Formations permeability

All the parameters discussed above are needed to calculate the volume of hydrocarbons in the reservoir. The formation permeability is a measure of the ease with which fluids can pass through the reservoir, and hence is needed for estimating well productivity, reservoir performance and hydrocarbon recovery. 

Formation permeability around the wellbore can be measured directly on core samples from the reservoir or from well testing (see Section 8.4), or indirectly (estimated) from logs. 

Figure 4-293. Invasion diameter versus invasion time for various formation permeabilities, (a) Filtrate invaded porosity 20% mudcake permeability 1 pd mudcake thickness 0.25 differential pressure 500 psi. (b) Filtrate invaded porosity 30% mudcake permeability 1 pd mudcake thickness 0.25 differential pressure 500 psi. (Courtesy Louisiana State University [99]. ...

The damage of the formation resulting from the use of a filtration loss agent can be a serious problem for certain fields of application. Providing effective fluid loss control without damaging formation permeability in completion operations has been a prime requirement for an ideal fluid loss control pill. 

A low-molecular-weight condensation product of hydroxyacetic acid with itself or compounds containing other hydroxy acid, carboxylic acid, or hydroxy-carboxylic acid moieties has been suggested as a fluid loss additive [164]. Production methods of the polymer have been described. The reaction products are ground to 0.1 to 1500 p particle size. The condensation product can be used as a fluid loss material in a hydraulic fracturing process in which the fracturing fluid comprises a hydrolyzable, aqueous gel. The hydroxyacetic acid condensation product hydrolyzes at formation conditions to provide hydroxyacetic acid, which breaks the aqueous gel autocatalytically and eventually provides the restored formation permeability without the need for the separate addition of a gel breaker [315-317,329]. 

N. A. Mumallah. Altering subterranean formation permeability. Patent US 4917186, 1990. 

T. R. Thomas and K. W. Smith. Method of maintaining subterranean formation permeability and inhibiting clay swelling. Patent US 5211239,1993. 

Injecting epoxy, furan, or furan-formaldehyde resins into poorly consolidated formations to consolidate them was a common sand control practice for thin highly productive formations (44-46). Organic solvents (46) and silane coupling agents (47) are used to promote adhesion of the resin to the rock surface. Excess resin is flushed deeper into the formation to minimize resin hardening in the flow channels since this would reduce formation permeability. 

Properly designed, the injected acid enters the flow channels of the formation and flows radially outward from the wellbore dissolving mineral fine particles in the flow channels. Minerals forming the flow channel walls also react with the acids. These processes increase formation permeability near the wellbore. The end result... 

Formation permeability damage caused by precipitation of dissolved minerals such as colloidal silica, aluminum hydroxide, and aluminum fluoride can reduce the benefits of acidizing (132-134). Careful treatment design, particularly in the concentration and amount of HF used is needed to minimize this problem. Hydrofluoric acid initially reacts with clays and feldspars to form silicon and aluminum fluorides. These species can react with additional clays and feldspars depositing hydrated silica in rock flow channels (106). This usually occurs before the spent acid can be recovered from the formation. However, some workers have concluded that permeability damage due to silica precipitation is much less than previously thought (135). 

Adsorption of corrosion inhibitors or cationic surfactants can reduce sandstone formation permeability. Alcohols can be used to remove corrosion inhibitors from rock surfaces. Oil-soluble corrosion inhibitors may be dissolved by organic solvents such as xylene or toluene containing a mutual solvent, most often ethylene glycol monobutyl ether, EGMBE (167). Aqueous fluids containing 5-10% EGMBE can be used to dissolve cationic surfactants. 

Coulter, G.R. Hower, W. "The Effect of Fluid pH on Clays and Resulting Formation Permeability", Proc. Annu. Southwest Pet. Short Course, April 1975. 

Coulter, A.W., Jr. Frick, E.K. Samuelson, M.L. "Effect of Fracturing Fluid pH on Formation Permeability", SPE paper 12150, 1983 SPE Annual Technical Conference and Exhibition, San Francisco, October 5-8. 

Pye, D.S. Smith, W.A. "Fluid Loss Additive Seriously Reduces Fracture Proppant Conductivity and Formation Permeability," 1973 SPE Annual Meeting, Las Vegas, Sept. 30-0ct. 3. 

The first set of data is for oil production from 22 wells. A quaternary ammonium salt polymer clay stabilizer was utilized in five of the well treatments. Otherwise the 22 well treatment designs were identical. Use of the clay stabilizer in 5 well treatments resulted in a 131% production increase compared to a 156% increase after stimulation of 17 wells without clay stabilizer. Although the initial overall production response of the five clay stabilizer treated wells was less, the overall production decline rate was 4% per year compared to 16%/yr for the treatments which did not include the clay stabilizing polymer. This decline rate was determined for the period 4 to 24 months after well treatment. It is tempting to speculate that the lower initial production response of the five polymer treated wells was due to the formation of an adsorbed polymer layer which reduced formation permeability (particularly of the Wilcox Formation) significantly. 

Formation permeability Relative permeability NAPL viscosity Actual NAPL thickness... 

During the design phase, all of the data derived from the hydraulic characterization are evaluated for use in the selection of recovery pumping equipment and for the determination of the most appropriate subsurface fixtures (whether wells, trenches, or drains, etc.). A variety of generic scenarios may be appropriate to optimize product recovery. If the product thickness is sufficient, the viscosity low, and the formation permeable, a simple pure-product skimming unit may be the best choice. Other combinations of permeability, geology, and product quality will require more active systems, such as one-pump total fluid, or two-pump recovery wells. 

Oil producers will typically set standards for oil-in-water content ranging from less than 10 ppm in very light crude oils to several hundred parts per million in very heavy crude oils. These specifications are usually site-specific and are dependent on equipment available and crude-oil type. Oil producers in Canada usually have the advantage of disposal wells or water-flood schemes in which produced water is disposed. Failure to meet self-imposed oil-in-water limits usually results in loss of hydrocarbon product back to the formation. For an oil production facility that disposes of 1000 m of water per day with an oil content of 1000 ppm, 365 m of oil is lost per year. At 25 (Canadian) per barrel, this amount of oil translates to a product loss worth approximately 57,000 per year, plus any maintenance costs and well stimulation costs to restore injectivity lost as a result of formation plugging from oil-wet solids. Oil-wet solids in water-flood systems may damage formation permeability and reduce recovery. 

Field tests of both colloidal silica and polysiloxane showed that these materials could be successfully placed with conventional grouting equipment, had good gel time control (from minutes to hours) and reduced formation permeabilities by two or more orders of magnitude. Reports prepared for the meeting noted above described other unusual grout properties These materials have a viscosity less than that of water and... 

When injections are made into stratified deposits, the degree of displacement is related to the formation permeability, and the grouted mass can take odd shapes, such as illustrated in Fig. 13.6. In this experiment, the zones where diluted grout gelled are shown by the shading on the upper and lower sand strata of Fig. 13.7. 

Alkaline consumption by chemical reaction and ion exchange is mainly due to the existence of clays. Thns, clay content shonld not exceed 15 to 25%. Formation permeability shonld be greater than 100 md. 

Invasion of Foreign Particles. Invasion of solid particles can cause severe damage around the wellbore. In this case, the solids plug some of the pores and, as a result, the formation permeability diminishes. According to Wojtanowicz et al. (71), the decline of permeability with respect to time can give an indication of the plugging mechanism. At a constant flow rate experiments, the pressure response that occurs due... 

Azari, M. and Leimkuhler, J., Formation Permeability Damage Induced by Completion Brines, J. Pet. Technol. 1990, 42, 486-492. 

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