Oil and gas companies operating carbonate oil and gas condensate fields in Kazakhstan have been carrying out acid stimulation activities leading to a substantial increase in hydrocarbon production. Nearly all treatments were considered a success. Nevertheless, a certain level of optimization in the production enhancement methods that could, potentially, have brought additional technical and financial benefits, were overlooked due to various reasons. A comprehensive review of historical treatments on several fields located in West-Kazakhstan region was performed to identify areas to improve post-stimulation well performance. This review identified improvements including "cleaner" fluid selection, optimised design and treatment schedules. Historical treatments in the oil field typically used straight hydrochloric acid as the main acid, polymer-gelled (self-diverting) acid as the chemical diverter, and linear guar gel for displacement, and diagnostic tests. The application of a modern single-phase retarded acid to replace the straight hydrochloric acid was identified as a key improvement that would yield more efficient wormhole generation and an improved stimulation ratio. Another opportunity for improvement was to upgrade the chemical diversion system from polymer-based self-diverting acid to a viscoelastic surfactant-based (polymer-free) diverting acid system. The use of an oil-based displacement fluid with high retained permeability instead of linear gel and to reduce the hydrostatic pressure post-acidizing, thereby improving flowback, was also employed. Extended core flow testing for regained permeability and solubility were carried out with several acid systems to compare their capabilities and efficiency to create conductive wormholes, and their dissolution capacities. Additionally, emulsion, and sludging tendency upon contact with wellbore tubulars and formation crude was checked to verify the acids’ compatibility with hydrocarbons produced from the target reservoir. After the prerequisite laboratory testing, field trials commenced applying various combinations of fluid technologies in high-rate matrix stimulation treatments. The optimizations resulted in higher (normalized) post-stimulation productivity index (PI), facilitated formation cleanup, and enabled more efficient operations. A similar approach is, currently, being implemented in other stimulation projects in the region, and the results are being replicated. As has been mentioned above, one of the main enhancements implemented as part of this work is the employment of the single-phase retarded acid. Most of the published literature discussing application of the acid covers the cases of stimulation of relatively hot reservoirs (BHST>100°C) as acidizing of high-temperature carbonate rock using traditional hydrochloric acid is a great challenge. The current paper provides details of the case studies, where the acid system was successfully implemented in combination with several other stimulation technologies for mid-temperature ranges. One of the objectives was also to assess whether application of reduced volumes of the retarded and diverting acids would still lead to improved wells’ productivity. Positive results of the laboratory studies, treatment modeling, and field trials were validated by the increasing normalized post-stimulation PI with each optimization step.

High-viscosity friction reducers (HVFR) have been actively studied and implemented recently in fracturing as a proppant carrier fluid in unconventional reservoirs due to advantages over crosslinked fluids and linear gels. The vast majority of the known studies are performed in unconventional jobs, where pumping rates are significantly higher than in conventional fracturing treatments. A study was designed to answer the question how an HVFR can be used effectively in conventional treatments deep wells. The analysis was based on a propped fracturing case study in a deep live annulus well completed with relatively small inside diameter (ID) fracturing string. High friction, significant depth, low reservoir permeability, and abnormal pressure indicate that HVFR can be a replacement for the conventional heavy crosslinked gel under certain conditions. Thorough laboratory testing was performed to optimize the recipe of the HVFR for the given conditions. After analysis of the injection and calibration tests, the obtained HVFR efficiency, friction, and downhole behavior were used to optimize the main treatment. The fracturing was performed successfully, placing 26 tons of proppant into the fracture. Analysis of the treatment was performed in an advanced fracturing simulator with multi-physics model that is capable of modeling the complex proppant transport and redistribution processes within the fracture. Simulation results revealed that towards the end of the treatment, the increased concentration of the proppant resulted in accelerated proppant settling at the fracture bottom, leading to the step-like pressure-out. Treatment results and post-treatment simulations revealed that at given rates (15 to 17 bbl/min) and HVFR efficiency (∼21%), the carrying capacity of the HVFR is enough to place 26 tons of proppant at maximum concentration of 3.5 to 4.0 PPA with 28 to 30% pad percentage. The calibrated model showed that the created fracture has an effective half-length of about 75 m, fracture height of 50 m, and dimensionless fracture conductivity approximately equal to 4.5. A new fracture flowback optimization software was used to estimate the set the limits for drawdown during cleanup; the amount of the predicted proppant flowback (<100 kg) was proved by the top-of-proppant tag.

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Hydrocarbon production enhancement by means of acid stimulation in Kazakhstan requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of high-temperature carbonate reservoirs, thereby improving return on investment. Several robust chemical product solutions, coupled with comprehensive modeling in a new advanced simulator, have been successfully implemented to tackle the challenges and successfully increase the efficiency of matrix acidizing. To improve the productivity of stimulated wells by improving the effectiveness of acid treatments, a detailed study of reservoir rock and its reaction to various acid and fluid systems has been made via laboratory testing and software modeling. Sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Enhanced modeling of a novel retarded acid, viscoelastic diverting acid and particulate diverting systems demonstrated more uniform zone coverage, as well as deeper wormhole penetration. The above optimizations were field tested in several oil fields. Prior to any acid stimulation, the formation injectivity and damage profiles were calibrated based on the well pre-treatment production profile taken from production logs. As the first step, performance of the retarded acid was tested in several treatments. The bottomhole injection pressure decline behavior indicated that a slower reaction takes place during injection of the retarded acid compared to the stages of conventional hydrochloric acid, confirming the retarded nature of the acid as seen from the core tests. Secondly, viscoelastic self-diverting acid was added to the schedule for treatment of long intervals, replacing conventional gelled acid with shorter viscosity peak and lower retained permeability features. Better zone coverage, observed from injection pressure slope changes upon arrival of each diverter stage downhole, and improved post-acidizing formation cleanup were achieved as a result of this implementation. Third, field trials were made using combined application of the viscoelastic diverting acid and degradable particulate diverter pills. Full and uniform coverage of the entire zone of interest has been observed after pressure matching the actual treatments’ schedule and was validated by post-stimulation production logs. Field application of the approach supports the theoretical findings. Substantial improvement in well productivity was monitored after the application of each optimization step. The above approach demonstrates the value of thorough integration of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids. The efficiency of the approach is supported by multiple successful field case studies and is the recommended way forward for carbonate acidizing.