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We present successful hydraulic fracture treatment practices in water sensitive tuffaceous reservoirs in Hailar Basin, China. The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracture treatments. The article describes the geological engineering framework, mineralogy investigation, hydrolytic weakening experiments, as well as application and results of new kinds of fracturing fluids. Rock mineralogy investigations indicated that rocks in the reservoir have a strong water sensitive property and a strong component of plastic behavior. Some tuffaceous rocks are rich in alkali minerals and become soft when exposed to aqueous fracture fluids. Although the fracture opening mechanism is the same as for normal sandstone, fracture extension is relatively suppressed and the fracture width is different from elastic predictions for normal sandstone. The analysis led to the changes in treatment stratages. The key difference from previous treatment is that clay content and concentration of different minerals were taken into consideration of fracture fluid design. Different kinds of emulsified fracturing fluid were designed used to mitigate swelling and hydrolytic weakening effects. By the end of 2005, 163 intervals in 66 wells have been treated using these new kinds of fracturing fluids, with a success rate of 97%. Introduction Massive hydraulic fracturing treatments in low-permeability sandstone reservoirs are common practices; wherease, stimulating tight, a volcanic-origin reservoir is far less common. Several reports of successful hydraulic fracturing treatments in volcanic reservoir rocks can be found; e.g., Weijers et al. (2002) reported fracturing practices in volcanic tight gas reservoirs in the Minami-Nagaoka gas field in Japan. Also, Antoci & Anaya (2001) discussed massive fracture treatments in tight gas zones in the Neuquen Basin (Argentina) where the lower parts of the oil zone are tuffaceous porphyrites. In recent years, tight tuffaceous reservoirs were discovered through exploration activities by Daqing Oilfield Ltd. in the Hailaer Basin. The Hailaer basin, together with the East Gobi Basin, and Tamsag Basin, are of a series of basins that formed in the China-Mongolia border region during a period of Late Jurassic-Early Cretaceous (Tse 2003, Johnson & Graham 2004). They have samiliar geological sedimentary structure and lithology. The basins are dominantaly nonmarine synrift sediment and volcanic flows fillings. The reduced porosity and permeability may be a concern because of rift-related volcanism and zeolite cements associated with volcanic input into saline-alkaline lakes. This system was eventually overwhelmed by volcanic debris during eruptions (Johnson & Graham 2004). Core analysis of the tuffaceous rock in Hailaer basin gave a porosity range of 5.6 to 21.7% (average 15.1%) and a permeability range of 0.03×10–3 to 27.4×10–3 µm2 (average 1.17×10–3 µm2). The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracturing treatments. The preliminary two field experiments of fracturing in the tuffaceous rocks (carried out in 2002) were failed. Figure 1 illustrates a standard pressure-time treatment curve for one layer in one well. In this case, after fracture initiation, the stable fracture fluid injection pressure was ~26 MPa at the pump. Proppants experienced sudden tip screen-out when the concentration reached 200 kg/m3, preventing further fracture propagation into the reservoir.
We present successful hydraulic fracture treatment practices in water sensitive tuffaceous reservoirs in Hailar Basin, China. The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracture treatments. The article describes the geological engineering framework, mineralogy investigation, hydrolytic weakening experiments, as well as application and results of new kinds of fracturing fluids. Rock mineralogy investigations indicated that rocks in the reservoir have a strong water sensitive property and a strong component of plastic behavior. Some tuffaceous rocks are rich in alkali minerals and become soft when exposed to aqueous fracture fluids. Although the fracture opening mechanism is the same as for normal sandstone, fracture extension is relatively suppressed and the fracture width is different from elastic predictions for normal sandstone. The analysis led to the changes in treatment stratages. The key difference from previous treatment is that clay content and concentration of different minerals were taken into consideration of fracture fluid design. Different kinds of emulsified fracturing fluid were designed used to mitigate swelling and hydrolytic weakening effects. By the end of 2005, 163 intervals in 66 wells have been treated using these new kinds of fracturing fluids, with a success rate of 97%. Introduction Massive hydraulic fracturing treatments in low-permeability sandstone reservoirs are common practices; wherease, stimulating tight, a volcanic-origin reservoir is far less common. Several reports of successful hydraulic fracturing treatments in volcanic reservoir rocks can be found; e.g., Weijers et al. (2002) reported fracturing practices in volcanic tight gas reservoirs in the Minami-Nagaoka gas field in Japan. Also, Antoci & Anaya (2001) discussed massive fracture treatments in tight gas zones in the Neuquen Basin (Argentina) where the lower parts of the oil zone are tuffaceous porphyrites. In recent years, tight tuffaceous reservoirs were discovered through exploration activities by Daqing Oilfield Ltd. in the Hailaer Basin. The Hailaer basin, together with the East Gobi Basin, and Tamsag Basin, are of a series of basins that formed in the China-Mongolia border region during a period of Late Jurassic-Early Cretaceous (Tse 2003, Johnson & Graham 2004). They have samiliar geological sedimentary structure and lithology. The basins are dominantaly nonmarine synrift sediment and volcanic flows fillings. The reduced porosity and permeability may be a concern because of rift-related volcanism and zeolite cements associated with volcanic input into saline-alkaline lakes. This system was eventually overwhelmed by volcanic debris during eruptions (Johnson & Graham 2004). Core analysis of the tuffaceous rock in Hailaer basin gave a porosity range of 5.6 to 21.7% (average 15.1%) and a permeability range of 0.03×10–3 to 27.4×10–3 µm2 (average 1.17×10–3 µm2). The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracturing treatments. The preliminary two field experiments of fracturing in the tuffaceous rocks (carried out in 2002) were failed. Figure 1 illustrates a standard pressure-time treatment curve for one layer in one well. In this case, after fracture initiation, the stable fracture fluid injection pressure was ~26 MPa at the pump. Proppants experienced sudden tip screen-out when the concentration reached 200 kg/m3, preventing further fracture propagation into the reservoir.
Because of the special characteristics of the tight-shale gas formations, the conventional concepts of hydraulic fracturing may become irrelevant, and the new concepts must be consequently developed to optimize the stimulation process for the tight formations. This paper focuses on improving the understanding of fracturing tight-shale gas formations through parametric sensitivity analysis of a case study. The concepts of stimulating tight formations were better understood by examining the end impacts of some critical factors, such as: a) leak-off percentage in relation to the tight-shale gas formations, b) screenout in relation to the net pressure signatures, and c) injection rate and proppant concentration in relation to the fracturing efficiency, etc. With reference to these observations, applying the proposed alternative approaches appears to be imperative to enhance the current stimulation technologies for tight-shale gas formations.
Frac-packs, and hydraulic fracturing, have become accepted, successful completion procedures for high permeability formations. To some extent, this success has come despite less than full understanding of the processes. Statements such as "fracture models cannot predict net pressure behavior in soft rocks" are heard. Inconsistencies are blamed on radical departures from "classical" theories of fracturing, and in some instances, this may be warranted. However, it is best to first examine simpler possibilities (Occam's Razor). Radical departures should not be postulated until fracture models routinely address actual geologic/reservoir environments. What is the big difference for high permeability fracturing? Of course, it is not "soft" rock, it is permeability, thus, fluid loss. ALL fracture designs are based on the idea of 1D, i.e., Carter or C/ t, loss, and assume (with no justification) this is valid. High loss is accounted for by high fluid loss coefficients, but using high values for something does not describe the process. One possible cause of the inconsistency might be non-1D, i.e., non-Carter type, loss behavior. Non-1D fluid loss occurs in water injection/water disposal fractures (though "normal" fracture models are still mistakenly utilized in these situations). 1D loss is valid if the fracture propagation is greater than loss velocity, and this condition is NOT true for water flood induced fracturing. Is this true for high permeability fracturing - with fluid efficiency < 10%, even in propped fracturing treatments using viscous fluids? This paper examines this question using a coupled 3D fracture-reservoir model (as described in Appendix A) to accurately simulate fluid loss. We simulate several field cases, review the design/post-analysis based on "traditional" loss behavior, and examine the effect of rigorously simulating loss. The results are used to identify conditions where non-Carter fluid loss is significant, and how to modify designs appropriately. Introduction In what has to be the most quoted "Appendix" in history, Carter1 laid out the basis for "1-D", or "Carter", or "C/Time" fluid loss behavior. This theoretical development has certainly stood the test of time, and has been the mainstay of fracture models and treatment designs for near five decades. Since that work, fracturing has moved from relatively small treatments in moderate-to-high permeability formations (where actually the use of "Carter" fluid loss might have been questionable), to massive fracturing of very low permeability formations (where the "Carter" fluid loss assumption was absolutely justified), to propped fracturing in very high permeability formations for stimulation and sand control (where once again the use of "Carter" fluid loss should be questioned). That is the subject of this presentation, to review the use of this fluid loss assumption by looking at existing work, by studying case histories, and to try to set some limits on when/where "1-D" fluid loss calculations are appropriate.
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