44 Measurement and Testing
Permeability of Stress-sensitive Formations: its Importance for Shale Gas Reservoir Simulation and Evaluation
E.H. Rutter, R. McKernan, J. Mecklenburgh, S.E. May Rock Deformation Laboratory, School of Earth, Atmospheric and Environmental Sciences,University of Manchester, Manchester M13 9PL, UK Email:
e.rutter@
manchester.ac.uk
Ernest Rutter
Rosanne McKernan
Julian Mecklenburgh
Reservoir simulation is essential to the interpretation of well flow tests, and in turn for the estimation of reservoir capacity and flow potential. Permeability of many reservoir rocks may be reduced by overburden pressure, and it is important to incorporate this into reservoir modelling.
Solutions to the transport equation for flow through a porous medium, where D is the hydraulic diffusivity, p is fluid pressure and t is time, form the basis of making such interpretations.
(1)
Hydraulic diffusivity is related to physical properties of the fluid medium and the host rock by
, in which is rock porosity, k is permeability, µ is fluid viscosity and c is the
combined compressibility of the fluid and porous matrix of the rock. For flow of a near incompressible fluid such as oil, the terms in D are not strongly dependent upon pressure and time, hence equation (1) forms a linear partial differential equation and analytic solutions can be obtained.
In the case of a gas, however, c depends strongly upon pressure, which causes (1) to become non-linear. Al-Hussainy1
proposed a pseudofunction given by (2)
in which z is gas deviation factor, to take account of gas property variations with pressure. Re-casting (1) with the pressure variable replaced by m(p) re-linearises the transport equation and permits analytic solutions to be found. However, it is still assumed that rock permeability is insensitive to the effective pressure (total pressure – pore fluid pressure) acting on the rock. In the simplest case, effective pressure, which tends to close pore spaces and particularly the pore throats that interconnect the pore spaces, is given by the difference between the mean pressure on the rock mass (largely due to the weight of overlying rocks) and the pore fluid pressure (whether gas or liquid). For relatively permeable rocks, in which pore throats may be large and do not close significantly when effective pressure increases, the assumption that the permeability is insensitive to effective pressure can be a reasonable and is routinely applied to the evaluation of conventional gas reservoirs.
Permeability of gas shales
For unconventional reservoirs such as gas shales, grain size and pore spaces are of small dimensions, and pore throat diameters typically are sub-micron in size. They are more easily closed by application of effective pressure. Such reservoir rocks are described as ‘stress-sensitive’, so that as gas pressure drawdown occurs during production, permeability varies with effective pressure and time throughout the reservoir.
It is common for reservoirs to display reduced permeability close to a production borehole, as a result of formation of a ‘skin’ of damaged rock where drilling fluids may have been forced into pore spaces. This effect appears in solutions to (1) as an increased pressure drawdown term that can be interpreted as a reduced overall reservoir permeability, thereby ignoring the essential stress sensitivity of the reservoir.
Permeability is one of the more time-consuming rock physical properties to measure, especially in the case of shales and other fine-grained rocks where its value may be very low. A commonly employed measurement technique is the GRI (Gas Research Institute) method, which measures intergranular permeability in an aggregate of 0.7 mm diameter rock particles to avoid the presence of cracks. Unfortunately the measurement can only be made at near zero effective pressures when permeability is at its highest, and no information about stress sensitivity or anisotropy is obtained. Using GRI data in reservoir simulations will lead to an over-optimistic assessment of potential and a large divergence from in-situ permeabilities estimated from well tests.
Permeability under effective pressure conditions can be measured on core plugs using steady- state flow methods (slow) or pulse transient decay methods (Brace et al.2 oscillating pore pressure method (Kranz et al.3; Fischer4
; Faulkner & Rutter5
), but we feel that the ; Bernabé et al.6
) is the
best method to assess the behaviour of stress-sensitive reservoir rocks. A sinusoidally-varying, low-amplitude (e.g. 75 to 150 psi) pore pressure wave is applied to the upstream end of a jacketed core plug subjected to a higher hydrostatic pressure to simulate depth of burial. At the downstream end the same wave, reduced in amplitude and shifted in phase is detected. From the amplitude loss and phase shift the permeability and sample storativity can be calculated. Unlike others, the method is robust and insensitive to small amounts of pressure leakage and
Steven May
Figure 1: Example of experimental data from a permeability measurement by the oscillating pore pressure method with a mean pore pressure of 4120 psi and a total confining pressure of 10000 psi. Relative to the upstream forcing wave the downstream wave is reduced in amplitude and is phase-shifted. The permeability is largely determined by the amplitude ratio, and is in this case 20 µD.
Figure 2: Experimentally determined argon gas permeability variations during repeated effective pressure cycling for Runswick Bay shale (core samples dried to constant weight at 60 ºC), both parallel (2 specimens) and perpendicular (1 specimen) to layering. Permeability anisotropy is more than 2 orders of magnitude. Results are expressed as sensitivity to effective pressure (total pressure – pore pressure). Permeability decreases rapidly during the first pressure cycle, probably through microcrack closure, but the subsequent cycles show little further permanent reduction, even when the pressures are removed at the end of a cycle. The black straight line shows the function used here to represent the sensitivity of permeability to pressure for reservoir modelling purposes (based on specimen #1).
AUGUST / SEPTEMBER 2013 •
WWW.PETRO-ONLINE.COM
Page 1 |
Page 2 |
Page 3 |
Page 4 |
Page 5 |
Page 6 |
Page 7 |
Page 8 |
Page 9 |
Page 10 |
Page 11 |
Page 12 |
Page 13 |
Page 14 |
Page 15 |
Page 16 |
Page 17 |
Page 18 |
Page 19 |
Page 20 |
Page 21 |
Page 22 |
Page 23 |
Page 24 |
Page 25 |
Page 26 |
Page 27 |
Page 28 |
Page 29 |
Page 30 |
Page 31 |
Page 32 |
Page 33 |
Page 34 |
Page 35 |
Page 36 |
Page 37 |
Page 38 |
Page 39 |
Page 40 |
Page 41 |
Page 42 |
Page 43 |
Page 44 |
Page 45 |
Page 46 |
Page 47 |
Page 48 |
Page 49 |
Page 50 |
Page 51 |
Page 52
