11

Flowing Pressure

Figure 10-1. Pressure distribution in a reservoir with a skin. {From the October, 1953 issue of Petroleum Engineer International. Publisher retains copyrights.)

Figure 10-2 shows that the effect of reduced rock permeability (as measured in a lineal core) on the productivity of a well decreases with distance from the borehole.

There are several mechanisms by which mud solids or filtrate may reduce well productivity. These may be summarized as follows:

1. Capillary phenomena—relative permeability effects resulting from changes in the relative amounts of water, oil, and/or gas in the pores; wettability effects: and blocking of the pores by aqueous filtrates.

2. Swelling and dispersion of indigenous reservoir clays by the mud filtrate.

3. Penetration of the formation, and plugging of its pores, by particles from the mud.

4. Plugging of gravel packs, liners and screens by mud filter cake.

5. Mutual precipitation of soluble salts in the filtrate and formation water.

6. Slumping of unconsolidated sands.

In this chapter we shall first discuss these mechanisms in detail. We shall then describe the various workover and completion fluids, and the best means of minimizing or avoiding formation damage.

When the filtrate from a water-base mud invades an oil-bearing formation it displaces the oil. Under certain circumstances not all of the water is produced back, and productivity is thereby impaired. This mechanism was the first type of formation damage to be recognized, and is commonly called water block.

Capillary Phenomena

Figure 10-3. Mercury capillary-pressure curve applying to pore casts in Figure 10-4. (From Swanson* Copyright 1979bySPE-AIME.)

C. 52% saturation

D. 73% saturation

Figure 10-4. Woods metal pore cast of Berea sandstone, (From Swanson.t Copyright 1979 by SPE-AIME.)

22% saturation

36% saturation

22% saturation

36% saturation

C. 52% saturation

D. 73% saturation

Figure 10-4. Woods metal pore cast of Berea sandstone, (From Swanson.t Copyright 1979 by SPE-AIME.)

To help visualize the tortuous paths followed by a fluid flowing through a rock, Swanson6 forced molten Woods metal—which, like mercury, does not wet rock surfaces—into rock specimens. He then dissolved the matrix of the rock with acid, leaving a pore cast of Woods metal. Figures 10-4 and 10-5 show scanning electron micrographs of the casts of high and low permeability sandstones. Note that many of the large pores are connected by smalt capillaries.

preferential wettability. In the case of water and oil (or gas) flowing through rocks that are preferentially water-wet, the water flows along the surface of the grains and through the minor capillaries, whereas the oil flows through the center of the pores and the larger flow channels. The relative permeability to each fluid (i.e., the permeability to the fluid expressed as a ratio of the permeability when only a single fluid—usually air—is present) depends on the wettability of the rock and on the percent saturation of each fluid. Figure 10 6 shows typical oil and water relative permeabilities plotted against percent water saturation. As would be expected, the relative permeability to oil at a given saturation is greater than the relative permeability to water at the equivalent water saturation. The residual water saturation (shown in Figure 10-6) is the minimum water saturation when only oil is flowing at given pressure drop, and the residual oil saturation is the corresponding value for oil.

A virgin oil reservoir is at residual water saturation for the prevailing reservoir pressure. Invasion by mud filtrate drives the oil towards residual oil saturation, and when the well is brought onto production, the oil drives the filtrate back towards residual water saturation. However, as shown in Figure 10-6, the relative permeability to water becomes very low as residual water is approached. It may therefore take a considerable length of time before all the filtrate is expelled, and full production is obtained, particularly if the oil/water viscosity ratio is low.8 In most virgin reservoirs, pressures are high enough to expel all the filtrate eventually, so impairment caused by relative permeability effects is temporary. However, in low pressure and low permeability reservoirs and in workover wells, capillary pressures become significant. As shown by Equation 7-1, capillary pressures are inversely proportional to radius, and t he finer capillaries of rocks are so small that capillary pressures may run into hundreds of pounds per square inch. Capillary pressure promotes the displacement of oil by an aqueous filtrate but opposes the displacement of the filtrate by the returning oil. The pressure drop may not be high enough to drive filtrate oui of the liner capillaries, especially in the immediate vicinity of the borehole wall, where the pressure drop at the oil-water interface approaches zero. This mechanism, which we will refer to as water block, causes permanent impairment—and even complete shut-off—in highly depleted reservoirs. Waterblock in gas reservoirs was formerly called the Jamin effect.0

Waterblock may be avoided by the use of oil muds, provided no water is in their filtrates under bottom hole conditions. Oil muds have two limitations. First, they should not be used in drilling dry gas sands, because not all the oil will be produced back, and will thus leave a second residual phase. Second, cat ionic surfactants used in their manufacture decrease the degree of water-welness" of the grain surfaces, and, if the mud is poorly formulated, may even convert the surfaces to the oil-wet condition.10 In an oil-wet rock, the shape of the relative permeability curves shown in Figure 10 -6 are interchanged, so that the relative permeability to oil at low water saturations is greatly decreased

Water Oil

Saturation Saturation

Water Oil

Saturation Saturation

Water Saturation %

Figure 10-6. Relative permeabilities to oil and water in a preferentially water-wet reservoir.

In situ emulsification of interstitial oil is another possible cause of capillary impairment that may occur if the filtrate of an oil-in-water emulsion mud contains appreciable quantities of emulsifier. Emulsification is possible because, although the bulk flow rate of the filtrate is low, the rate of shear at constrictions in the flow channels is high. If a stabilized emulsion is formed, the droplets become trapped in the pores and reduce the effective permeability. However, emulsifier will only be present in the filtrate if excess is present in the emulsion mud. Therefore in situ emulsification can be avoided if care is taken in formulating and maintaining the emulsion muds.

Permeability Impairment by Indigenous Clays

Nearly all sands and sandstones contain clays which profoundly influence the permeability of the rock. These clays derive from two possible sources.

Detrital clays are clays which have sedimented with the sand grains at the time the bed was deposited. Diagentetic clays are clays which have subsequently been precipitated from formation waters or which were formed by the interaction of formation waters and pre-existing clay minerals.'1 The clays may be present as part of the matrix, as coating on the pore walls, or lying loose in the pores. Diagenetic clays usually occur as a deposit of clay platelets on the pore walls oriented normally to the grain surfaces (see Figure 10 7a). Clays may also be present as thin layers, or partings, in the sand beds Carbonate formations are seldom clay-bearing, and, when clays are present, they are incorporated in the matrix.

The action of aqueous filtrates on indigenous clays can severely reduce the permeability of the rock, but only if the clays are located in the pores. Nowak and Krueger1 found that the permeability of a dry core, which contained montmorillonite, was 60 md to air, but only 20 md to the interstitial water from the same formation. With other brines, the permeability decreased with decrease in the salinity of the brine; with distilled water, it was only 0.002 md Experimental evidence suggested that the reduction in permeability was caused by the swelling and dispersion of the montmorillonite, and the subsequent blocking of the pores was caused by the migrating particlcs. Formations whose permeability is reduced by aqueous fluids are called wafer-sen.si five formations.

Other investigators10,1 14 have shown that permeability reduction is greatest when montmorillonite and mixed-layer clays are present. Reduction is less with illite, and least with kaolinite and chlorite. On the basis of petro-graphic examination, Basan14a has classified reservoirs in order of potential impairment according to the nature and location of the clays in the rock pores. Permeability impairment may also be caused by loose fines of minerals such as mica15 and quartz.10 Muecke17 reported that fines of unconsolidated Gulf Coast sands consisted of 39% quartz, 32% amorphous materials, and 12% clay. The fines were located on the surface of the larger grains, as shown in Figure 10-7b,

Mechanism of Impairment by Indigenous Clays

The mechanism whereby aqueous fluids impair water-sensitive rocks has been studied by a number of investigators whose work is discussed below. In order to simplify interpretation of the results, experiments were made on single phase systems. Usually, concentrated sodium chloride brine was first flowed through the core or sandpack, followed either by floods of successively-lower salinity or by distilled water. The study by Bardon and Jacquin14 is particularly illuminating because it separates the reduction in permeability caused by crystalline swelling from that caused by dispersion, and from that caused by deflocculation, and defines the salinity range in which each of these

0 0

Post a comment