In the case of nondeformable media, any pressure change or flux imposed at the wellbore diffuses, as per the dictates of a diffusion equation. Pressure diffusivity under normal circumstances of moderate permeability is significantly larger than mass diffusivity. As observed at the source or an observation point, the response encodes information about the diffusivity and any variation in it. The implementation of such a test, measurements associated with it, and the time-dependent data interpretation are the main components of a pressure transient test. Such tests may be conducted with WFTs or drillstem tests (DST) in an open borehole. In a cased well, production and injection tests may be augmented by a wireline-conveyed casedhole formation tester.

Introduced approximately 70 years ago, WFT remains the prime data source for formation pressure and its gradient, gas/oil, and oil/water contacts, horizontal and vertical permeabilities, inference of faults and fractures, depth-dependent fluid samples and analysis, and formation fracturing pressure. WFTs are frequently used in the exploration phase and may supplement other analyses in a reservoir’s development and production phases. Mostrecent advances enable the tester to be configured for the purpose: modules may be added or, if the situation warrants, it pumps fluids at a rate as high as 100 cm³ s⁻¹ (54.34 B/D).

With the introduction of repeat formation testers in 1975 and quartz pressure sensors, uncertainty in reservoir pressure measurements was reduced considerably. Accuracy facilitated pressure gradient evaluation, which enabled inference of far-field fluid density, but also equally importantly, fluid contacts from observations of abrupt-fluid density changes. Pretest, designed initially to make contact with the formation to get pressure, was useful in obtaining permeability. The advent of pump-out modules allowed for continuous pumping of formation fluid for transient testing and several liters’ sample collection. Multiple samples and inline spectroscopic detection made first-pass evaluation a routine service, with corroboration from physical samples corresponding to the depth of interest. Bubblepoint detection avoids phase separation while sampling. The presence of gas in the flow line was inferred through a gas detector on the basis of the refractive index contrast. Multiple probe-probe or packer-probe configurations provide interference pressure measurements at multiple observation points to estimate horizontal and vertical permeability with high confidence. Modern advances aim to increase flow rates even further, with reasonably sophisticated collection geometries to sample native fluids earlier (Hashem et al. 2004). Further advances are likely to handle acidic gases and crude oil.

No hardware advance would realize its full potential if it were not for the associated modeling. Not only has spectroscopic interpretation allowed more components to be identified and quantified, but detection of gas and water fractions in the flowline through processing meant that phase holdup fractions could be displayed on a log. With regard to pressure, analytical solutions have been developed for single-phase fluid flow in many complicated well and boundary conditions for WFT in homogenous, anisotropic, fractured, layered, and laterally and radially composite systems. For multiphase flow and complicated heterogeneous systems, approximate analyses could be supplemented with numerical simulations. Many of the principles developed for WFT are also useful for well testing.

To a large extent, this book addresses several issues not previously covered. Exposition of analytical models, systematic inclusion of mixed boundary value problems, first-principle-based pressure-gradient interpretation, probabilistic enumeration of radius of investigation, and system identification methods set this book apart from others.

Weber (1986) said, “Reservoir heterogeneity is among the major reasons why enhanced oil recovery is so difficult. Projects undertaken without detailed reservoir evaluation often end in failures related to unexpected baffles to flow, permeability heterogeneity, or the wrong appreciation of the residual oil distribution.” Improving reservoir characterization is, therefore, paramount for computing reliable predictors and uncertainties in reservoir performance. Advanced formation testing modules and new interpretation techniques are a step in this direction.