The concept and the accumulation characteristics of unconventional hydrocarbon resources
- 2.7k Downloads
Unconventional hydrocarbon resources, which are only marginally economically explored and developed by traditional methods and techniques, are different from conventional hydrocarbon resources in their accumulation mechanisms, occurrence states, distribution models, and exploration and development manners. The types of unconventional hydrocarbon are controlled by the evolution of the source rocks and the combinations of different types of unconventional reservoirs. The fundamental distinction between unconventional hydrocarbon resources and conventional hydrocarbon resources is their non-buoyancy-driven migration. The development of the micro- to nano-scale pores results in rather high capillary resistance. The accumulation mechanisms of the unconventional and the conventional hydrocarbon resources are also greatly different. In conventional hydrocarbon resources, oil and gas entrapment is controlled by reservoir-forming factors and geological events, which is a dynamic balance process; while for unconventional hydrocarbon resources, the gas content is affected by the temperature and pressure fields, and their preservation is crucial. Unconventional and conventional hydrocarbons are distributed in an orderly manner in subsurface space, having three distribution models of intra-source rock, basin-centered, and source rock interlayer. These results will be of great significance to unconventional hydrocarbon exploration.
KeywordsUnconventional hydrocarbon resources Non-buoyancy-driven accumulation Accumulation mechanisms Distribution model
Unconventional hydrocarbon resources are becoming increasingly significant in global energy structures. Global petroleum exploration is currently undergoing a strategic shift from conventional to unconventional hydrocarbon resources. Unconventional hydrocarbon resources (including tight oil/gas, shale oil/gas, and coal bed gas) are becoming a significant component of world energy consumption (Jia et al. 2012; Zou 2013). Unconventional hydrocarbon resources are distinct from conventional hydrocarbon resources. The characteristics of the unconventional hydrocarbon resources are as follows: the source and the reservoir coexist; the porosity and the permeability are ultra-low; nano-scale pore throats are widely distributed; there is no obvious trap boundary; buoyancy and hydrodynamics have only a minor effect, Darcy’s law does not apply; phase separation is poor; there is no uniform oil–gas–water interface or pressure system; and oil or gas saturation varies (Sun and Jia 2011; Yang et al. 2013). Unconventional hydrocarbons in tight reservoirs show characteristics distinct from those of the hydrocarbon sources hosted in structural and stratigraphic traps. Unconventional petroleum geology differs from traditional petroleum geology in terms of trap conditions, reservoir properties, combination of source and reservoir rocks, accumulation features, percolation mechanisms, and occurrence features, so different reservoir conditions and accumulation mechanisms are essential for unconventional hydrocarbon accumulation (Zou et al. 2012). According to the relationship between source rock evolution and reservoir formation, we clarify the relations of various unconventional hydrocarbon resources, propose the identification marks and distribution models for unconventional hydrocarbon resources, and compare the differences between unconventional and conventional hydrocarbon in terms of types, characteristics, distribution models, and accumulation mechanisms, which provide important guidance for unconventional hydrocarbon exploration (Zou et al. 2015).
2 Concept of unconventional hydrocarbon resources
2.1 Generation of unconventional hydrocarbon resources
2.2 Identification marks of unconventional hydrocarbons
Non-buoyancy-driven accumulation means that hydrocarbon accumulation is driven by forces excluding buoyancy. Unconventional hydrocarbon resources have the characteristics of coexisting source rocks and reservoirs, no obvious trap boundaries, weak fluid phase differentiation, no uniform water–oil interface, independent pressure system, and oil or gas saturation varying significantly (Zou et al. 2011; Ju et al. 2015). There is a fundamentally important geological distinction between conventional and unconventional hydrocarbon. Conventional gas resources are buoyancy-driven deposits, occurring as discrete accumulations in structural and/or stratigraphic traps, whereas unconventional gas resources are generally non-buoyancy-driven accumulations. Non-buoyancy-driven accumulation means that buoyancy has a weak effect on hydrocarbon migration and cannot overcome resistance.
2.2.1 Key reason of non-buoyancy-driven accumulation
Capillary pressure is the principle resistance for hydrocarbon migration, which is controlled by the radius of pore-throats of reservoirs. The narrower the pore-throats, the higher the capillary pressure. Thus, the key reason of non-buoyancy-driven accumulation of unconventional hydrocarbon can be attributed to small pore-throats of reservoirs. By advanced experimental test methods, it has been proved that the widely developed micro–nano-pore-throats lead to large resistance due to high capillary pressure (Loucks and Ruppel 2007). The statistical analysis of global tight reservoirs’ pore-throat diameters shows that the shale reservoirs have the minimum pore-throat diameters, while the tight sandstones have relatively larger pore-throat diameters (Nelson 2009; Zou et al. 2011; Passey et al. 2011). The average pore-throat diameter of the shale gas reservoirs is 5–200 nm (Jarvie et al. 2007), that of the shale oil reservoirs is 30–400 nm (Montgomery et al. 2005), that of the tight gas reservoirs is 40–700 nm, that of the tight sandstone oil reservoirs is 50–900 nm, and that of the tight carbonate oil reservoirs is 40–500 nm (Jia et al. 2012; Du et al. 2014). The development of micro–nano-pores leads to high capillary pressure in the pore structure of reservoirs. If the diameter of pores is 10–50 nm, then the calculated capillary pressure of those pores could be 12–24 MPa (Zhang et al. 2014), indicating that at least under such strength of driving force (buoyancy or abnormal pressure), hydrocarbon could be capable of migrating.
2.2.2 Mechanisms of non-buoyancy-driven accumulation
Within conventional petroleum systems, buoyancy is considered to be the driving force, and capillary pressure is the resistance for hydrocarbon migration and accumulation (Davis 1987). According to the equation of buoyancy and capillary pressure (Schowalter 1979), when the radius of pore-throats decreases by 10 %, the capillary pressure would increase tenfold. If buoyancy is still considered to be the driving force, then hydrocarbon migration would happen only when buoyancy correspondingly increases tenfold. Taking one gas column with a height of 3 m and density of 0.2 g/cm3 for an example, the buoyancy can be 0.024 MPa, but gas cannot enter the pore-throats with a radius of 2 μm. The pore-throat diameter of tight sandstones is mostly less than 1 μm, the capillary pressure is at least more than 0.08 MPa. However, migration of gas with a density of 0.2 g/cm3 needs a buoyancy of 0.07 MPa, and the height of the gas column required would be over 10 m. Based on the research of outcrops, thickness measurements, and profile interpretation, the fluvial sandbodies with a vertical thickness over 10 m are scarce (Shanley 2004). Therefore, no favorable geological conditions for gas columns can form enough buoyancy, and buoyancy could not be the dominant driving force for unconventional oil and gas accumulation.
3 Characteristics of unconventional hydrocarbon accumulation
The differences between unconventional and conventional hydrocarbons in occurrence and accumulation processes determine the differences in accumulation mechanisms. In order to better understand the characteristics of unconventional hydrocarbon accumulation, unconventional gas reservoirs characterized by adsorbed gas are taken as examples to compare with conventional gas reservoirs.
3.1 The unconventional gas content is affected by temperature and pressure fields while the conventional gas content is controlled by dynamic balance
Conventional gas accumulation can be divided into two processes: natural gas generated and expelled from source rocks migrates and accumulates in reservoirs, and then it is continuously lost by diffusion and seepage. Conventional gas accumulation is the consequence of the balance of gas charge and loss, namely the dynamic balance. Thus, the intensity and time of gas charge and sealing conditions are the key factors to natural gas accumulation.
3.2 Unconventional gas accumulation is controlled by preservation, while the conventional hydrocarbon accumulation is controlled by the best match of petroleum systems
Conventional gas accumulation generally experiences processes of gas generation, migration, concentration, and preservation. The best match of static factors such as source rocks, reservoirs, and caprocks and the dynamic factors such as natural gas generation, migration, entrapment, and accumulation controls the hydrocarbon accumulation periods.
CBM loss is primarily due to tectonic uplift and pressure–temperature changes, which result in desorption of gas. There are three diffusion paths for reservoir gas. First, free gas diffuses by overcoming capillary pressure of sealing rocks (Song et al. 2007). Second, dissolved gas in water diffuses because of a concentration difference. Third, gas is flushed directly by flowing water (Qin et al. 2005). Thus, tectonic evolution, hydrodynamics, and sealing conditions are three major controlling factors for CBM accumulation and enrichment (Song et al. 2012).
CBM reservoir accumulation depends on the preservation conditions resulting from tectonic uplift. The higher the coal seam is uplifted, the poorer the preservation conditions will be. During tectonic uplifting when gas generation ceased, if the coal seam was uplifted to a depth still below the present weathering zone, CBM would be preserved through enhanced adsorption capacity (Song et al. 2005). The CBM abundance is then dependent on the thickness of the overlying strata. The thicker the overlying strata are, the higher the CBM abundance will be (Fig. 6). The formation of unconventional gas reservoirs is controlled by the key time of structural evolution, which is different from the charge time of the conventional gas.
3.3 Synclinal accumulation of unconventional gas is controlled by water potential and pressure and conventional gas is distributed in structural highs under control of gas potential
Conventional gas is featured by accumulation in structural highs under control of gas potential. Regionally, unconventional gas is characterized by synclinal accumulation mainly controlled by water potential and pressure field. A low potential area enclosed by high potential layers is located in reservoirs. The low potential area with high porosity and permeability is a favorable area for hydrocarbon accumulation and preservation, indicating that the oil and gas potential controls the accumulation of conventional hydrocarbon. Low potential is generally located at structural highs and is the migration direction, so the conventional hydrocarbon mainly accumulates in the anticline structures.
4 Distribution characteristics of unconventional hydrocarbon
4.1 Coexistence of unconventional and conventional hydrocarbon
Accumulation mechanisms of different unconventional hydrocarbons
Conventional oil and gas
Tight oil and gas
Shale oil and gas
Coal bed methane
d > 2 μm
2 μm > d > 0.03 μm
0.1 μm > d > 0.0005 μm
d > 2 μm
Long distance migration through preferential pathways, secondary migration
Driven by pressure difference, short-distance migration
Adsorption and free gas, primary migration
Relationship with source rocks
Distant from source rocks
Near source rocks
In source rocks
In source rocks
4.2 Distribution models of unconventional hydrocarbon
Three models of unconventional hydrocarbon distribution can be determined in petroliferous basins, namely the intra-source rock model, the basin-centered gas model, and the source rock interlayer model.
4.2.1 The intra-source rock model
4.2.2 The source rock interlayer model
4.2.3 The basin-centered gas model
The types of unconventional hydrocarbon resources include oil shale, tight oil/gas, shale oil/gas, and CBM. These are controlled by the evolution of source rocks and the combinations of different unconventional reservoirs.
The fundamental differences of unconventional hydrocarbon from conventional hydrocarbon resources are tight reservoir properties, non-buoyancy-driven migration, and no obvious trap boundary. The essential reasons for non-buoyancy-driven accumulation are widespread micro- and nano-scale pores, the resistance of high capillary pressure in tight reservoirs and lack of formation conditions providing strong buoyancy.
The differences in occurrence and accumulation processes between unconventional and conventional hydrocarbon result from the great differences in accumulation mechanisms. For unconventional hydrocarbon, subsurface temperature–pressure fields control the gas content, preservation conditions affect the critical time for hydrocarbon accumulation, and water potential and pressure result in accumulation in synclines. For the conventional hydrocarbon resources, dynamic balance processes control the hydrocarbon accumulation, the best match of reservoir-forming factors and geological events controls the entrapment time, and gas potential controls the accumulation in structural highs.
Unconventional and conventional hydrocarbons coexist and are distributed in an orderly manner in sedimentary basins. The unconventional hydrocarbon has three distribution models, namely the intra-source rock model, the basin-centered gas model, and the source rock interlayer model.
This research was supported by Major Projects of Oil and Gas of China (No. 2011ZX05018-002). We thank Profs. Zou Caineng, Jiang Zhenxue, and anonymous reviewers for their critical and constructive comments. We also thank Ji Wenming and Xiong Fengyang for improving the English of the manuscript.
- Curtis JB. Fractured shale-gas systems. AAPG Bull. 2002;86(11):1921–38.Google Scholar
- Dai JX, Pei XG, Qi HF. Natural gas geology in China, vol. Vol. 1. Beijing: Petroleum Industry Press; 1992. p. 118–31 (in Chinese).Google Scholar
- Davis RW. Analysis of hydrodynamic factors in petroleum migration and entrapment. AAPG Bull. 1987;71(6):643–9.Google Scholar
- Du JH, He HQ, Yang T. Progress in China’s tight oil exploration and challenges. China Pet Explor. 2014;19(1):1–9 (in Chinese).Google Scholar
- Huang DF, Li JC, Zhou ZH, et al. Evolution and hydrocarbon generation mechanism of continental organic matter. Beijing: Petroleum Industry Press; 1984 (in Chinese).Google Scholar
- Jia CZ, Zou CN, Li JZ, et al. Assessment criteria, main types, basic features and resource prospects of the tight oil in China. Acta Pet Sin. 2012;33(3):344–50 (in Chinese).Google Scholar
- Li W, Zou CN, Yang JL, et al. Types and controlling factors of accumulation and high productivity in the upper Triassic Xujiahe Formation gas reservoirs, Sichuan Basin. Acta Sedimentol Sin. 2010;18(5):1037–45 (in Chinese).Google Scholar
- Passey QR, Bohacs KM, Klimentidis RE, et al. My source rock is now my shale-gas reservoir—Characterization of organic-rich rocks. AAPG Annual Convention. Houston, Texas; 2011.Google Scholar
- Schowalter TT. Mechanics of secondary hydrocarbon migration and entrapment. AAPG Bull. 1979;63(5):723–60.Google Scholar
- Shanley K W. Fluvial reservoir description for a giant low permeability gas field: Jonah field, Green River Basin, Wyoming, USA. AAPG studies in geology 52 and Rocky Mountain Association of Geologists 2004 Guidebook. 2004; 52:159–82.Google Scholar
- Song Y, Jiang L, Ma XZ. Formation and distribution characteristics of unconventional oil and gas reservoirs. J Palaeogeogr. 2013;15(5):677–86 (in Chinese).Google Scholar
- Song Y, Qin SF, Zhao MJ. Two key geological factors controlling the coalbed methane reservoirs in China. Nat Gas Geosci. 2007;18(4):545–52 (in Chinese).Google Scholar
- Sun ZD, Jia CZ. Exploration and development of unconventional hydrocarbon. Beijing: Petroleum Industry Press; 2011. p. 67–70 (in Chinese).Google Scholar
- Wang FP, Reed RM. Pore networks and fluid flow in gas shales. Paper SPE124253 presented at the SPE annual technical conference and exhibition. New Orleans, Louisiana, 4–7 October 2009.Google Scholar
- Zhang HF, Zhang WX. Petroleum geology. Beijing: Petroleum Industry Press; 1981 (in Chinese).Google Scholar
- Zou CN, Tao SZ, Hou LH. Unconventional hydrocarbon geology. Beijing: Geological Publishing House; 2011. p. 33–56 (in Chinese).Google Scholar
Open AccessThis article is distributed under the terms of the Creative Commons Attribution 4.0 International License (http://creativecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons license, and indicate if changes were made.