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Many well pressure data coming from long and narrow reservoirs which result from either fluvial deposition of faulting cannot be completely interpreted by conventional analysis since some flow regimes are not conventionally recognized yet in the oil literature. This narrow geometry allows for the simultaneous development of two linear flow regimes coming from each one of the lateral sides of the system towards the well. This has been called dual linear flow regime. If the well is off-centered with regards to the two lateral boundaries, then, one of the linear flow regimes vanishes and, then, two possibilities can be presented. Firstly, if the closer lateral boundary is close to flow the unique linear flow persists along the longer lateral boundary. It has been called single linear flow. Following this, either steady or pseudosteady states will develop. Secondly, if a constant-pressure closer lateral boundary is dealt with, then parabolic flow develops along the longer lateral boundary. Steady state has to be developed once the disturbance reaches the farther boundary. This study presents new equations for conventional analysis for the dual linear, linear and parabolic flow regimes recently introduced to the oil literature. The equations were validated by applying them to field and simulated examples.

Although, the radial difussivitity equation has been solved for a single-fluid phase flow, in some cases more than one phase flows from the reservoir to the well; therefore, the single-phase solution has been previously extended to multiphase flow without losing a significant degree of accuracy. Practically, there exist two ways of dealing with multiphase flow: The Perrine method, Perrine (1956) which basically replaces the single-phase compressibility by the multiphase compressibility so that each fluid is analyzed separately using the concept of mobility. The other one is the use of pseudofunctions which have been found to be the best option. The TDS technique has been widely applied to a variety of scenarios. It has been even tested to successfully work on condensate systems with the use of pseudofunctions, Jokhio, Tiab and Escobar (2002). However, equations for estimation of phase permeability, skin factor and drainage area has not neither presented nor tested. In this article, we present new versions of a set of equations of the TDS technique to be applied to multiphase flow following the Perrine method along with a previously presented way of estimation of the absolute relative permeability. We successfully applied the proposed equations to synthetic and field examples.

The analysis of injection tests under nonisothermic conditions is important for the accurate estimation of the reservoir permeability and the well's skin factor; since previously an isothermical system was assumed without taking into account a moving temperature front which expands with time plus the consequent changes in both viscosity and mobility between the cold and the hot zone of the reservoir which leads to unreliable estimation of the reservoir and well parameters. To construct the solution an analytical approach presented by Boughrara and Peres (2007) was used. That solution was initially introduced for the calculation of the injection pressure in an isothermic system. It was later modified by Boughrara and Reynolds (2007) to consider a system with variable temperature in vertical wells. In this work, the pressure response was obtained by numerical solution of the anisothermical model using the Gauss Quadrature method to solve the integrals, and assuming that both injection and reservoir temperatures were kept constant during the injection process and the water saturation is uniform throughout the reservoir. For interpretation purposes, a technique based upon the unique features of the pressure and pressure derivative curves were used without employing type-curve matching (TDS technique). The formulation was verified by its application to field and synthetic examples. As expected, increasing reservoir temperature causes a decrement in the mobility ratio, then estimation of reservoir permeability is some less accurate from the second radial flow, especially, as the mobility ratio increases.