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.

The formation of calcite scale is induced generally through a change in pressure and temperature, which affects the saturation level of calcium and bicarbonate as the CO2 gas is released. Prevention of calcite precipitation through scale inhibitor squeezing job treatment is a well-known method for minimizing potential scaling. The selection of suitable scale inhibitor is important as its performance can be affected by the lithology and reservoir conditions. In this study, a scheme of screening new scale inhibitors was evaluated. The proposed scheme included the study of the adsorption/desorption characteristics of the scale inhibitor and its efficiency at higher temperature. The proposed scale inhibitor treatment design included pre-flush/post-flush fluid and the SI main fluid in addition to the synthetic formation water (SFW). Lithium chloride was introduced to the main SI fluid as a tracer. To study the SI fluid-rock interaction, core flood testing was conducted on the Outcrop Torrey Buff sandstone core plug. The results of the core flood was used to determine the change in permeability during the SI soaking and assess the formation damage. Ca, Mg and total iron in the effluents samples were used to study the dissolution of the plug. P and Li analysis were used to study the absorption/desorption behavior of the scale inhibitor during the 5 days of flooding and compared to the minimum inhibition concentration (MIC). Core flood data showed the differential pressures versus the cumulative pore volume of the injected fluids revealed that around 20% of formation damage was encountered during the SI flooding, which is anticipated in sandstone rock due to high adsorption of the scale inhibitor on the rock. The desorption profile of the scale inhibitor showed that the proposed treatment scale inhibitor could keep its concentration above the MIC at ultra-high temperature. The study revealed that the proposed phosphonate-based inhibitor showed effective performance at higher temperature. The desorption rate is adequate to keep the scale inhibitor concentration above the MIC. The scheme of study can be used to screen different scale inhibitors at higher temperature and to assess their adsorption/desorption characteristic.

The need for more efficient, cost effective, relatively high flashpoint, and environmental friendly organic solvent is crucial. Due to safety and environmental effects of the conventional aromatic solvents, efforts are being focused to search for more natural based products. A total of 14 terpene-based and conventional solvents have been examined to identify their dissolving power of asphaltene/organic sludge. The organic solvents vary in their compositions from xylene or conventional based solvents to the more environmental friendly compounds of terpene (green solvents). They also vary in their flash points from as low as 75°F tod as high as 200°F. The organic scale/sludge samples have been studied by thermogravimetric analysis (TGA), FT-IR, ESI-MS and asphaltene analyses. The analysis showed the contents of asphaltene, functional groups, saturation level and weigh loss of both deposits. Dissolution tests were conducted on both organic deposits using 11 terpene-based solvents and 3 conventional solvents. Dissolution tests were conducted at room temperature and 50°C with soaking times of 3 and 24 hours. The solubility of deposit A at most of the solvents was found to be lower than the solubility of deposit B due to variation in both deposits’ compositions. Even though the increase of the soaking time was found to be of positive impact, most of the dissolving occurred in the first few hours. This study results also revealed that the efficiency of the terpene-based organic solvents is a function of terpene concentration; however, increasing the terpene concentration would decrease the flash point, which is of a safety concern in warm climate countries, especially during high temperature seasons. The environmentally friendly terpene-based solvents displayed promising results and can be an alternative to conventional solvents.

The quality of base fluid used in the preparation of different stimulation and wellbore cleaner recipes is very critical toward high efficient job. However, due to the limited access to adequate quality water sources, efforts to minimize the operational impacts of such less quality source is grown rapidly. High sulfate mixing water is well known example of such low quality water and which results in sulfates deposits during stimulation operation. In this paper, an effective management of barium sulfate precipitation in high pH and iron rich environment is presented. A simulated low quality water with high sulfate content of more than 500 ppm and produced water of high barium and iron contents were proposed and prepared for this study. Static jar compatibility tests at high pressure and temperature were conducted at different ratios to study the potential precipitation of sulfates and iron deposits. Precipitated solids were identified by Scanning Electron Microscope (SEM) and aqueous phases were analyzed by ICP-OES and IC for barium, iron and sulfate content. Then, three different scale inhibitors (SI) were assessed at different loadings for their efficiency to prevent scaling. Chelating agent was also used to enhance the efficiency of scale prevention and work to chelate iron ions presented in the produced water. The effect of high pH in the precipitation quantity was also studied. Results showed high potential of barium sulfate precipitation at different maxing ratios. At higher ratios of produced water, the presence of more iron deposit was observed. Analysis confirmed the barium sulfate deposition during the static jar tests. Scale inhibitors performance were found to be functions of loading and the presence of iron. Chelating agent improve the performance of SI and led to minimum precipitation potential. An optimized fracturing recipe was designed utilizing the high sulfate source water and proved to minimize the impact of sulfates scaling. The use of the chelating agent was found to be critical to enhance the scale inhibitor tolerance toward iron presence.

Waterflooding has always been considered as a favorable technology to support reservoir pressure during production and enhance recovery. The main challenge that needs to be addressed is the increase in scale potential due to incompatibility of mixing two different waters of different physical and chemical properties. Calcium sulfate scaling can form as a result of the reaction of high calcium produced water with high sulfate injection water. Since there is no feasible method that can efficiently be used to reduce the high calcium content in the formation water, treating the injection water by adding scale inhibitor or lowering its sulfate content is of high interest. Reducing the sulfate content physically through RO membranes or chemically through ion exchange methods can be considered a solution. In this study, different scenarios for using reduced sulfate simulated injection water (SIW) in addition to untreated SIW have been examined as options for waterflooding prior to field application recommendations. Three different concentrations of reduced sulfate SIW (100, 200 and 300 SO4− ppm) in addition to the untreated SIW with almost 4000 ppm of SO4− were used to study water-water reaction and water-rock interaction. The study scheme included static bottle testing for compatibility of the synthetic flooding water and SPW at different mixing ratios and coreflooding at different temperatures for the water-rock interaction. Water-water interaction tests revealed that the reduced sulfate SIW was found to be compatible, and no sign of precipitatation was observed. Untreated SIW showed white precipitates of calcium sulfate when mixed with the high calcium synthetic simulated production water (SPW) at different ratios and temperature. Coreflooding formation damage assessment indicated a reduction in the commercial core plug permeability of less than 12%. Reduced sulfate waterflooding can eliminate the risk of calcium sulfate scale formation damage and minimizing scaling mitigation and challenges requirements.