A non-associated gas is being produced from deep carbonate reservoirs in Saudi Arabia. The lithology of the formation is mainly dolomite with some calcite and streaks of anhydrite. The non-associated gas is sour with hydrogen sulfide content that varies from 0 to 10-mol%. The average reservoir temperature is 275 °F and initial reservoir pressure is 7,000 psi. Because of the high bottomhole temperature and the corrosive nature of HCl, especially at high temperatures, a special acid system was needed to effectively stimulate the carbonate reservoir. Reaction rate of HCl/formic acid system with reservoir rocks was determined using a rotating disk apparatus. Coreflood tests indicated that this acid system could create deep wormholes in tight reservoir cores. Corrosion tests indicated that the well tubulars (low carbon steel, L-80 and C-95) could tolerate this acid system. Based on extensive lab work, 15-wt% HCl-9- wt% formic acid was used to stimulate several vertical, cased wells. The acid treatment comprised a preflush, main acid, closed fracture acid, and a postflush stage. Viscous pads were used alternately between stages to aid in cooling the formation. Initial results following this treatment indicated substantial increases in gas production and flowing wellhead pressures. Analysis of well flowback samples following acid treatments was used to optimize the treatment (acid soaking time, volume of postflush, etc). This paper describes optimization of HCl/formic acid system to stimulate deep gas wells using lab and field data.


Stimulation of carbonate reservoirs is typically the result of a need for restoration or enhancement of production to a more economic level. The design of these treatments requires a great deal of input to be successful. First, a thorough understanding of the reservoir is essential. This should include complete knowledge of the composition of both the mineralogy and the fluids, flow characteristics, permeability, porosity, and mechanical properties. After this is the need for a good knowledge of the well's history. Complete records of the drilling operations, production history, workovers, changes in wellbore parameters and the wellbore configuration. Lastly, as accurate a diagnosis of the damage or restriction inhibiting the economic production level. From all of this information will come the "Key's" to what to use and how to conduct the treatment.

Certain wells by their nature add additional constraints or hurdles to overcome to reach the desired production increases. One of these is depth and, therefore, higher temperature and possible treating rate limitations. The higher temperature increases corrosion rate of well tubulars and limits depth of penetration due to increased reactivity, if acids are to be used as the treating fluids.

Organic acids have been used extensively in acid stimulation treatments in the oil industry. Harris first reported the use of acetic acid for well completion and stimulation in 1961.1 Formic acid was used with HCl for high-temperature stimulation by Dill and Keeney in 1978.2 Acetic acid3–13 and formic acid6–9,12,14 have been used extensively in stimulation treatments in recent years.

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