Evaluation of Damage Mechanisms in Tight Gas Reservoirs: Field Example from Perth Basin
- Nick Bahrami (SGS Netherlands) | Samaneh Soroush (SGS Netherlands) | Mofazzal Hossain (Curtin University) | Arshad Lashari (Universiti Teknologi Petronas) | Muhammad Daloma (PNOC EC) | Akim Kabir (Saudi Aramco)
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- Society of Petroleum Engineers
- SPE Saudi Arabia Section Annual Technical Symposium and Exhibition, 21-23 April, Al-Khobar, Saudi Arabia
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- Document Type
- Conference Paper
- 2015. Society of Petroleum Engineers
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Tight gas reservoirs represent a significant portion of natural gas reservoirs worldwide. Production at economical rates from tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. Tight gas reservoirs generally do not flow gas to surface at commercial rates, unless the well is completed using advanced technologies and efficiently stimulated.
One of the major damage mechanisms in tight gas reservoirs is liquid phase trapping damage that is controlled by pore system geometry, capillary pressure, relative permeability and interfacial tension between the invading trapped fluid and reservoir fluid. The liquid invasion damage into the rock matrix reduces the near wellbore permeability as a result of temporary or permanent trapping of liquid inside the porous media, and results in low productivity in tight gas reservoirs.
This study presents evaluation of damage mechanisms in tight gas reservoirs and the methods that can provide improved well productivity by minimizing damage to the formation. Numerical reservoir simulation is integrated with tight gas field data analysis and core flooding experiments to better understand the effect of different damage mechanisms on well productivity in order to propose the possible remedial strategies that can help achieve viable gas production rates from tight gas reservoirs.
Tight gas formations normally consist of numerous reservoir low permeability layers/lenses with different characteristics that may vary in shape and size, and are discontinuous both vertically and laterally separated by non-reservoir shales in a thick complex sedimentary system. In order to produce economically from such reservoirs, a long horizontal/deviated wellbore is required that can intersect the isolated sand lenses and connect them effectively to the wellbore through the high permeability conduits (Law and Curtis, 2002).
In tight formations, wellbore instability issues during drilling is a common problem, which results in large wellbore breakouts in the tight gas wells especially if the well is drilled under-balanced. In term of perforation efficiency in cased-hole completion system, tight reservoirs have high rock strength and penetration of the perforation jet into the tight formation may significantly be reduced compared with equivalent sandstone of higher porosity (Behrmann, 2000). The reduced jet penetration due to the rock tightness and the large wellbore breakouts filled by cement behind the casing, may cause penetration of the perforation jet into the tight formation not to be deep enough, and therefore the wellbore may not effectively be connected to the undamaged reservoir rock, causing low well productivity (Bahrami et al, 2011).
The rock matrix may primarily be composed of micro-pores where average pore throat aperture is very small, causing strong potential of capillary pressure energy suction. In tight formations that are water-wet in nature, the capillary forces cause liquid to be imbibed and held in the capillary pores. This causes the critical water saturation and the irreducible water saturation to be high in tight formations (Mahadevan et al, 2007). Tight gas reservoirs may have normal initial water saturation (Swi ~ Swc) or in some cases sub-normal (Swi<< Swc) as shown in Figure 1, due to water phase vaporization into the gas phase (Bennion and Brent, 2005). A sub-normal Swi relatively provides a higher effective permeability for gas phase, close to absolute permeability as shown in Figure 2-a. The initial water saturation might also be more than critical water saturation if the hydrocarbon trap is created during or after the gas migration time (Bennion and Thomas, 1996). For high initial water saturation, relative permeability to gas may be very low. Tight gas reservoirs often have large transition zones, that sometimes leads to mobile water and low relative permeability to gas. For ultra tight gas reservoirs there could be presence of a ‘permeability jail’, a saturation range in which gas and water can hardly flow as shown in Figure 2-b (Bennion and Brent, 2005).Economical development of tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. The tight formations generally do not flow gas to surface naturally at commercial rates, and must effectively be stimulated by a large hydraulic fracture treatment and/or be produced from a horizontal or multilateral wellbore (Holditch, 2006; Meeks et al., 2006).
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