Understanding Unconventional Gas Reservoir Damages

Abstract

It is estimated that there are large reserves of unconventional gas located throughout the world, including coalbed methane, shale gas and tight gas sands. Due to their specific characteristics—particularly low permeability in the microdarcy range, microfractures and high capillary pressures—unconventional gas reservoirs are vulnerable to irreversible damage during ex-ploitation. This paper focuses on studies of damage evaluation in unconventional gas reservoirs around the world. We aim to provide a set of guidelines to avoid, minimize and/or remediate this damage. In Brazil, the Petrobras Strategic Plan for 2020 predicts 200% growth in gas production until 2020, as compared to 2010 gas production. Expected growth in international gas production will be 30% until 2020, as compared to 2010 world gas pro-duction. The main natural gas production projects of Petrobras between 2010 and 2014 are Mexilhão, Uruguá and Tambaú Cidade de Santos, totaling 35,000 BOE per day. Demand for natural gas is expected to increase from 46 million m3/day (2009) to 130 million m3/day until 2014, envisaging use in electrical power, industrial, fertilizer and other applications. The fundamental processes causing formation damage include but are not limited to physicochemical, chemical, hydro-dynamic, mechanical, thermal and biological. Formation damage is not necessarily reversible, and therefore it should be avoided. Laboratory tests are designed to determine, understand and quantify the governing processes, their dependency on the in-situ and operational conditions, and their effect on formation damage. It should be emphasized that on one hand, high capillary pressure favors the spontaneous imbibition phenomenon and, consequently, mainly water-blocking damage. On the other hand this same effect has been investigated by several researchers to change the reservoir wettability by optimizing rock-fluid interactions using specific surfactant-brine systems during exploi-tation. It has been concluded that, beyond formation evaluation, phenomenological observations and the optimization of rock-fluid interactions are likely to promote gas production from minimally damaged unconventional reservoirs. Introduction Reservoirs that originally contain free gas as the only hydrocarbon source are termed gas reservoirs. These reservoirs store a mixture of hydrocarbon compounds that exist entirely in the gaseous state. The gas may be ‘dry,’ ‘wet,’ or ‘condensate,’ depending on its composition, as well as the pressure and temperature at which the accumulation occured1. A natural-gas source is named an unconventional gas reservoir when the well must be stimulated by large hydraulic fracture treatment, ho-rizontal wellbores or multilateral wellbores to produce at economic flow rates or volumes2. Similar to conventional hydrocarbon sources, unconventional gas reservoirs present complex geological characteristics, as well as heterogeneities at all scales. Unconventional gas reservoirs, though, typically have very fine-grain rock size distribu-tion, gas storage and flow regimes influenced by the tight pore throat. Grain rock size distribution and organic and clay con-tent can promote favorable bonds between the gas molecules and the rock surface3. The three major categories of unconven-tional gas reservoirs are coalbed methane, tight gas sands and shale gas2. In terms of pore structure, shale gas reservoirs typically present dimensions at the nanometer to micrometer size, while tight gas sands present pores in the micrometer or larger size3. Coalbed methane systems are naturally fractured and can present two distinct porosity patterns: one primary composed of micropores with extremely low permeability; and one sec-ondary composed of macropores with a natural fracture network of cracks and fissures1. One important aspect to consider for unconventional gas reservoirs due to their lower permeability in contrast to high permeability reservoirs, is that the effects of capillary pressure are significant4,5. All these characteristics make unconventional gas reservoirs more susceptible to damage during exploratory phases and processes6.

New Insight into Enhancing Organic-Rich Shale Gas Recovery: Shut-in Performance Increased through Oxidative Fluids

“…Thirdly, over ten thousand cubics of fracturing fluids is pumped into a shale gas well to create the required fracture network for production. Nevertheless, over 70% of fracturing fluids are retained in the formation after the flowback operations, which induces some formation damage such as aqueous phase trapping (APT) or clay swelling, impairing the performance of the fracturing stimulation [29][30][31][32]. Reducing the amount of the retained fluid and shortening the water-rock interaction time through fast flowback operations after hydraulic fracturing can facilitate the reduction of these formation damages [33][34][35][36][37][38].…”

Experimental Evaluation of Permeability Damage to No.15 Coal Seam in the Qinshui Basin

“…As a result, we reveals the mechanism of fracturing fluid on permeability of CBM reservoirs from micro perspective. * Permeability is often used to characterize flow capability of CBM (Chen et al, 2006;Lucas, et al, 2011). Permeability test includes steady state method and unsteady method.…”