Additional causes of formation damage

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.

Emulsions and sludges

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.The mixing of two immiscible fluids at a high shear rate in the formation can sometimes result in the formation of a homogeneous mixture of one phase dispersed into another. Such emulsions usually have a higher viscosity than either of the constituent fluids and can result in significant decreases in the ability of the hydrocarbon phase to flow.

Crude-oil/brine emulsions are stabilized by the presence of surfactants and colloidal particles such as clays, paraffins, and asphaltenes. In general, organophilic particles such as paraffins and asphaltenes favor the formation of oil-external emulsions and sludges. Water-wet solids such as clays favor the formation of water-external emulsions. It is important to minimize the loss of surface-active materials into the near-wellbore region to ensure that emulsions do not form. For example, large volumes of surfactants are used as corrosion inhibitors and dispersants in acid treatments. A significant cause of failure of acid treatments is the formation of sludges and emulsions during an acid treatment as a result of the presence of these surfactants. The compatibility of crude oil with the acid package needs to be evaluated before it is pumped into the well. It has also been observed that the presence of iron enhances the formation of these sludges. It is therefore recommended that iron be removed from the tubing by circulating a slug of acid to the surface to ensure that the iron-rich acid is not squeezed into the formation during an acid treatment.

In general, it is difficult to remove emulsions and sludges once they are formed. Thus, it is imperative to prevent the formation of such emulsions. Use of mutual solvents such as alcohols and surfactants (demulsifiers) is the most common way to remove these deposits from the near-wellbore region. However, because of the unfavorable mobility ratio of the injected fluid, placing the treatment fluids in the plugged zones can be difficult. Again, laboratory tests with the crudes should be conducted to ensure compatibility.

Wettability alteration

Converting a rock from water-wet to oil-wet results in a substantial reduction in the relative permeability to the hydrocarbon phase and an increase in relative permeability to the water (Fig. 1). Wettability alteration to less water-wet conditions is therefore clearly undesirable.

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  Fig. 1—Reduction in well productivity caused by condensate buildup, Arun field, Indonesia.

The loss of surfactants in drilling and completion fluids, corrosion inhibitors and dispersants in stimulation fluids, and the use of resins for sand control can cause changes in wettability in the near-wellbore region. Care must be exercised when oil-wetting surfactants are used in the wellbore to ensure that these fluids are not lost to the productive zone. Alteration of wettability in a region around the wellbore can result in an additional pressure drop because of the reduction in oil permeability. This additional pressure drop or skin is hard to distinguish from mechanical skin caused by physical plugging of pore throats. In effect, wettability alteration has the same net result as changing the effective permeability to the hydrocarbon phase in a region around the wellbore.

The use of solvents and water-wetting surfactants may be recommended in cases in which large volumes of oil-wetting surfactants such as oil-based muds have been lost to the formation.

Bacterial plugging

anaerobic bacteria are ubiquitously present in and around oil and gas wells. Under most producing conditions, their growth is not stimulated because of the high temperature and pressure conditions. However, in some instances, injection of water-based fluids can induce the growth of microbial populations and can result in significant declines in productivity or injectivity. The growth of sulfur-reducing bacteria can also result in the generation of hydrogen sulfide gas and the fouling of flowlines and facilities.

The use of a bactericide (such as sodium hypochlorite or mixtures of other strong oxidizing agents and antibacterial agents) is sometimes an effective, albeit expensive, method of reducing this problem.

Gas breakout

In solution gas drive reservoirs, as the reservoir fluid pressure drops below the bubblepoint, a gas phase is formed. If this event occurs in the wellbore, the gas bubbles formed help to lift the liquid hydrocarbons to the surface. However, if the bubblepoint is reached in the near-wellbore region, a significant gas saturation builds up around the wellbore resulting in a decrease in the oil relative permeability. As might be expected, this form of damage is more likely to occur later in the life of the reservoir as the average reservoir pressure is depleted below the bubblepoint.

This type of damage can be diagnosed, if the production engineer has a good understanding of and access to phase behavior data. In many cases, lack of access to these data can result in an incorrect diagnosis of the reduction in well productivity. Such a misdiagnosis can lead to inaccurate recommendations for stimulation treatments.

In typical relative permeability curves, the change in the relative permeability to oil can be rather drastic as the gas saturation increases. This decrease in oil permeability can have a dramatic effect on well productivity. Oil flow rates can decrease while gas flow rates may increase rapidly over a relatively short duration.

The most common method to address gas breakout problems is to hydraulically fracture the well in an attempt to reduce the drawdown needed to produce at a given rate. Repressurizing the reservoir is also an excellent alternative. The economics of reservoir repressurization need to be carefully evaluated in such applications. It should be noted that, in cases in which the average reservoir pressure drops below the bubblepoint throughout most of the reservoir, a gas cap may begin forming in the reservoir. This can, over a long time period, result in increased gas production into the wellbore from the gas cap.

Water blocks

If large volumes of water based drilling or completion fluids are lost to a well, a region of high water saturation around the wellbore forms. In this region, the relative permeability to the hydrocarbon phases is decreased, resulting in a net loss in well productivity.

Regions of high water saturation, or water blocks around the wellbore, are expected to dissipate with time as the hydrocarbon fluids are produced. In general, when the viscous forces are significantly larger than the capillary forces, the water block will clear up rather rapidly. If, however, the capillary forces holding the water in place are larger than the viscous forces, for example, in tight gas reservoirs, water blocks may persist for a very long period of time. A capillary number, defined as the ratio of capillary to viscous forces, can be used to quantify this effect. When capillary forces are larger than or combrble to viscous forces, water blocks are hard to remove. On the other hand, when viscous forces dominate, water blocks will clear up in a matter of a few hours or days. Water blocks will generally be more troublesome for low-permeability, depleted gas wells in which the capillary number is significantly less than 1.

There are three primary methods used to remove water blocks:

• Surging or swabbing the wells to increase the capillary number temporarily
• Reducing surface tension through the addition of surfactants or solvents, which also has the net effect of increasing the capillary number by reducing the interfacial tension between the hydrocarbon and water phases so that the water block may be cleaned up during flowback
• Use of solvents or mutual solvents, such as alcohols, to solubilize the water and remove it through a change in phase behavior.

All of these three methods have been successfully applied in the field. The benefit of one method over another depends on the specific conditions of reservoir permeability, temperature, and pressure.

Noteworthy papers in OnePetro

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See also

Formation damage

Drilling induced formation damage

Formation damage from completion workover fluids

Formation damage from perforating and cementing

Formation damage from fines migration

Formation damage from swelling clays

Formation damage from paraffins and asphaltenes

Formation damage from condensate banking

Formation damage in injection wells

PEH:Formation_Damage