Fields in offshore Mexico present different challenges to maximizing resource recovery due to the reservoir characteristics and completion configurations. Acidizing of high temperature (HT) dolomitic reservoirs (290 °F/143 °C) in the maritime fields represents the primary stimulation option due to existing well parameters restricting treatment designs to matrix rate conditions. Acidizing treatments are typically based on HCl and organic acids and for the first time a multifunctional, low viscosity, retarded HCl acid is also available. Laboratory wormhole tests were conducted for matrix injection but also in a pseudo-acid fracture condition (split-core) in order to establish feasibility for future stimulation designs. Three acid blends were used, a blend of organic acids (OA), a mixture of HCl and organic acid (HA), and a polymer free retarded HCl acid (HRMA). The cores tested correspond to a particular well and X-ray Diffraction (XRD) analysis confirms it is >98% dolomite. CT imaging corroborates the heterogeneous permeability due to primary and secondary porosity systems (5% – 10% and 10% – 15%). The pore volume breakthrough of each acid blend was determined for two cores of similar porosity under same constant injection rate. Results indicate the organic acids blend (OA) can have better injectivity when flow rate is much higher than the HCl/Organic acid (HA) blend. A core with 10X lower permeability (0.1 – 0.5 mD) was tested with new Retarded HCl acid (HRMA) using same injection rate as the other acid blends. Results indicate that Retarded HCl (HRMA) does not cause core facial dissolution under unoptimized injection rate. The wormhole patterns generated for the HCl/Organic acid (HA) blend show good distribution and for Retarded HCl (HRMA) show enhance acid containment (less ramification). Both HCl acid blends (HA and HRMA) are suitable for dolomitic acidizing under different injection rates, while the purely organic acid blend is more adequate for high rate injection. Notably acidizing of dolomitic reservoirs can be highly efficient under optimized conditions and future work with non-retarded and retarded acids can systematically drive pumping engineering designs. The Retarded HCl acid (HRMA) has multifunctional properties including scale inhibition and lower HCl reactivity.

Removal of wellbore scale from downhole equipment continues to impact well economics due to productivity losses and asset maintenance. The use of first-of-its-class calcium sulfate (CaSO4) scale dissolver in high producing offshore wells equipped with electric submersible pumps (ESP) is presented. The efficiency of the new fluid surpasses the performance of established dissolvers since it does not require long shut-in periods. Anhydrite (CaSO4) scale dissolution and removal can be accomplished with a simple treatment fluid employing a formulation that has been field-proven to restore production and protect downhole equipment in a time-efficient manner. Mineral anhydrite and wellbore scale samples were tested with the dissolver formulation at 200°F (93.3°C), under static conditions for one hour. Dissolution efficiencies greater than 94% were a requirement. Fluid compatibility with metallic and non-metallic components in the wellbore were assessed at bottom hole static temperature (BHST) conditions for a period of 24 hours. The fluid was deployed from a stimulation vessel at a pumping rate from 1 to 5 bpm. A small volume pill of 5 m3 on average was pumped in at least 20 wells, through the production tubing to the ESP and was allowed to soak for 1 hour. Wells were immediately opened to production after a 1-h soak period. Minimizing the non-productive time incurred when long soak periods are required has been attained with the use of the new dissolver fluid, leading to greater efficiencies associated with CaSO4-type scale removal. ESP temperature was monitored and reduced by 13°F (7.2°C) after treatment, similar to temperatures before scale build up. After the treatment, the results show a 1.125-fold increase in oil production. The fast-acting formulation exceeds 90% dissolution efficiency within one hour and improves operations by using a fluid that is non-corrosive to downhole materials in a one-stage removal package. The dissolver formulation provides dissolution of anhydrite at 200°F in ESPs. The fast acting dissolver is delivered as a single fluid package and eliminates the need for separate fluid stages as well as the use of incompatible fluids. Anhydrite scale dissolution and removal can be accomplished with a simple treatment fluid and extend the life of the ESP.