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.

INTRODUCTION When the natural energy of a reservoir is not enough in order to elevate the oil to the surface, it is necessary to use an artificial lift system that supply the additional energy required to continue the exploitation of the reservoir. Likewise, the artificial lift system is installed to increment the production in flowing wells. This is achieved by the energy that is added to fluids in the bottom of the well. The hydraulic pumping, is an artificial lift system that transmits energy in the bottom of the well by a power fluid that flow through a pump. There are two types of hydraulic pumping; the denominated piston type, that consists in a pair of reciprocating pistons, where one of them is driven by the power fluid and the other pumping the well fluids. And the hydraulic pumping jet type, which converts the pressurized power fluid to a high velocity jet that is mixed directly with the well fluids. A description is presented and the result reached in a pilot test of hydraulic jet pump, effected in the Balam 91 well of the Ek-Balam field. BACKGROUND The Ek-Balam field was discovered when the Ek 101 and Balam 1 wells were drilled in March 1991 and January 1992 respectively. This reservoir is located at 95 km to the N 10° W of Carmen City, Campeche, in the Gulf of Mexico. The geophysical and petrophysical evidence allowed to define the existence of a saline intrusion lengthened with NW-SE orientation that divides the reservoir into two blocks, that have similar but independent characteristics (figure 1). The first tests indicated the possibility that had been found a field of great magnitude. However, the initial production rate declined quickly as well as the static pressure of the reservoir, which originally was rated from 7,850 psi for Ek up to 8,200 psi for Balam. The producing formation belongs to the Upper Jurassic Oxfordian sandstone and constituted mainly by light consolidated sand, which cause that fine solid materials be carried when the pressure drop in the reservoir is high, occasioning problems in the surface and bottomhole installations, as well as in the bottom of the well for their deposition. How a days, the wells in operation in the Ek-Balam field produce through the artificial lift denominated Electro Submersible Pump (ESP). However, with the purpose of analyzing another option that could complement to the utilized system, was proposed the development of a test of hydraulic jet pump (HJP) in the Ek-Balam field. The Balam 91 well is located in the Balam-TE platform, in the Ek-Balam field that belongs to the PEMEX Northeast Marine Region in the Campeche Bay, Gulf of Mexico. Hydraulic pumping. The hydraulic pumping operate for the transmission of potential energy that is effected in a pump located in the bottom of the well to the produced fluids. The hydraulic pump in the bottom acts like a transformer converting the energy of a power fluid to potential energy or pressure. Exist two types of installations: fixed and free pump. The fixed installation consists of a down hole pump attached to the end of a tubing string; the free pump is design in order to permit it installation inside of the tubing, which normally is coiled tubing (CT), in order to drive the power fluid. This allows recovering the pump with inverse circulation. There are two forms to inject the power fluid; in closed or open circuit. Hydraulic pumping. The hydraulic pumping operate for the transmission of potential energy that is effected in a pump located in the bottom of the well to the produced fluids. The hydraulic pump in the bottom acts like a transformer converting the energy of a power fluid to potential energy or pressure. Exist two types of installations: fixed and free pump. The fixed installation consists of a down hole pump attached to the end of a tubing string; the free pump is design in order to permit it installation inside of the tubing, which normally is coiled tubing (CT), in order to drive the power fluid. This allows recovering the pump with inverse circulation. There are two forms to inject the power fluid; in closed or open circuit.

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.