We assert that a classification of gas flow regimes in shales that is widely accepted in the petroleum industry, may be inconsistent with the physics of high-pressure gas flow in capillaries. This classification follows from the 1946 work by
In the small-scale, low-velocity flows of gases, failure of the standard Navier-Stokes description (the standard Darcy law in petroleum engineering) can be quantified by the Knudsen number, ratio of the mean free path, λ, of gas molecules at the reservoir pressure and temperature to the characteristic pore radius,
For example, in Barnett mudrocks, naturally occurring pores are predominantly associated with organic matter and pyrite framboids. In organic matter, the median pore length is 100 nm,
The generally accepted "Knudsen-diffusion" in shales is based on a mistranslation of the flow physics and may give theoretically unsound predictions of the increased permeability of shales to gas flow. This increase of permeability is real, and it comes from the micropores, fine-scale microfractures and cracks. The nanopores in shales provide gas storage by sorption and capillary condensation of heavier gas components. In the smallest nanopores even methane molecules are increasingly ordered and resemble more liquid than gas. These nanopores feed the macroscopic flow paths in ways that are not captured well by the generally accepted equations.
Development of liquid rich shale (LRS) reservoirs has gained tremendous momentum in recent years. A detailed understanding of fluid behavior, completion practices and reservoir dynamics is essential to accurately predict their long-term performance. This paper uses stochastic reservoir modelling to identify the optimal values for several completion and uncertainty parameters.
A compositional reservoir simulation model for a typical gas condensate well in the Eagle Ford shale was used to identify the optimal production strategies for maximum EUR of oil and gas. The important factors considered for the study are fracture spacing, fracture conductivity, fracture half-length, well spacing, porosity, permeability, initial GOR and well constraints. These factors are often studied independently of one another and their interaction is usually ignored. For example, in a higher permeability play, greater fracture density leads to rapid recovery but ultimate cumulative production does not improve. However, for a play with lower permeability, greater fracture density improves both recovery rate and EUR thereby leading to improved overall economics. Thus, interaction effects due to coupling can have a decisive effect on the overall performance of a reservoir. This paper presents a statistical study of both independent and coupled effects on ultimate oil and gas production from a LRS gas condensate reservoir.
The results show that fracture half-length and fracture spacing have the most complex and significant effects on performance of the reservoirs studied. High initial rates are often preferred in unconventional reservoirs with their rapid rates of decline. These high rates can be achieved with larger fracture half-lengths and smaller fracture spacing. This study shows that high initial rate of production leads to a greater liquid dropout and larger condensate banking. These results also reduce the production rate of gas due to relative permeability effects. Return on investment is reduced due to reduced cumulative production and excess spending on fracture creation. Similar effects were observed for other factors like well constraints where higher minimum flowing bottom-hole pressure led to lower cumulative gas production and lower liquid dropout. In some cases higher bottom-hole pressure might be preferable due to the differential in the price of condensate and gas.
The sensitivity studies in this study provide considerable insight into the long-term production behavior in LRS gas condensate reservoirs. During the initial phase of a project, uncertainties related to various field parameters and their coupled effects are often ignored leading to suboptimal returns on investment.
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.