Fracturing fluids are normally injected at high rates and pressures to break the reservoir rock, where proppants ideally are suspended during fluid injection. High strength ceramic proppants are used to overcome hash environments (i.e., high closure stress and temperatures). Advancements in proppant manufacturing further added several characteristics to the proppants, such as self-suspending, multi-phase flow enhancer, and multifactional proppants. The objectives of this study were to compare the performance of HSP and ULW ceramic proppants though proppant characterization, wettability measurements, settling behavior, acid solubility, proppant pack conductivity, and proppant crush resistance. Fracture cell was used to measure the proppant pack conductivity. Proppant crush resistance was conducted using hydraulic uni-axial loading frame. XRD and XRF were used to characterize proppant samples. Solubility in HCl solutions was examined. Elemental analysis was conducted using ICP. Light transmission and backscattering technique was used to compare the settling behavior of proppant samples. Drop Shape Analyzer was used to measure the contact angle on the surface of proppant samples. The highest performance proppant among the five-examined proppants was proppant P-1. This was based on the conductivity values obtained, the correlation between conductivity and fines generated, settling behavior, and solubility in HCl acids. Proppant P-5 exhibited non-wetted properties for both water and condensate fluids. ULW proppants (i.e., P-7 and P-8) showed significantly improved suspension properties over the examined HSP proppants. The solubility of the HSP proppants in HCl acid depended on the acid concentration, soaking time, surface area. The solubilities obtained was up to 10 wt% in concentrated HCl acids. High concentrations of Fe were observed in concentrated acid solution (i.e. ~1800 mg/l). Proppant pack conductivity values for examined proppants were relatively similar except for proppants P-3 and P-5.A linear correlation was found between wt% of fines generated and proppant pack conductivity.

Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential due to scale precipitation. Various components in produced water such as H2S, suspended solids, bacteria and other metal ions such as iron are the primary cause of permeability impairment. Injected water should be compatible with both rock and formation fluids, thus the need to find chemical solutions to minimize the impact of injection water on formation rock arises. Potassium Permanganate (KMnO4), and Citric Acid based treatments are experimentally investigated to effectively improve water injection quality and minimize formation damage. Extensive experimental methods were conducted to determine the optimum treatmentpercentage required to reach optimum water quality, with least amount of scale precipitants. Water samples with high salinity, iron content, sulfates and bicarbonates were used in this study. Additional experimental methods including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the impact of adding KMnO4 and Citric Acid onformation water and formation rock permeability. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less damage on formation permeability. Experiments were conducted at temperatures up to 250°F and pressure 3,000 psi. Post treatment damage mechanisms were also investigated using XRD and ESEM methods on formed scale due to fluid/fluid and rock/fluid interactions. The experimental investigation yielded that KMnO4 would reduce the iron content, therefore, eliminating possibility of formation damage. Oxygen scavenger was also added to some water mixtures to halt iron precipitation. HT/HP compatibility test results indicated that no iron oxide precipitation occurred in examined water mixtures after KMnO4 and oxygen scavenger were added. Coreflood experiments showed no permeability reduction in the core plugs although with white solid precipitation noticed on the face of the plugs which was attributed to the precipitation of the insignificant amount of CaCO3 as indicated by ESEM and XRD analysis. Citric acid-based recipe, on the other hand, yielded varying results with different water samples. Some cases showed somehow good water quality improvements with low iron content and others did not with high iron content. This paper presents an experimental approach to treating and optimizing the quality of water intended for injection using KMnO4, or Citric Acid. XRD, ESEM analysis and compatibility and coreflooding experiments were conducted to assess impact of interaction of different water/water mixtures on clastic and carbonate core plugs permeabilities. It also investigates different formation damage mechanisms associated with water injection.

Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity. In this study, an extensive laboratory work was conducted to explore potential interactions of an oil-based mud with different contaminants encountered in downhole environment. A typical sludge sample was characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The source of calcium carbonate might the drilling additives while the source of quartz is the formation. Analysis of supernatants generated from solubility tests conducted for the sludge sample revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. This paper presents in detail the results of interactions of iron ions, quartz, and pipe dope. It also examined several chemical formulations for removal of sludge formed and filtercake.

Acid matrix stimulation is a widely used method to improve well productivity by removing and/or bypassing damage in the near wellbore area and creating channels for hydrocarbon flow. Hydrochloric (HCl) and organic acids are commonly used to design fluid recipes utilized in these treatments. However, these acids can cause formation damage by forming stable emulsions and sludge upon contact with formation crude if the treatment and/or stimulation fluid are not designed carefully. It is well reported that acid in contact with crude oil can destabilize asphaltenes either by neutralizing asphaltene or dissolution of resins. Therefore, acid recipe chemical additives must be selected and examined carefully to ensure effective acidizing treatments. In this study, the interaction of different HCl-based recipes with oil was investigated using different lab techniques and analysis including acid/oil separation tests, sludging tendency testing, and SARA analysis. The influence of several factors including acid concentration, acid type, and dissolved iron content were investigated. Experiments were conducted with varying acid blends, demulsifier and anti-sludge type and concentration. To simulate dissolving corrosion products by acids in downhole environment, ferric chloride was incorporated in acid recipes. The results showed an increase in temperature enhanced emulsion/sludge breaking tendency. The addition of demulsifier/anti-sludge agents in acid recipes was necessary to avoid creating stable emulsions and sludge that can damage reservoir permeability. Higher amounts of dissolved iron in the acid solution resulted in a more stable emulsion and enhanced sludge formation. Asphaltene problematic oil, as determined from the asphaltene colloidal instability index, showed severe sludging tendency. Lastly, the use of HCl/organic acid blends may be necessary for some oil types to avoid formation of sludge. This paper showcases a comprehensive testing method to mitigate formation damage from acidizing treatments. The testing can be expanded to design an acid stimulation fluid recipe to minimize acid-induced formation damage and maximize well productivity enhancement.