Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan

Abstract

Abstract Stimulation of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity, damage to each zone, matrix mineralogical composition, and pressure regimes of each zone need to be taken into consideration. The presence of natural fractures makes the entire treatment more complex. Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor to the lowest possible value in each zone. At the same time, the selected optimum acid system, placement, and diversion techniques need to be applicable in the field in a simple manner without impacting the overall treatment logistics. The use of a hydrochloric acid system containing a viscoelastic surfactant system that allows, upon acid spending, the development of viscosity in situ, has shown that significant skin reductions can be obtained provided the proper placement techniques are used. However, in certain cases where natural fractures are dominant, diversion effects can be noticed but are not optimal. An enhanced system that contains temperature-degradable fibers has been used in Kazakhstan. Such systems are shown to successfully divert and stimulate effectively even when natural fractures are dominant. This paper presents experiences with different types of acid placements and diversion techniques in the thick carbonate reservoirs of western Kazakhstan. Pretreatment and post-treatment production data have been analyzed to evaluate the effectiveness of the treatments in terms of skin reduction or productivity index increase. Introduction Hydrocarbon wells producing from carbonate reservoirs are often stimulated with small quantities of hydrochloric acid, and in most of the cases relevant increases in hydrocarbon production are obtained. Because the chemical reactions involved are simple, the results are almost guaranteed even when using acid systems with a minimal amount of additives. The main question that needs to be answered is if the well was properly stimulated. After the stimulation treatment has the well reached the ideal producing conditions and has the skin been reduced to the minimum possible compatible with the type of reservoir from which hydrocarbons are being produced. Because almost all the carbonate reservoirs in Kazakhstan have more-or-less thick sections with natural fractures, the hydrocarbon production occurs with a dual-porosity mechanism through the sections with natural fractures and with a matrix flow where no natural fractures are present. These natural fractures create a network, and, as a result of the wellbore intersecting the natural fracture network (either with perforations or through possible fractures induced during the drilling phases), it is not rare to see a well producing with skin as low as -4 or -5. When stimulating one of these wells, the question that needs to be answered after a stimulation treatment, once the production data are obtained, is have such skin values have been achieved or not. In this paper several stimulation treatments performed in thick carbonate reservoirs in Kazakhstan have been analyzed with all relevant available data. The data include the hydrochloric acid systems selected, the additives included in the fluid package, the use and the type of diverting agents, the placement techniques adopted, and the pre-treatment and post-treatment production logs, where available. The treatments have been evaluated to measure the gains resulting from each treatment, and some common trends have been established in terms of skin reduction, or more specifically, productivity index increases for certain types of designs and placements.