Production of Hydrogen Sulfide (H2S) gas in oil and gas wells has increased over the last few years. These sour (H2S Producers) wells have been successfully acid stimulated for many years. Wellbore acid washes, high rate squeeze treatments and acid fracs have been the norm for stimulating wells in carbonate formations. However, to accomplish this there are many problems related to the interaction of the treatment fluids and the H2S. These can result in excessive corrosion, unwanted precipitants, metal cracking, etc.

In recent years, the practice of drilling horizontal wells has led to the technique of underbalanced acid washing. Controlling corrosion, metal fatigue and unwanted precipitants when using this technique in sour formations presents a special challenge. The resulting interaction of the H2S and acid additives, especially corrosion inhibitors has been the primary focus of concern.

This paper describes test equipment and procedures designed to investigate H2S and acid additive interactions. Test results with a range of inhibitors and additives designed to minimize formation damage and protect coiled tubing and tubular steels are provided. Specifically, weight loss, pitting and precipitation products are listed.


With the Petroleum Industry looking deeper and deeper for oil and gas reserves, thorough evaluation of the behavior of materials in those harsh conditions must be undertaken. A great deal of this work is now being done utilizing coiled tubing, primarily due to the ability to reduce location costs in many areas and due to a reduction of safety risks.1 Coiled tubing has added new dimensions to types and effectiveness of acid treatments.1–7 Many areas around the world are using coiled tubing to work on wells that are not only deep with high bottomhole temperatures and pressures but also produce corrosive fluids (H2S and CO2). Temperatures in these wells range from 275° to 415°F.1–5 H2S concentrations in these wells vary from <100 ppm to >60%. The diameters and lengths of coiled tubing strings have increased from the one-inch and one and half-inch diameters used initially to up to three inches, with tapered strings going to 20000 feet plus.

Types of treatments vary from conventional overbalanced acid fracturing and bullhead matrix acid jobs to underbalanced washing or wellbore clean-out operations. Table 1 lists the relative importance of reactions that may occur in the acid treatment of sour wells. These potential problem areas will be the subject of the discussion and experimental work described in this paper. Matrix treatments using coiled tubing allow for more effective treatment of lower zones through better placement.2,6 Placement is very important in long horizontal wellbores.2,3,5,7 An example, is the avoidance of contact by acid on acid sensitive formations while removing tubular scale in openhole completions. Another, would be the targeting of specific production intervals, such as an oil zone in preference to an acid treatment going into a gas zone in the same wellbore. Proper placement through the usage of coiled tubing was found to double injectivity in Arab-D PWI wells.6 Washing treatments are typically utilized to clean out scales or debris produced from the reserovir1,3,4

Corrosion control is a major factor in the success of all the acid treatments mentioned above. However, it is even more critical when H2S is added to the mix of conditions to be dealt with. Under conditions where the well is dead or non-reactive fluids are pumped ahead of acids under pressure, the H2S in the wellbore will be flushed into the formation so that contact of the metal with H2S saturated acid will be avoided. However, when washing treatments are being performed underbalanced or when iron sulfide scales are being dissolved, the coiled tubing and the metal tubulars will be exposed to the combined acid and H2S. Another occasion of concern is during the recovery of spent or partially spent acids, which have been depleted of inhibitors. The area of spent fluid corrosion is being investigated but will not be dealt with in this paper.8

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