Electric Submersible Pumps (ESP) are commonly used artificial lift equipment in production wells. The ESP packer penetrator system is designed to carry the electric power cable that connects the electric motor in ESP to the surface control panel. Various chemicals downhole make up highly corrosive and hostile environments to the metal wires and their insulation materials for electric connectors. Many ESP failures could be attributed to packer penetrator failure due to corrosion of the electric connector beneath the ESP packer. A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive atmospheres and chemical attacks. Mixture of low-density materials/composites are prepared on the surface and then pumped into targeted place through the bypass tubing. The mixture has low density so that it travels upwards in the wellbore and floats on the top of downhole fluids. Under a given well temperature, a rigid gel/composite system forms between the electric connector and the downhole fluids, isolating the electric connector from the hostile chemicals thus providing a better protection. We have developed the low density settable material and demonstrated its performance in the lab scale. It is also scaled up to a mocked up physical simulator to observe the flow dynamics and chemical reaction in realistic geometry.

Acid treatments for sandstones differ significantly from those for carbonate rocks. Unlike carbonate acidizing where HCl reacts with carbonates to generate reaction products soluble in water, sandstone acidizing using mud acids produces reaction products that may precipitate and reduce rock permeability. The challenges of sandstone acidizing are to optimize damage removal while minimizing formation-damaging precipitates. Understanding formation mineralogy and the nature of damage is critical for designing a proper acid treatment. Sandstone acidizing has been always a challenging task, especially if the formation is acid-sensitive. Traditionally, sandstone reservoirs in the Northern Area of Saudi Arabia are not stimulated due to their negative reaction to acidizing. Wells A and B were drilled and completed as vertical cased hole wastewater disposal wells for a refinery in the northern area of Saudi Arabia. They have been used to dispose the refinery wastewater since 1998. The injectivity of Well A was maintained since it was placed on injection, whereas well B showed low injectivity with a skin damage of + 20. The major minerals found in the sandstone reservoir are quarts, dolomite, and calcite with kaolite and smectite. The latest analysis of the refinery injection wastewater showed that the wastewater contained suspended solids (iron sulfide) and oil. After several negative clean-up trials by flowing the well back in order to restore injectivity and maintain adequate wastewater disposal capacity of the refinery, it was decided to stimulate or sidetrack the well. A new design methodology with extensive lab testing was applied to design a tailored treatment to address these challenges. It included a pre-flush of aromatic solvents, then stages of 10 wt% HCl, 9:1 HCl:HF acids. To achieve better acid diversion for the long perforated intervals (200 ft) with high permeability contrast, foamed diverter stages (quality 70%) were incorporated in the treatment. A carefully designed train of treatment fluids was applied to remove formation damage induced by drilling and injection fluids. Injectivity tests before and after each step of the treatment was recorded and evaluated. Proper design and execution of the stimulation treatment almost doubled the well injectivity index from 47 to 86 b/d/psi. The maximum injection rate increased from 50 to 92 BPM, at 1,500 psi injection pressure. Challenges, fluid selection, design criteria, field treatment, lessons learned, and results of the acid treatments will be discussed in this paper. Introduction Matrix acidizing reestablishes productivity or injectivity in many damaged wells in a cost effective way. A matrix acid treatment forces the injected acid into the formation at a pressure below its fracture pressure. The treatment often involves several stages that may be repeated. The damage can be natural, caused by reservoir fluids moving through the formation, or induced by fluids used in the operations, such as drilling, completions and workovers, or stimulation. Typical examples of formation damage include: fines migration, scale formation, deposition of paraffins, asphaltenes, or mixed organic and inorganic deposition.[1–4] It can also result from plugging by foreign particles in injected fluids, wettability changes, clay swelling, emulsions, precipitates or sludges caused by acid reactions, bacterial activity and water block.[3–7] Wellbore cleanup, matrix stimulation treatments or acid fracturing can be used to remove or bypass the damage. Acid treatments conducted in sandstones reservoirs differ significantly from those performed in carbonates rocks. Carbonate rocks dissolve readily in hydrochloric acid, and the reaction products are water-soluble. A matrix acid job is usually designed to bypass near wellbore damage by dissolving carbonates and creating high permeability channels, or wormholes, in the rock, thus providing a flow path past the near wellbore damage.

The deployment of downhole packers in Electrical Submersible Pump (ESP) completions brings many added benefits to the wellbore integrity, yet it adds a certain degree of complexity to the completion design, installation, and operation. Thermal expansion of the trapped completion fluid in the tubingcasing-annulus (TCA), located between the ESP upper completion packer and the tubing hanger, poses several risks to the wellbore integrity, including tubing collapse, wellhead rupture, packer failure, casing failure, ESP cable failure, and packer electric penetrator failure. The increase in TCA pressure is accelerated in ESP wells because of their capability to instantaneously produce high volumes of hot reservoir fluids to the surface. Improper bleeding of TCA pressure results in explosive decompression (ED) of the different ESP cable components leading to a sudden premature failure of the electrical system. While appropriate bleed-off procedures have shown to minimize ED effects the selection of suitable ESP cable materials have eliminated these types of TCA cable failures. Gathering data from multiple sources such as Dismantle Inspection and Failure Analysis (DIFA), ESP downhole sensors, laboratory tests, and completion pull reports was a critical step for accurate identification of the root cause behind the encountered TCA problems. The followed analysis methodology showed that selection of packer elastomers that are suitable for the reservoir conditions was proven to be of extreme importance to the wellbore integrity and the ESP runlife. In the presented case study, changing to high-grade elastomer packers was necessary in order to tolerate the high hydrogen sulfide (H 2 S) partial pressure experienced in the studied field. Moreover, data gathered from DIFA proved that proper well cleanouts prior to ESP installation is also crucial in preventing explosive decompression of packer penetrator. In fact, effective TCA management is an important strategy that needs to be implemented in both the design and operation of the well completion.

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