Formation damage

Producing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable. In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations. It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock.

Typically, any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin.

Preventing formation damage

Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons:

1.     Ability to recover fluids from the reservoir is affected very strongly by the hydrocarbon permeability in the near-wellbore region

2.     Although we do not have the ability to control reservoir rock properties and fluid properties, we have some degree of control over drilling, completion, and production operations

Thus, we can make operational changes, minimize the extent of formation damage induced in and around the wellbore, and have a substantial impact on hydrocarbon production. Being aware of the formation damage implications of various drilling, completion, and production operations can help in substantially reducing formation damage and enhancing the ability of the well to produce fluids.

Formation skin damage

Fig. 1 illustrates formation skin damage.

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Fig. 1—Formation skin damage.

More information can be found in Determination of flow efficiency and skin.

Damage mechanisms

Formation damage is a combination of several mechanisms including:

·         Solids plugging. Fig. 2 shows that the plugging of the reservoir-rock pore spaces can be caused by the fine solids in the mud filtrate or solids dislodged by the filtrate within the rock matrix. To minimize this form of damage, minimize the amount of fine solids in the mud system and fluid loss. See Drilling induced formation damage

 

Fig. 2—Formation damage caused by solids plugging.

·        Clay-particle swelling or dispersion. This is an inherent problem in sandstone that contains water-sensitive clays. When a fresh-water filtrate invades the reservoir rock, it will cause the clay to swell and thus reduce or totally block the throat areas. See Formation damage from swelling clays.

·        Saturation changes. Production is predicated on the amount of saturation within the reservoir rock. When a mud-system filtrate enters the reservoir, it will cause some change in water saturation and, therefore, potential reduction in production. Fig. 3[1] shows that high fluid loss causes water saturation to increase, which results in a decrease of rock relative permeability.

 

Fig. 3—Formation damage caused by saturation.

·         Wettability reversal. Reservoir rocks are water-wet in nature. It has been demonstrated that while drilling with oil-based mud systems, excess surfactants in the mud filtrate that enter the rock can cause wettability reversal. It has been reported from field experience and demonstrated in laboratory tests that as much as 90% in production loss can be caused by this mechanism. Therefore, to guard against this problem, the amount of excess surfactants used in oil-based mud systems should be kept at a minimum. See Additional causes of formation damage

·         Emulsion blockage. Inherent in an oil-based system is the use of excess surfactants. These surfactants enter the rock and can form an emulsion within the pore spaces, which hinders production through emulsion blockage. See Additional causes of formation damage

·         Aqueous-filtrate blockage. While drilling with water-based mud, the aqueous filtrate that enters the reservoir can cause some blockage that will reduce the production potential of the reservoir. See Additional causes of formation damage

·         Mutual precipitation of soluble salts in wellbore-fluid filtrate and formation water. Any precipitation of soluble salts, whether from the use of salt mud systems or from formation water or both, can cause solids blockage and hinder production.

·         Fines migration. Buildup of fine particles, particularly in sandstone reservoirs, can significantly reduce well productivity. See Formation damage from fines migration

·         Deposition of paraffins or asphaltenes. Paraffins and asphaltenes can deposit both in tubing and in the pores of the reservoir rock, significantly limiting well productivity. See Formation damage from paraffins and asphaltenes

·         Condensate banking. A buildup of condensate around the wellbore can impede gas flow by reducing permeability. See Formation damage from condensate banking

·         Other causes. These can include bacterial plugging and gas breakout. See Additional causes of formation damage

Quantifying formation damage

A commonly used measure of well productivity is the productivity index, J, in barrels per pounds per square inch:

....................(1)

The most commonly used measure of formation damage in a well is the skin factor, S. The skin factor is a dimensionless pressure drop caused by a flow restriction in the near-wellbore region. It is defined as follows (in field units):

....................(2)

Fig. 4 shows how flow restrictions in the near-wellbore region can increase the pressure gradient, resulting in an additional pressure drop caused by formation damage (Δpskin).

Fig. 4—Pressure profile in the near-wellbore region for a well with formation damage.[2]

In 1970, Standing[2] introduced the important concept of well flow efficiency, F, which he defined as

....................(3)

Clearly, a flow efficiency of 1 indicates an undamaged well with Δpskin = 0, a flow efficiency > 1 indicates a stimulated well (perhaps because of a hydraulic fracture), and a flow efficiency < 1 indicates a damaged well. Note that, to determine flow efficiency, we must know the average reservoir pressure,, and skin factor, S. Methods to measure these quantities are discussed in Determination of flow efficiency and skin.

The impact of skin on well productivity can be estimated by the use of inflow performance relationships (IPRs) for the well such as those proposed by Vogel,  Fetkovich,  and Standing. [2] These IPRs can be summarized as follows:

 

When x = 0, a linear IPR model is recovered; when x = 0.8, we obtain Vogel's IPR; and when x = 1, Fetkovich's IPR model is obtained. An example of a plot for the dimensionless hydrocarbon production as a function of the dimensionless bottomhole pressure (IPR) is shown in Fig. 5 for different flow efficiencies. It is evident that, as flow efficiency decreases, smaller and smaller hydrocarbon rates are obtained for the same drawdown .

Fig. 5—Inflow performance relations for different flow efficiencies(F).

The choice of the IPR used depends on the fluid properties and reservoir drive mechanism. Standing's IPR is most appropriate for solution-gas-drive reservoirs, whereas a linear IPR is more appropriate for waterdrive reservoirs producing at pressures above the bubblepoint and for hydrocarbons without substantial dissolved gas. A more detailed discussion of this is provided in Peters .

Formation damage vs. pseudodamage

It is important to clearly distinguish formation damage from well completion and reservoir effects that are a consequence of how the wellbore penetrates the reservoir and where the perforations are placed (sometimes referred to as pseudoskin effects)  and permeability loss as a result of depletion. [10] Reservoir engineering models for limited-entry flow in partially penetrating wells are presented in several reservoir engineering texts such as Dake. 

The second major cause of pseudoskin is high-velocity flows near the wellbore, which induces turbulence or inertial effects. As discussed in the previous section, turbulence or inertial effects can lead to an additional turbulent pressure drop that needs to be clearly distinguished from the pressure drop induced by a reduction in permeability.

Finally, flow restrictions in the wellbore itself such as chokes, scale buildup, wax, or asphaltene deposits can often result in tubing pressure drops that are substantially larger than anticipated. This reduction in well productivity is not commonly referred to as formation damage. Other types of production impairment caused within the tubing are collapsed tubing or flow restrictions caused by mechanical restrictions such as:

·         Corrosion products

·         Poor cement jobs, resulting in commingling of produced fluids from different zones

·         Insufficient tubing diameter or improper design of artificial lift systems

This partial list provides some examples of flow restrictions caused primarily in the tubing and should not typically be categorized as formation damage. They do not show up in measures of formation damage such as skin, which are primarily measures of flow restrictions in the near-wellbore region.

Flow restrictions in the completion itself such as the compacted zone around perforation tunnels and plugged gravel packs are included in Determination of flow efficiency and skin because they typically are measured as a well skin.