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.

To selectively stimulate a well with a complex completion in a naturally fractured carbonate reservoir in a mature field, the use of a self-degrading diverter deployed by rigless means through 1 1/2-in. coiled tubing (CT) was necessary in addition to an effective acidizing schedule using relative permeability modifiers (RPMs) as an additional diverter. The well was completed in combined 5-in. casing (slotted liner at the lower part and upper free casing) and two upper perforated intervals.Initially, a nonreactive treatment was performed, pumping 500 bbl of solvent through a slotted liner section to evaluate the lower zone.After this, the operator's program involved adding two new perforated intervals in the upper portion. Following this, the challenge was to effectively treat the upper intervals while isolating the lower zone.After consultation, the service company recommended temporarily isolating the lower zone with a self-degrading diverting agent deployed with 1 1/2-in. CT and immediately stimulating the upper intervals using a gelled acid blend system and a RPM as a diverter pumped during the stimulation phase.A noncommercial production rate was obtained with the nonreactive treatment after the evaluation of the lower section (75 m in slotted liner section).With the temporary isolation of the lower zone using a self-degrading diverter deployed throughout 150 m in the 5-in. liner, a reactive stimulation was performed by means of bullheading and directed to the upper intervals. Previous to the stimulation treatment, the well did not produce. After treatment, the well produced in natural flow 852 B/D of oil with 3.8 % water cut through a 1.45-in. choke. The outcome was excellent productivity in a problem well with a complex completion in a naturally fractured carbonate reservoir.This paper highlights various challenges encountered while stimulating complex completion wells and describes step-by-step procedures followed to achieve outstanding results. Additionally highlighted is how lessons learned can be applied during future treatments on candidate wells.

Enhancing stimulation treatments in carbonate reservoirs is a continuous process that includes input from previous operations and production results. Individually, stimulation provides an opportunity to improve the treatment design by means of various factors, such as changes to rates and volumes, new fluid designs, use of nitrogen to increase energy and recover additional fluid after the operation, changes to the well completion, novel diversion techniques, and additional additives. These factors affect overall optimization of fluid distribution. This paper discusses the use of particulate diverter systems during acidizing treatments and highlights how such treatments have progressed. A case study of a carbonate formation in northern Mexico is also presented. A carbonate field in northern Mexico was analyzed in 2010 to implement a stimulation treatment. The operations ranged initially from reactive and nonreactive stimulation treatments at low-pumping rates to hydraulic acid fracturing in a single formation. After understanding the use of hydraulic acid fracturing in a single zone, multiple formation zones were fractured to improve production while introducing changes in the well completion to enable a faster operation. Multiple acid fracturing treatments during a single intervention were performed with a particulate diversion material to increase the zonal coverage. The successful diversion application has been documented using diagnostics, such as temperature profiles and radioactive tracers. When a reactive and nonreactive stimulation treatment was performed, the average production in the field was 30 BOPD. Later, with the implementation of hydraulic acid fracturing in a single interval (more than 20 fracturing operations), the average production per well increased to 100 BOPD. More recently, in the last 15 wells, the application of fracturing improvements and the stimulation of two to three zones using particulate diversion to distribute the fluid achieved average production results of approximately 300 BOPD. These results represent a threefold increase since the initial fracturing operations and a tenfold increase since stimulation operations began in the field. Improvements in acid diversion techniques using particulate diverters has provided significant advantages by enabling effective treatment of several zones in one step, without stopping the operation. This paper describes the design and implementation of the diverting system used during the case study to improve production in a carbonate formation.

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