Conventionally, matrix acidizing treatments have not been performed in HPHT wells with temperatures much above 150°C, because of the limitations on acid retardation technologies of hydrochloric acid (HCI) and the inhibition of corrosion of these fluids at elevated temperatures.

This paper presents the corrosion studies for the design of an acid treatment performed on a gas well in a naturally- fractured, tight carbonate under conditions that were beyond the limit of conventional matrix acidizing experience. Stimulation of the well required acid to be placed below fracturing pressures into the natural fracture system beyond the near wellbore region. The reservoir was deep (16,000 ft [5,000 m]), sour (2 to 4% H2S) and at high temperature (~170°C) nd pressure (>8,700 psi [600 bar]).

Ensuring success of such an operation requires detailed design, involving extensive laboratory testing of fluid properties, corrosion evaluation and design of placement techniques. The factors that need to be considered for such treatments, namely balancing the conflicting requirements of acid reaction and corrosion, acid stability and placement, are illustrated using details from the case study. A critical issue was designing a fluid system and a placement method that achieved the required penetration and placement over the target interval while maintaining acceptable corrosion inhibition.


The acid treatment which is presented here, was performed as part of a second well test of the Buah formation in welt MKM-3, a gas appraisal well in a large, deep gas field in central Oman. [11 The challenges to overcome were the selection and corrosion inhibition of the stimulation fluids required for the treatment. The most important factors for the design of the two acid systems were the reservoir temperature and the sour nature of the produced gas. At reservoir temperatures above 150°C, acid corrosion rates and reaction rates become very rapid and until recently were beyond the limit of low pump-rate (matrix) acidizing treatments. Moreover, corrosion inhibition is more difficult to achieve in the presence of sour gas. The design and operational considerations were previously discussed in detail. [2] Previous studies had not discussed the corrosion issues of the emulsified acid systems and the use at higher temperatures and pressures resulted in new challenges.

The Makarem field has two overlying reservoirs - the Buah carbonate at around 15,748 ft [4,800m] depth and the Amin sandstone some 328 f [100m] shallower. Both reservoirs are over-pressured, with a pressure of 9,427 psi [650 bar] and a temperature of 168°C in the target reservoir. The reservoir fluids are common to both and have 2 - 4% hydrogen sulphide, H2S, and 4% carbon dioxide, CO2. See Table 1 for an overview of the field parameters. The design of this treatment was strongly influenced by:

? Formation properties, especially the presence of a nearby gas-water contact and fracture properties,

? Well status, An additional zone was potentially open to flow and a repair had been performed on the tubing, which had partially corroded. [3]

? High formation temperatures in the presence of I-iS, which is at the limit of today's technology for corrosion inhibition and acid retardation.

Formation properties

The Buah formation is a tight, fractured carbonate, with effective matrix porosities as little as 2 - 3% and which contains vuggy, fractured layers through which most the initial production is obtained. During an initial test in 1998, 69 fi [2 lm] o f the Buah in MKM-3 was perforated and tested to a maximum rate of 7,000 MScf/d [0.2 million l~/d] at a tubing head pressure (THP) of 725 psi [50 bar]. A short flowing build-

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