroscopy (XRD/SEM-EDS) to determine its composition. The HPHT aging cell was used to conduct the experiments at a temperature ranging from 77 to 300°F to evaluate the performance of several calcium sulfate dissolvers. The testing involved static dissolution tests to identify the optimal dissolver, scale dissolver to inorganic scale ratio, temperature influence, surface area influence, and the appropriate soaking time. Compatibility and thermal stability tests were also explored to avoid formation damage issues during the removal treatment. Additionally, corrosion tests were performed using low carbon steel metal coupons to assess the dissolver corrosivity at 200 and 300°F. The scale dissolvers compatibility and thermal stability were presented up to 300°F. The performance of the dissolvers generally increased as the temperature and soaking time increased. The scale dissolver chemistries were tested at high pH conditions and most of the tests exhibited a low corrosion rate of < 0.05 lb/ft2 with no significant pitting at 200°F or 300°F for the duration of the soaking time. One of the tested scale dissolvers failed the corrosion test at 300°F and two dissolvers thermally degraded when exposed to high temperature. This work is derived from testing actual inorganic scale field samples and shares the difficulty of dissolving such scale samples. The work also systematically compares three commercial scale dissolvers to resolve this issue.

There exists a need for high temperature fracturing fluids as we expand exploration into deeper, lower permeability, and hotter formations. Fracturing fluid stability depends on two main bonds: the crosslinker to polymer bond and the monomer to monomer bond. To preserve the crosslinker to polymer bond, a proper crosslinker with a suitable delay additive is typically utilized. On the other hand, the monomer to monomer bond is challenging to protect since it’s susceptible to a variety of factors with the main culprit being oxygen radical attacks. Consequently, the most common high temperature stabilizers used are oxygen scavengers such as sodium thiosulfate or sodium sulfite. Unfortunately, both additives create their own issues. Sodium thiosulfate is known to degrade at high temperature to generate H2S, while sulfites generate sulfates that end up causing inorganic scale precipitation or feeding sulfate reducing bacteria creating another source of H2S in the reservoir. Additionally, Sodium thiosulfate is a high pH additive which can cause formation damage through fines migration and precipitation of hydroxides. Vitamin C is renowned for its antioxidative and oxygen scavenging properties throughout many industries. It is commonly used as an extremely cheap supplement to boost the immune system and as a food preservative to increase shelf life. Moreover, it has an acidic pH and offers a chemical structure capable of delaying crosslinking reactions. For that reason, this work aims to study the influence of Vitamin C as a multifunctional additive in fracturing fluids. The tests mainly utilized the high-pressure/high-temperature (HPHT) rheometer. The performance of Vitamin C was assessed with a guar derivative at temperatures between 250-300°F for 1.5 hours. Moreover, zeta potential and coreflood were used to evaluate the formation damage tendencies of using this additive. The results showed that the use of Vitamin C was able to provide a pH reduction, crosslinking delay, and enhance the high temperature stability of fracturing fluids. Zeta potential and coreflood experiments showed that clays were more stable at lower pH conditions minimizing fines migration. Vitamin C is a cheap and readily manufactured environmentally friendly additive that offers solutions to the use of fracturing fluids at high temperatures. Utilizing it not only offers oxygen scavenging ability, but also replaces additives that lower pH and provides crosslinking delaying properties.