One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

The Empire Abo field, located in New Mexico, US, covers 11,000 acres (12.5 miles long by 1.5 miles wide) and contains approximately 380 million stock tank barrels (STB) of original oil in place (OOIP).[1][2] This reservoir is a dolomitized reef structure (Figure 1) with a dip angle of 10 to 20 from the crest toward the fore reef. The oil column is approximately 900 ft thick, but the average net pay is only 151 ft thick. The pore system of this reservoir is a network of vugs, fractures, and fissures because the primary pore system has been so altered by dolomitization; the average log-calculated porosity was 6.4% BV. Numerical simulations of field performance and routine core analysis data have indicated that the horizontal and vertical permeabilities are about equal.

As with most technology, proper candidate selection is key to success. The economics are often determined by the number of and locations of the wells and by the overall geographical development plan. It is important to recognize that downhole processing is not a substitute for prudent profile control of wells through workovers, gel polymer treatments, cement squeezes, and so on. The following discussion applies to both gas/liquid and water/oil processing, followed by sections that discuss screening criteria specific to each. From an equipment standpoint, gas/liquid separation is much easier than oil/water separation. This generally means that it is a more robust application. All separation and pump equipment has an expected lifetime that is typically much shorter than the lifetime of the well. The cost of replacing or repairing the equipment must be considered as well as the initial capital cost.

Obtaining and analyzing cores is crucial to the proper understanding of any layered, complex reservoir system. To obtain the data needed to understand the fluid flow properties, the mechanical properties and the depositional environment of a specific reservoir requires that cores be cut, handled correctly, and tested in the laboratory using modern and sophisticated laboratory methods. Of primary importance is measuring the rock properties under restored reservoir conditions. The effect of net overburden pressure (NOB) must be reproduced in the laboratory to obtain the most accurate quantitative information from the cores. To provide all the data needed to characterize the reservoir and depositional system, a core should be cut in the pay interval and in the layers of rock above and below the pay interval. Core from the shales and mudstones above and below the pay interval help the geologist determine the environment of deposition.

Core analyses are a critical part of analyzing CBM reservoirs to determine gas saturations. Coal cores must be placed in desorption canisters and heated to reservoir temperature. As the coal desorbs, gases are captured, and both their volume and composition are determined. Desorption continues for up to several months until the rate at which gas is being liberated from the coal becomes very small. At this point, the canisters are opened, and the cores can be described. The cores then are crushed in a mill that captures any remaining gas (residual gas), and the milled coal is mixed thoroughly to form a representative sample. An alternative to crushing the entire core is to first slab the core and crush one-half.

There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. It is uncommon to have emulsions and sludges form in the near-wellbore region without the introduction of external chemicals.[1]The

Once you determine that a well is a good candidate for matrix acidizing and have selected appropriate acids, you are ready to design the treatment. Essentially, the design process is a systematic approach to estimating and calculating injection pressure and rate, volumes, and concentrations. If acid can easily reach nearby plugging solids, small volumes of 25 to 50 gal/ft of HF-type acid can dissolve this damage; however, with more severe damage, more time and volume are needed to reach the plugging solids. Effective acid diversion reduces acid volumes needed. Permeability and mineralogy determine the compatible concentration of HCl or acetic acid in the preflush stage and HF and HCl acid in the HF-/HCl-acid stage.

Permeability is one of the fundamental properties of any reservoir rock required for modeling hydrocarbon production. However, shale permeability is not yet fully understood because of the complexities involved in modeling flow through nanoscale throats. Historically, shale was thought to perform two key functions: act as a seal for conventional reservoirs and as a source rock for hydrocarbons. Recently, several shale formations have also proven to be major self-sourcing hydrocarbon reservoirs. Liquid production from numerous shale reservoirs confirmed shale as an important source of hydrocarbons and spurred a worldwide assessment of the production potential of shale.

Because foam applications for mobility control during gas flooding have proven technically challenging and marginally attractive, the recent focus has shifted somewhat to the application of relatively small volumes of foam that are placed as gas blocking agents from the production well side. The application of foams as gas blocking agents has been discussed and reviewed numerous times in the literature.[1][2][3][4][5][6] Because foams are exceptionally effective at reducing gas permeability, they are good candidates for use in gas blocking treatments that are placed relatively near to producing wellbores. The foam's low effective density results in the tendency for selective placement in the upper sections of the reservoir where gas, especially coning and cusping, is entering the wellbore. The obvious and major challenges that must be overcome to successfully apply foams as a gas blocking agents are to assure that the emplaced blocking foam will have adequate strength and that the metastable foam will be stable long enough to result in attractive economics.