A new technique for characterizing secondary and tertiary reactions during sandstone matrix stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent element concentrations, batch reactor experiments and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial flow setups, are reviewed.
The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%.
Recent studies on matrix stimulation have strongly emphasized the importance of secondary and tertiary reactions in determining the success of matrix stimulation treatments.1,2 However, the extent of these reactions under reservoir conditions is difficult to quantify. Several factors make the traditional acid response tests on short reservoir cores inadequate for characterizing secondary and tertiary reactions. First, secondary and tertiary reactions are slower than primary reactions, and so much longer fluid residence times in the core are required to observe these reactions. Second, linear flow along the axis in cylindrical cores is not representative of radial flow in a reservoir treatment. Third, cores used in the core tests may not be representative of the entire treatment interval.
Fig. 1 illustrates the limitations of traditional core flow tests. Fig. 1a shows that a core plug is a small sample of the area of interest. For formations in which the mineralogy changes significantly in the pay zone interval, a single core plug will not be representative of the entire treatment interval.
Fig. 1b shows an example of how a traditional core flow test to evaluate two fluids on a short reservoir core can lead to erroneous conclusions. Shown in the figure are permeability profiles in a simulated reservoir treatment after injection of 50 gal/ft of acetic acid preflush followed by 100 gal/ft each of (i) 12/3 mud acid and (ii) an organic fluoboric acid. In both cases the reservoir was undamaged prior to treatment. 12/3 mud acid provides good stimulation near the wellbore, but causes damage deeper in the reservoir. The organic fluoboric acid achieves a lesser stimulation near the wellbore but also causes lesser damage deeper in the reservoir than 12/3 mud acid. The post-treatment skin for the organic fluoboric acid is –0.5, compared to a skin of 2 for the 12/3 mud acid. The organic fluoboric acid is, therefore, a better fluid for the reservoir treatment. However, if these two fluids were evaluated with a traditional core flow test, 12/3 mud acid would have been erroneously selected because it provides better stimulation at the length scale of the core (~4 in.). Therefore, core tests on short cores by themselves are inadequate for fluid selection for matrix treatments. For accurate evaluation of a proposed stimulation design, it is necessary to account for the formation damage caused by secondary and tertiary reactions, which are typically not observed in tests on short cores.
The following is a brief review of the techniques suggested in the literature to quantify secondary and tertiary reactions and to overcome limitations of tests on short cores.