Acidizing treatments in carbonates often result in significant skin decrease due to high reactivity of the formation with acids. Noticeable production increase or inability to run analysis tools after the treatment may lead to the conclusion that the matrix acidizing job was performed efficiently, when, in fact, the job was not optimized in terms of fluid volumes, acid types, wellbore coverage, and pumping rates. As a result, the final skin is not as low as it could be, and, most importantly, medium - and long-term post-acidizing production decline is faster than it could be with an optimized treatment. To overcome these concerns, an integrated approach to acidizing treatments was implemented for different oil fields in Kazakhstan. The integrated approach consists of comprehensive laboratory testing, which includes core flow tests with subsequent 3D computer tomography scanning. The tests help to determine wormholing regimes and channel geometry while providing calibration points for acid-rock interaction curves. These coefficients are used in the acidizing modeling software, which enables optimization of fluid volumes, pumping rates, and diversion strategy. The approach suggests the use of a single-phase retarded acid system is the most effective method of keeping the treatment in the dominant wormhole regime, especially at elevated temperature. The integrated approach loop is closed by the analysis of the distributed temperature sensor data to calibrate the efficiency of diversion and reservoir injectivity profile. The approach was introduced for different oil fields in Kazakhstan, with a variety of conditions: depths up to 5000 m and temperatures up to 145°C. The approach helped to optimize acid volumes by as much as 44% to achieve an optimum skin. In the mid-term perspective, this approach helped to reduce the production decline rate by at least 20%, and ongoing post-treatment analysis is even more promising.

Important factors affecting acid fracturing efficiency include etched fracture geometry, cleanup, and optimum differential etching to retain open channels after fracture closure. A recently applied integrated approach combined improvements in all three factors: new fracture simulation techniques enabled fracture geometry optimization, single-phase retarded acid provided significant increase in half-length, and high retained permeability viscous fluids supported better fracture cleanup. The approach was successfully implemented in several carbonate oil fields and resulted in a substantial productivity index increase. The approach enables acid fracture optimization in three steps. First, the high retained permeability, low-pH pad fluids and polymer-free leakoff control acids are used in combination to enhance formation cleanup after a treatment and to reduce the concentration of polymers in fissures network of naturally fractured carbonate reservoirs. Second, a new single-phase retarded acid is used to achieve longer half-length due to retarded reaction with formation rock and favorable viscous fingering effects. Third, a new acid fracturing simulation model is used to optimize fracture geometry. The simulation technique employs an innovative transport model that includes the viscous fingering effect, advanced leakoff simulation, changing acid rheology upon spending, and a novel calculation approach to mixed fluids' rheology. This combined concept was applied during acid fracturing treatments in moderate permeability wells of carbonate reservoirs with target intervals up to 4,600 m TVD and temperatures up to 125°C. The treatments consisted of guar-free low-pH pad fluid, polymer-free leakoff control acid, and single-phase retarded acid. Treatment optimization was performed using an advanced acid fracturing simulator to properly address the transport processes within the fracture in a low-stress-contrast environment. After the treatments, the pressure transient analysis indicated a strong linear regime for more than 15 hours, indicating effective fracture half-length at least 25% higher than average half-length after acid fracturing in offset wells where the conventional approach had been applied. Post-treatment half-length calculations showed a good match with advanced simulator results and proved the importance of accounting for viscous fingering effects during acid fracture half-length calculations. Calculation of the productivity index from the production data showed at least 15% increase compared to conventional acid fracturing treatments. The post-fracturing production decline rate was at least 20% slower than that of the conventional treatment in offset wells, which can be explained by the longer conductive fracture.

The use of conventional acid systems in high-temperature, fast-reactive carbonate reservoirs limits the effectiveness of matrix acidizing and acid fracturing. Therefore, during acid stimulation in such conditions, acids with retarded reaction are usually recommended. Industry-employed retarded acid systems have several significant drawbacks—they either dissolve lower rock volume or have higher friction and are more complex to mix than the standard hydrochloric acid system. The introduction of a new single-phase retarded acid enabled minimizing these drawbacks. The sustained increase in productivity index (PI) after the acid fracturing and matrix acidizing treatments under high-pressure/high-temperature conditions was achieved. The treatments were performed on exploration wells drilled in carbonate oil fields of the pre-Caspian and Mangystau oil-bearing provinces of West Kazakhstan.

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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