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The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test.
Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve.
Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity.
We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions.
In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult.
Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 15-17 February 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material, and the capillary suction time (CST) test has become a standard test method. However, the CST test is designed to measure particle flocculation and specific filtration, and as such is not constructed to differentiate the relative impact of either clay swelling or wetting alteration effects. The CST test produces an amalgamated result of several processes and cannot be scaled back to one particular process.
Exploitation of shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments. Damage to the fracture conductivity and to the near-fracture matrix permeability caused by residual water can be avoided by optimizing fracture cleanup. The wide variation in mineralogy, texture and lithology of kerogen rich shales entails a substantial variation in the wetting characteristics of these rocks on all scales, whether one is comparing rock from different reservoirs, formations, or even different zones within a formation. It is therefore critical to evaluate shale/fluid interactions.
The contact angle is a quantitative measure of the relative wettability of a substrate with respect to two fluids brought into contact with it. To understand dynamic processes in the reservoir, dynamic contact angles need to be measured. Dynamic contact angles (advancing/imbibing and receding/draining fluids) differ substantially from static contact angles. For fracture cleanup the receding contact angle is most relevant. Obviously, static goniometer measurements that are presently used in the industry to infer fluid behavior within the rock matrix give wrong results that do not reflect the mixed wettability of shales with diverse pore types. The results of a macroscopic goniometer measurement, obtained on a polished surface cannot be projected down to pore scale with rough and diverse surfaces.
In this document, we present a rapid and practical method to measure the saturation dependent capillary pressure in a shale sample pack. A new method has been developed to measure threshold pressures and receding contact angles on freshly prepared shale and mudstone surfaces. We introduce a fluid retention ratio as a meaningful way to directly compare additive performance with regards to fracture cleanup.
This method is used to screen treatment fluid additives on a reasonably small amount of formation material. Rock samples from different shale formations have been tested with various additives. Measurement results show that different additives behave differently when exposed to shales from different reservoirs; different responses are even observed from well to well in the same reservoir and zone to zone in the same well.
As new reservoirs are developed and formations are exposed to various fluids, clay swelling and fines migration can cause serious damage. Clay stabilizers are generally added to mitigate these problems. However, the performance of formation stabilizers is not always properly assessed in the traditional analyses of formation samples. In general, laboratory testing with formation material is performed to define the best additive and concentration. Incorrect choice of stabilizer additives can result in severe damage from swelling and mobile formation clays. There appears to be no standard method for conducting formation stabilizer evaluations, therefore, it is difficult to make meaningful comparisons. Test methods based on the capillary suction time (CST) test or hot rolling lack any theoretical basis and may not show subtle effects.
A new test protocol incorporates several significant improvements over the traditional core flow methods. It considers important factors such as the critical salt concentration and the critical flow velocity. A key improvement is that the proposed method closely mimics pumping and cleanup operations actually encountered in field operations. The new test method is able to distinguish performance differences based upon both stabilizer chemistry and concentration.
Testing results from a moderately sensitive Berea core yielded a surprising finding: well-known organic stabilizers were only slightly more effective than de-ionized water, whereas inorganic salts were quite effective, even at low concentrations. Further, confirming findings by others, our results showed that the Berea core used in this study required no stabilization at 270°F.