Abstract

Conventionally, matrix acidising 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 (HCl) and the inhibition of corrosion of these fluids at elevated temperatures.

This paper presents the design and operational experience from a 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, sour and at high temperature and pressure.

Ensuring success of such an operation requires detailed design, involving extensive laboratory testing of fluid properties and design of placement techniques. Additional procedures and equipment are also required to effectively manage HSE risks and well integrity. This paper presents the critical factors in the design and operations planning stages, highlighting these with the case history for this well.

Introduction

The acid treatment which is presented here, was performed as part of a second well test of the Buah formation in MKM-3, a gas appraisal well in a large, deep gas field in central Oman [1]. The Makarem field has two overlying reservoirs - the Buah carbonate at around 4,800-m depth and the Amin sandstone some 100 m shallower. Both reservoirs are over-pressured, with a pressure of 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.

During an initial test in 1998, 21-m of the Buah in MKM-3 was perforated and tested to a maximum rate of 0.2 million m3/d at a tubing head pressure (THP) of 50 bar. A short flowing build-up (FBU) survey performed during this test indicated an extremely high skin of around 400. The cause of this high skin was unknown, but was thought to be due to either tortuosity due to limited connection between the nearby fracture system and the zero-phased perforations or impairment from the drilling process.

The second test of the Buah, which was performed in 2000, utilised an improved perforating policy with deep penetrating charges and 60° phasing. This only led to a limited increase in production capacity, with the same rate, 0.2 million m3/d, being achieved at a higher THP of 150 bar. A stimulation treatment was planned to increase the production rate, by either increasing the number and length of fractures that were open to flow or bypassing the possible impairment.

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 [2].

  • High formation temperatures in the presence of H2S, 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.

Acid fracturing of MKM-3 was considered undesirable because the gas-water contact was only 15 m below the lowest perforation. The natural fracture system has been studied extensively and there was a high degree of confidence that the fractures near the perforations did not extend to the water leg. A low-rate (matrix) treatment could therefore be designed to acidise the fractures connected to or near to the perforations.

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