First Massive Hydraulic Fracturing Treatment in Argentina

Antoci, Juan C.; Anaya, Luis Antonio

doi:10.2118/69581-ms

Cited by 6 publications

(2 citation statements)

References 7 publications

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“…Since its introduction in the late 1940s, hydraulic fracturing has been widely used in North America to achieve higher recovery from low permeability reservoirs and/or to bypass the formation damage around the wellbore (Economides, et al, 2002). In addition, successful applications of this technique have been reported in other locations including North Sea (Vos, et al, 2009), South America (Antoci and Anaya, 2001), Asia (Shaoul, et al, 2007) and Middle East (Al-Zarouni and Ghedan, 2012) and (Mirzaei-Paiaman, 2013). Generally, many steps of analysis are performed prior to any hydraulic fracturing job to ensure its effectiveness.…”

Section: Introductionmentioning

confidence: 98%

Evaluation of heterogeneity impact on hydraulic fracturing performance

Parvizi

Gomari

Nabhani

et al. 2017

Journal of Petroleum Science and Engineering

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Section: Introductionmentioning

confidence: 98%

Evaluation of heterogeneity impact on hydraulic fracturing performance

Parvizi

Gomari

Nabhani

et al. 2017

Journal of Petroleum Science and Engineering

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“…Sea (Vos, et al, 2009), South America (Antoci & Anaya, 2001), Asia (Shaoul, et al, 2007) and Middle East (Al-Zarouni & Ghedan, 2012) have been reported.…”

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confidence: 99%

Hydraulic Fracturing Performance Evaluation in Tight Sand Gas Reservoirs with High Perm Streaks and Natural Fractures

et al. 2015

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Hydraulic fracturing in tight gas sandstone reservoirs increases the connectivity of the well to more reservoir layers and farther areal regions, thus boosting the production as well as the net-present-value of the project. When comparing different well performances, wells that far outperform other wells are usually connected to high permeability streaks or natural fractures. This paper demonstrates the analysis and performance evaluation of hydraulic fractures that are connected to high permeability streaks or natural fractures.In order for oil and gas operators to consider the development of tight gas sandstone reservoirs economically feasible, stimulation operations such as a large hydraulic fracture treatment of the wells are required. However, the induced fracture is not the main reason for the success of many of the field development in tight gas sandstone reservoirs. In the Southern North Sea, the more productive multiple hydraulically fractured horizontal wells (MHFHW) are usually connected to high permeability streaks or natural fractures. In this work, a reservoir with high permeability streaks and natural fractures was then modelled. This is then calibrated against several years of production and pressure history.The analysis of core data, borehole image logs, well tests and geomechanics data demonstrated the existence of high permeability streaks or natural fractures in the reservoir. The data derived from the analytical methods were then captured in the simulation model. The simulation model shows a very good match with the history data and when compared with a 3-week long shut-in, the build-up pressure response and its derivative displayed an excellent match. This study shows that, in addition to the role played by the hydraulically induced fractures, natural fractures and high permeability streaks also serve as dominant factors in success of tight gas sandstone reservoir development.This study demonstrates a practical integrated approach towards the modelling of high permeability streaks and natural fractures that are connected to hydraulic fractures. This can be used to better understand hydraulic fracturing and tight gas sandstone reservoirs in the Southern North Sea.

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Fracturing Water-Sensitive Tuffaceous Reservoirs

et al. 2007

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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.

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First Massive Hydraulic Fracturing Treatment in Argentina

Cited by 6 publications

References 7 publications

Evaluation of heterogeneity impact on hydraulic fracturing performance

Evaluation of heterogeneity impact on hydraulic fracturing performance

Hydraulic Fracturing Performance Evaluation in Tight Sand Gas Reservoirs with High Perm Streaks and Natural Fractures

Fracturing Water-Sensitive Tuffaceous Reservoirs

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