Development of a condensate bank in gas condensate wells producing below the dew point pressure causes productivity losses as gas mobility at the wellbore is reduced. The same is true in volatile oil wells producing below the bubble point pressure due to the existence of a gas bank. Using compositional simulation, this paper investigates the use of back-pressure plots expressed in terms of pressure, singlephase pseudo-pressure, and two-phase pseudo-pressure to describe well productivity losses below saturation pressure for gas condensate or volatile oil wells. It is shown that the theoretical stabilized back-pressure deliverability straight line at krg =krgi cannot be obtained using pressure and single-phase pseudo-pressure back-pressure plots whereas it can matched with two-phase pseudo-pressures, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. Bottom-hole back-pressure plots using two-phase pseudo-pressures can then be used to quantify productivity and mobility reductions and to separate the effect of the bank from other effects such as multi-layering, thus allowing identification of appropriate remediation measures. These results are verified with data from actual gas condensate and volatile oil reservoirs.

Deconvolution is a recent milestone in well test analysis which converts multirate pressure data into a single drawdown at constant rate. It yields a pressure derivative with a duration equal to the duration of the test, thus providing more pressure data to interpret than with conventional techniques; and gives access to the true radius of investigation of the test. In addition, the deconvolved derivative is free from distortions due to the pressure derivative calculation algorithm and from errors introduced by incomplete or truncated rate histories. Theoretically, deconvolution is only valid for linear systems. In practice, it is also used, with pseudo-pressures, for dry gas, and even for gas condensate and volatile oil below saturation pressure. As these systems are highly non-linear, there has been some concerns about the validity of such an approach. This paper investigates the use of deconvolution for gas condensate and volatile oil below saturation pressure. Using compositional simulation, it applies deconvolution to different reservoir geometries using two-phase pseudo-pressures, which linearize the reservoir-fluid system by replacing the two-phase fluid below saturation pressure by a single fluid equivalent. Comparison with deconvolution using single-phase pseudo-pressure (for gas condensate) or pressure (for volatile oil) shows that the resulting deconvolved derivatives are similar, and in particular exhibit similar late time behaviours, thus justifying the simpler pseudo-pressure (resp., pressure) approach. Simulation results were verified with actual data from vertical and horizontal wells in a number of gas condensate and volatile oil reservoirs.

Well testing in gas-condensate and volatile oil reservoirs with flowing bottomhole pressure below the saturation pressure creates multiphase flow in the reservoir, resulting in relative permeability reduction and a rate-dependent skin factor. In lean gas condensate reservoirs, the wellbore skin effect calculated using single-phase pseudo-pressures has often been found to be constant or even to decrease with increasing gas rates, instead of increasing as in dry gas reservoirs. This behaviour has been tentatively attributed to capillary number effects compensating for condensate blockage and inertia effects, but no detailed study of this behaviour has appeared in the literature to-date. This paper investigates wellbore skin behaviours in lean and rich gas condensate reservoirs and in volatile oil reservoirs by using compositional simulation with capillary numbers and non-Darcy flow to generate well test data. It is shown that below saturation pressure, gas condensate well test analyses with single-phase pseudo-pressures and volatile oil well test analyses with pressures do not correctly estimate the rate-independent wellbore skin effects and the non-Darcy flow coefficients, whereas analyses with two-phase pseudo-pressure do, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. In gas condensate reservoirs below the dew point pressure, the rate independent skin factor and the non-Darcy flow coefficient calculated with two-phase pseudo-pressures are identical to the corresponding values calculated above the dew point pressure with single-phase pseudo-pressures. These simulation results are applied to actual field data.

Anisotropy measurements in unconventional rocks require fully characterized azimuthal rock properties. Accurate characterization of the minimum in situ horizontal stress plays a vital role in fracture modeling. Underestimation of stresses from applying the assumptions of isotropy leads to poor drilling and completion design. On the other hand, applying a simplified tensors’ assumption and assuming a constant Biot's Poroelastic Coefficient of one overestimates the stresses leading to costly drilling issues and incorrect proppant placement. First step involves obtaining high frequency directional core samples i.e. vertical (0°), inclined (45°) and horizontal (90°) to derive five independent and continuous velocity profiles (including vertical shear and vertical compressional velocities) and mechanical properties for anisotropic models. Importance of core testing is imperative to deriving pseudo velocity profiles and for dynamic to static conversion of Young's Moduli and Poisson's Ratios. Rock physics govern static core based properties (stress-strain measurements) be used as opposed to dynamic properties measured directly from velocities for accurate characterization of stresses. Obtaining an inclined ASTM (American Standard Testing Material) standard core plug for rock testing is one of the biggest challenges the industry is facing due to the fragile nature of shale material. Shorter core plugs lead to end-cap friction and scaling related errors by increasing uncertainty in rock properties. These challenges have forces the industry to make a simplified assumption on tenors (i.e. C12=C13) that are imperative to deriving anisotropic mechanical properties from measured azimuthal velocities. Second challenge is the characterization and validation of Biot's poroelasticity theory. Building pore pressure to measure grain compressibility to calculate Biot's constant in unconventional rock types is time consuming and costly. Therefore, many standard models assume a constant Biot's of one. The tensor and Biot's assumptions were investigated independently and fracture modeling was performed to predict the fracture geometry that was also compared with the available calibration data. It was determined that the both tensor and Biot's of one models overestimated the stresses, resulting in an inaccurate fracture geometry prediction. Finally, a variable Biot's model without the simplified tensor assumption derived using inclined velocity measurements was proposed, that composed of fully integrated anisotropic core based rock properties. The proposed model is a useful tool to accurately characterize the geomechanical properties of unconventional rocks and hence accurately predict the resulting fracture geometry. Good understanding of the stress field around a wellbore allows operators to make informed decision regarding the drilling and completion program of the in-fill wells leading to optimum field development strategies and significant cost savings.

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