Abstract

A sandstone reservoir in central Saudi Arabia produces sweet, super-light oil. Reservoir pressure support is accomplished by water injection into an aquifer underlying the pay zone. Several water injectors were found to be damaged due to iron sulfide and biomass generated by sulfate reducing bacteria (SRB). The sandstone reservoir is heterogeneous, poorly cemented, and contains up to 11 wt% of clay minerals and up to 0.3 wt% calcite.

An experimental study was conducted to design an effective stimulation treatment to restore the injectivity of the damaged wells, while maintaining the integrity of the formation. Various acids including HCl, acetic acid, regular and retarded mud acids were tested. Stimulation additives including H2S scavenger (aldehydes), iron control agents (EDTA), corrosion (amines) and scale inhibitors (phosphonic acid) were evaluated. Tests included acid-rock interactions under static and dynamic (core flood) conditions. Spent acid was analyzed for key cations using Inductively Coupled Plasma Spectrophotometry (ICP).

Core flood tests indicated that full strength mud acid damaged reservoir cores. Therefore, a half strength regular or retarded HF acid was used. Retarded HF acids which are based on boric acid produced a precipitate (KBF4) and are not recommended for field application. Hydrochloric acid at 7.5 wt% was effective in removing iron sulfide and biomass. However, XRD/XRF analyses indicated that elemental sulfur and CaSO4 precipitated inside the core, and were present in the core effluent. Addition of EDTA (chelating agent) to the acid substantially increased the concentration of multivalent cations in the core effluent. It also triggered production of fine silica particles and kaolinite, thus the cores were damaged. Hydrogen sulfide scavenger were found not to damage the reservoir cores. Scale inhibitor (phosphonic acid) minimized precipitation of calcium sulfate, however, it caused a significant drop in brine permeability when used at high concentrations >0.3 wt%).

Results obtained in this study indicated that a thorough screening of various acids and stimulation additives is needed before stimulating sour wells, otherwise severe damage can occur due to acid reactions with iron sulfide (a corrosion byproduct) and carbonate minerals present in the formation.

Introduction

Water injection has been used for reservoir pressure support to produce a sweet, superlight crude from an oil field in central Saudi Arabia. Several water injectors were drilled in the east and west sides of the field, injectivity tests conducted on selected wells indicated that the injection rate significantly dropped within a few hours. This result indicated that these wells had experienced some type of damage which would reduce flow of water into the formation. This paper discusses the damaging mechanism and a stimulation program which was designed to remove the damage while maintaining the integrity of the formation.

Table 1 shows the concentration of key ions present in the bottom, injection and connate waters. It is worth noting that the injection water contains a high concentration of sulfate ion (3,660 ppm).

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