Reservoir Geo-mechanics: Biot’s Coefficient
1. How important is the concept of Biot’s coefficient (involved in Biot’s effective stress relationship which assumes that total isotropic confining stress remains equal to the sum of effective stress and the pore fluid pressure multiplied by Biot’s coefficient) towards characterizing a petroleum reservoir?
Feasible to determine Biot’s coefficient for a low-porous and low-permeable reservoir @ laboratory-scale considering the time required to reach equilibrium of reservoir pore fluid pressure? 2. Feasible to validate the following two basic aspects @ field-scale associated with a petroleum reservoir, when reservoir pressure remains to be lesser than bubble point pressure?
(a) Biot’s coefficient cannot be greater than unity, if the reservoir is assumed to be an elastic isotropic material; and
(b) Biot’s effective stress getting reduced to Terzhagi’s effective stress upon Biot’s coefficient reaching unity.
3. How do we know whether the exploitation of oil and gas at a particular basin has "significantly" contributed to perturbations in the geosphere in terms of changes to the total stresses, pore pressures and the thermal regime?
Along with in-situ seismic wave velocity measurements, whether the existing coupled effect of thermo-hydro-mechanical-chemical phenomena would be able to provide the required responses of water/oil/gas saturated reservoir rock masses (which essentially depends on how exactly the external stresses remain partitioned between solid-grain network and the reservoir pore fluids)?
4. Although Biot’s theory of poro-elasticity can be expressed as functions of strains, elastic properties, and fluid pressure or increment of fluid volume per unit volume of porous reservoir rock using linear elastic state partitioning; when exactly a petroleum reservoir requires the partitioning between solid-grain network and pore fluids to remain to be defined by a non-linear elastic state under transient conditions (and not under equilibrium conditions)?
5. To what extent, the concept of Biot coefficient (a scalar multiplier for the pore pressure term in the stress-strain-fluid pressure relationship) remains to be useful in characterizing conventional hydrocarbon reservoirs?
How easy would it remain to measure effective stress coefficient (the pore pressure factor associated with the stress regimes that falls outside Biot’s linear poro-elasticity) below and above bubble point pressure?
Whether the same simplified concept (linear poro-elasticity) could be extended to unconventional reservoirs as well?
6. Bulk compressibility being a function of pore-shape, fracture aspect ratio and fracture density, how easy would it remain to determine Biot’s coefficient of a fractured reservoir?
Whether Biot’s coefficient would remain to be varying as a function of
(a) stress path; and
(b) fracture orientation (with reference to their bedding planes)?
2,31,2,📷Zhengming Yang2,3,📷Yapu Zhang2,3,📷Zhenkai Wu1,2,*📷,📷Yutian Luo2,3,📷Haibo Li2,3 and📷Ying He
1
College of Engineering Science, University of Chinese Academy of Sciences, Beijing 100049, China
2
Institute of Porous Flow and Fluid Mechanics, University of Chinese Academy of Sciences, Langfang 065007, China
3
Research Institute of Petroleum Exploration and Development, Beijing 100083, China
*
Author to whom correspondence should be addressed.
Energies 2021, 14(11), 3121; https://doi.org/10.3390/en14113121
Received: 12 April 2021/ Revised: 22 May 2021/ Accepted: 23 May 2021/ Published: 27 May 2021
(This article belongs to the Section I1: Fuel)
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Abstract The separation of solution gas has great influence on the development of gas-bearing tight oil reservoirs. In this study, physical simulation and high-pressure mercury intrusion were used to establish a method for determining the porous flow resistance gradient of gas-bearing tight oil reservoirs. A mathematical model suitable for injection–production well networks is established based on the streamline integral method. The concept of pseudo-bubble point pressure is proposed. The experimental results show that as the back pressure decreases from above the bubble point pressure to below the bubble point pressure, the solution gas separates out. During this process, the porous flow resistance gradient is initially equal to the threshold pressure gradient of the oil single-phase fluid, then it becomes relatively small and stable, and finally it increases rapidly and exponentially. The lower the permeability, the higher the pseudo-bubble point pressure, and the higher the resistance gradient under the same back pressure. For tight reservoirs, the production pressure should be maintained above the pseudo-bubble point pressure when the permeability is lower than a certain value. When the permeability is higher than a certain value, the pressure can be reduced below the pseudo-bubble point pressure, and there is a reasonable range. The mathematical results show that after degassing, the oil production rate and the effective utilization coefficient of oil wells decline rapidly. These declines occur later and have a flat trend for high permeability formations, and the production well pressure can be reduced to a lower level. Fracturing can effectively increase the oil production rate after degassing. A formation that cannot be utilized before fracturing because of the blocked throats due to the separation of the solution gas can also be utilized after fracturing. When the production well pressure is lower than the bubble point pressure, which is not too large, the fracturing effect is better.gas-bearing tight oil; resistance gradient; high-pressure mercury intrusion; microscopic; productivity predictionKeywords:
1. Introduction With the continuous growth of the global oil and gas demand and the continuous decline of conventional oil and gas production, unconventional oil and gas resources are increasingly being valued by various countries and oil companies. Unconventional oil and gas resources include heavy oil, tight oil, shale oil and gas, coalbed methane and natural gas hydrates. As a typical unconventional petroleum resource, tight oil is a research focus of exploration and development [1,2,3,4,5]. China has a wide distribution and diversity of tight oil, which is an important renewable resource. The recoverable tight oil reserves are predicted to be about (20–25) × 108 t [6,7,8,9]. Tight oil is light in quality, often bearing solution gas, and the original gas–oil ratio in some tight oil fields is high. In heavy oil reservoirs, asphaltene particles are very problematic. However, in light oil reservoirs, there is less of a risk of asphaltene deposition. Asphaltene deposition is one of the most serious problems in the industry at the moment and it significantly increases the expenses. Many scholars have carried out particle-scale modeling studies on the problem of asphaltene deposition [10,11,12]. The tight sandstone of the Yanchang Formation in the Ordos Basin and the tight sandstone and limestone of the Jurassic strata in central Sichuan are the most typical. Due to the narrow pore throats of tight formations, it is difficult to supplement the formation energy, so development is usually by natural depletion, which leads to a rapid decrease in the formation pressure. When the pressure drops to the bubble point pressure, the solution gas separates out, resulting in a sharp decline in production, which seriously affects the efficiency of tight oil development [13,14,15]. Therefore, it is of great importance to conduct research on porous flow resistance to effectively develop gas-bearing tight oil reservoirs. At present, few studies have been conducted on porous flow resistance in gas-bearing tight oil reservoirs in China and abroad [16,17], and more studies have focused on heavy oil and medium-high permeability reservoirs. For heavy oil reservoirs, Akin and Kovscek and other scholars have used the visualization method to study the influence of solution gas separation on heavy oil flow [18,19,20,21,22,23]. Cui and other scholars have studied the flow performance of heavy oil after the solution gas separates from the oil [24,25,26,27,28]. They have also analyzed the factors influencing the oil flow properties, such as the solution gas–oil ratio, the pressure depletion rate, and the pore throat size. These studies mainly focused on the microscopic porous flow mechanism, but they did not involve porous flow resistance. For medium-high permeability reservoirs, the porous flow resistance is low when a small amount of solution gas separates out because of the large pore throats, so the production pressure can be reduced to from 20% to 30% below the bubble point pressure [29,30,31,32]. However, whether the research results for medium-high permeability reservoirs can be applied to tight reservoirs requires further study. Many scholars have established empirical and theoretical models suitable for the two-phase flow of oil and gas in gas-bearing reservoirs and have calculated the formation pressure distribution, degassing radius, production rate, and minimum allowable pressure of oil wells [33,34,35,36,37,38], but the calculation process is mostly cumbersome. In this paper, a physical simulation experiment and the high-pressure mercury intrusion method were used to analyze the structural characteristics of micropores with different permeabilities. A test method for porous flow resistance in gas-bearing tight oil reservoirs was established. The effects of the different cores and gases on the production of gas-bearing tight oil reservoirs were studied. Based on the streamline integral method, equations for calculating the production rate and the effective utilization coefficient that are suitable for injection–production well networks were derived and the influencing factors were analyzed.
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