Pore pressure shales

Figure 4-330. Matthews and Kelly relationship between formation pore pressure and shale resistivity for the South Texas Gulf Coast. (Courtesy SPE [101]. ...

Alixant, J-L., Real-time Effective Stress Evaluation in Shale Pore Pressure and Permeability Estimation, Ph.D. dissertation, Louisiana State University, p. 210, December 1989. 

Shale stability is an important problem faced during drilling. Stability problems are attributed most often to the swelling of shales. It has been shown that several mechanisms can be involved [680,681]. These can be pore pressure diffusion, plasticity, anisotropy, capillary effects, osmosis, and physicochemical alterations. Three processes contributing to the instability of shales have to be considered [127] ... 

Clays or shales have the ability to absorb water, thus causing the instability of wells either because of the swelling of some mineral species or because the supporting pressure is suppressed by modification of the pore pressure. The response of a shale to a water-based fluid depends on its initial water activity and on the composition of the fluid. The behavior of shales can be classified into either deformation mechanisms or transport mechanisms [1765]. Optimization of mud salinity, density, and filter-cake properties is important in achieving optimal shale stability and drilling efficiency with water-based mud. 

Abstract This paper is concerned with the experimental identification of some chemo-poroelastic parameters of a reactive shale from data obtained in pore pressure transmission - chemical potential tests. The parameter identification is done by matching the observed pressure response with a theoretical solution of the experiment. This solution is obtained within the framework of Biot theory of poroelasticity, extended to include physico-chemical interactions. Results of an experiment on a Pierre II shale performed in a pressure cell are reported and analyzed. 

The so-called pore pressure transmission-chemical potential test is used in the petroleum industry to assess the osmotic membrane efficiency of a shale in contact with a drilling fluid ([6, 7, 12-1]). It is motivated by the need to assess the capacity of improving the stability of a borehole in a chemically active shale by increasing the salt concentration of the drilling fluid. In this test, a saturated cylindrical sample of shale is subjected sequentially to a hydraulic... 

The set of constitutive parameters contains the (drained) elastic volumetric compliance C and two poroelastic constants the Biot stress coefficient b, and the unconstrained storage coefficient Sa = d(/dp a which can be expressed as So- = bB 1C ([13]), where B is the Skempton pore pressure coefficient. The other three parameters, a, f3, and 7 quantify the physico-chemical interactions. Both a and (3 are constrained to vary from 0 when there is no chemical interaction to 1 when the salt ions are trapped in the pore network (this limiting case is referred to as the perfect ion exclusion membrane model ). The coefficient 7 can simply be approximated by 7 x0/n, where n is the porosity of the shale. 

Figure 3. Downstream fluid pressure response for a pore pressure transmission test with a Pierre II Shale, for successive hydraulic and chemical loading (experimental data and matched theoretical response).

The borehole is assumed to be infinitely long and inclined with respect to the in-situ three-dimensional state of stress. The axis of the borehole is assumed to be perpendicular to the plane of isotropy of the transversely isotropic formation. Details of the problem geometry, boundary conditions and solutions for the stresses, pore pressure and temperature are available in [7], The solution is applied to assess the thermo-chemical effects on stresses and pore pressures. Both the formation pore fluid and the wellbore fluid are assumed to comprise of two chemical species, i.e., a solute fraction and solvent fraction. The formation material properties are those of a Gulf of Mexico shale [7] given as E = 1853.0 MPa u = 0.22 B = 0.92 k = 10-4 md /r = 10-9 MPa.s Ch = 8.64 x 10-5 m2/day % = 0.9 = 0.14 cn = 0.13824 m2/day asm = 6.0 x 10-6 1°C otsf = 3.0 x 10-4 /°C. A simplified example is considered wherein the in-situ stress gradients are assumed to be trivial and pore pressure gradients of the formation fluid and wellbore fluid are assumed to be = 9.8 kPa/m. The difference between the formation temperature and the wellbore fluid temperature is assumed to be 50°C. The solute concentration in the pore fluid is assumed to be more than that in the wellbore fluid such that mw — mf> = —1-8 x 10-2. 

Direct observations of sub-surface pressure allow a calibration to be made between the SGR and seal capacity. Ideally, an in situ measurement of the pore-pressure in the reservoir and that inside the fault zone would allow the capillary entry pressure of the fault to be calculated. However, fault-zone pressures are rarely available. Instead, the pressure difference between the two walls of the fault is a more general parameter that can be derived from pressure measurements in pairs of wells across the fault. Fig. 7a shows one such calibration, based on the Nun River dataset of Bouvier et al. (1989). From their strike projections of Fault K , values of SGR have been calculated on a dense grid across the fault surface. On the same grid, minimum across-fault pressure differences have also been derived, using the proven distribution of hydrocarbons in the footwall sands to calculate buoyancy pressures. Fig. 7a shows a cross-plot of these two parameters for the areas of sand-sand contact at the fault surface. The dashed line indicates the inferred relationship between SGR and seal capacity. At SGR < 20%, no fault-sealed hydrocarbons are observed the shale content of the slipped interval... 

Pore pressure gradients are very difficult to estimate with the same accuracy in shales outside the reservoir zones, where RFT or DST measurements are impossible. We have, however, estimated pressure gradients in three wells on the border between the Melke and Gam Formations, based on the drilling data in Fig. 5. We have attempted to calculate the flow of water from the overpressured Upper Jurassic and Lower Cretaceous shales, into the underlying Middle Jurassic sandstones. The main uncertainty in... 

The processes can be considered as three initially independent processes. These include the undrained load-deformaiion-failure process and the fluid and heat flow processes. The fluid flow process may include solute transport. Other mechanisms include swelling of shale caused by change in water potential resulting from the other processes. The main coupling parameters are stress, pore pressure and temperature. 

Loss of confinement resulting from the creation of a borehole can lead to wellbore failure. The weight of the drilling fluid provides some of the support (for the wellbore) which was originally provided by the drilled out material. However, when drilling under an overbalance condition in shales without an effective flow barrier present at the wellbore wall, invasion of the mud filtrate into the formation may occur. Due to the saturation and low permeability of shales, a small volume of mud filtrate penetrating the formation will result in a considerable increase in pore pressure near the wellbore wall. The increase in pore pressure reduces the effective mud support and can lead to a less stable wellbore condition. 

Due to the low permeability of shales, the coefficient of thermal diffusivity is at least a few orders of magnitude greater than the coefficient of fluid diffusivity. Hence, heat transfer in the formation will be dominated by diffusion, and convective transfer by fluid flow may be ignored. Since the coefficient of thermal expansion of pore fluid is much larger (in the order of 100 times) than the coefficient of rock solid, temperature change will result in a change in pore pressure. 

Oil reservoirs are layers of porous sandstone or carbonate rock, usually sedimentary. Impermeable rock layers, usually shales, and faults trap the oil in the reservoir. The oil exists in microscopic pores in rock. Various gases and water also occupy rock pores and are often in contact with the oil. These pores are intercoimected with a compHcated network of microscopic flow channels. The weight of ovedaying rock layers places these duids under pressure. When a well penetrates the rock formation, this pressure drives the duids into the wellbore. The dow channel size, wettabiUty of dow channel rock surfaces, oil viscosity, and other properties of the cmde oil determine the rate of this primary oil production. 

Smith, J.E., 1971. The dynamics of shale compaction and evolution of pore-fluid pressures. 

Under the hydrostatic condition, water within the pore spaces of the rocks is connected to water in the sediments and the sea above. Under lower rates of sedimentation, it is possible for water to be expelled at a rate adequate to maintain the hydrostatic equilibrium. However, at rapid burial rates, with relatively impermeable shales, this equilibrium is not maintained. The fluid motion is retarded, and the pore fluid begins to support the overburden, resulting in pressure increase. 

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